Stratigraphic framework of Cambrian and Ordovician rocks in the central Appalachian Basin from Medina County, Ohio, through southwestern and south-central Pennsylvania to Hampshire County, West Virginia

USGS Publications Warehouse

Ryder, Robert T.; Harris, Anita G.; Repetski, John E.; revised and digitized by Crangle, Robert D.

2003-01-01

A 275-mi-long restored stratigraphic cross section from Medina County, Ohio, through southwestern and south-central Pennsylvania to Hampshire County, W. Va., provides new details on Cambrian and Ordovician stratigraphy in the central Appalachian basin and the structure of underlying Precambrian basement rocks. From west to east, the major structural elements of the block-faulted basement in this section are (1) the relatively stable, slightly extended craton, which includes the Wooster arch, (2) the fault-controlled Ohio-West Virginia hinge zone, which separates the craton from the adjoining Rome trough, (3) the Rome trough, which consists of an east-facing asymmetric graben and an overlying sag basin, and (4) a positive fault block, named here the South-central Pennsylvania arch, which borders the eastern margin of the graben part of the Rome trough. Pre-Middle Ordovician structural relief on Precambrian basement rocks across the down-to-the-west normal fault that separates the Rome trough and the adjoining South-central Pennsylvania arch amounted to between 6,000 and 7,000 ft. The restored cross section shows eastward thickening of the Cambrian and Ordovician sequence from about 3,000 ft near the crest of the Wooster arch at the western end of the section to about 5,150 ft at the Ohio-West Virginia hinge zone adjoining the western margin of the Rome trough to about 19,800 ft near the depositional axis of the Rome trough. East of the Rome trough, at the adjoining western edge of the South-central Pennsylvania arch, the Cambrian and Ordovician sequence thins abruptly to about 13,500 ft and then thins gradually eastward across the arch to about 12,700 ft near the Allegheny structural front and to about 10,150 ft at the eastern end of the restored section. In general, the Cambrian and Ordovician sequence along this section consists of four major lithofacies that are predominantly shallow marine to peritidal in origin. In ascending stratigraphic order, the lithofacies are identified by the following descriptive names: (1) sandstone, shale, limestone, and dolomite unit, (2) dolomite and sandstone unit, (3) limestone and black shale unit, and (4) shale and sandstone unit. Each of these units and their associated subunits thicken from west to east across the restored section to a maximum near the depositional axis of the Rome trough and then thin eastward to the end of the section. The sandstone, shale, limestone, and dolomite unit is largely confined to the asymmetric graben that marks the initial phase of the Rome trough. This unit is Early and Middle Cambrian in age and consists, in ascending order, of a basal sandstone unit (undrilled but probably present), the Tomstown Dolomite (undrilled but probably present), the Waynesboro Formation, and the Pleasant Hill Limestone and its equivalent lower one-third of the Elbrook Formation at the eastern end of the section. The dolomite and sandstone unit forms the core of the Cambrian and Ordovician sequence. In the Rome trough and on the adjoining South-central Pennsylvania arch, this unit consists, in ascending order, of the Middle and Upper Cambrian Warrior Formation and the equivalent upper two-thirds of the Elbrook Formation at the eastern end of the section, the Upper Cambrian Gatesburg Formation, and the Lower Ordovician and Middle Ordovician (Whiterockian and Chazyan) Beekmantown Group. West of the Ohio-West Virginia hinge zone, the dolomite and sandstone unit consists, in ascending order, of the Conasauga Formation of Janssens (1973), the Krysik sandstone of driller's usage, the B zone of Calvert (1964), the Knox Dolomite and the associated Rose Run Sandstone Member, and the Wells Creek Formation. The widespread Knox unconformity is located at the base of the Wells Creek Formation and at or near the top of the adjoining Beekmantown Group, except near the depositional axis of the Rome trough, where the unconformity seems to be absent. The limestone and black shale unit i

Tidal-bundle sequences in the Jordan Sandstone (Upper Cambrian), southeastern Minnesota, U.S.A.: Evidence for tides along inboard shorelines of the Sauk Epicontinental Sea

USGS Publications Warehouse

Tape, C.H.; Cowan, Clinton A.; Runkel, Anthony C.

2003-01-01

This study documents for the first time tidal bundling in a lower Paleozoic sheet sandstone from the cratonic interior of North America, providing insights into the hydrodynamics of ancient epicontinental seas. The Jordan Sandstone (Upper Cambrian) in the Upper Mississippi Valley contains large-scale planar tabular cross-sets with tidal-bundle sequences, which were analyzed in detail at an exceptional exposure. Tidal-bundle sequences (neap-spring-neap cycles) were delineated by foreset thickening-thinning patterns and composite shale drapes, the latter of which represent accumulations of mud during the neap tides of neap-spring-neap tidal cycles. Fourier analysis of the bundle thickness data from the 26 measurable bundle sequences revealed cycles ranging from 15 to 34 bundles per sequence, which suggests a semidiurnal or mixed tidal system along this part of the Late Cambrian shoreline. We extend the tidal interpretation to widespread occurrences of the same facies in outcrops of lesser quality, where the facies is recognizable but too few bundles are exposed for tidal cycles to be measured. By doing so, this study shows that tidally generated deposits have a significant geographic and temporal extent in Upper Cambrian strata of central mid-continent North America. The deposition and preservation of tidal facies was related to the intermittent development of shoreline embayments during transgressions. The tidally dominated deposits filled ravined topographies that were repeatedly developed on the updip parts of the shoreface. Resulting coastal geomorphologies, accompanied perhaps by larger-scale changes in basinal conditions and/or configuration, led to changes in depositional conditions from wave-dominated to tide-dominated. Outcrops of the Jordan Sandstone tidal facies in the Upper Mississippi Valley represent the farthest inboard recorded transmission of ocean-generated tides in the Laurentian epicontinental seas, demonstrating that tidal currents were significant agents in the transport of sand along the far cratonic interior shorelines of Cambrian North America. The results of this study improve the facies-level understanding of the genesis of sheet sandstones. Furthermore, tidalites documented here occur in a specific position within a sequence stratigraphic architecture for the Jordan Sandstone. This provides a framework to compare these ancient deposits and processes to younger (e.g., Carboniferous) epicontinental systems where stratal and sediment dynamics are better documented. ?? 2003, SEPM (Society for Sedimentary Geology).

The Chuar Petroleum System, Arizona and Utah

USGS Publications Warehouse

Lillis, Paul G.

2016-01-01

The Neoproterozoic Chuar Group consists of marine mudstone, sandstone and dolomitic strata divided into the Galeros and Kwagunt Formations, and is exposed only in the eastern Grand Canyon, Arizona. Research by the U.S. Geological Survey (USGS) in the late 1980s identified strata within the group to be possible petroleum source rocks, and in particular the Walcott Member of the Kwagunt Formation. Industry interest in a Chuar oil play led to several exploratory wells drilled in the 1990s in southern Utah and northern Arizona to test the overlying Cambrian Tapeats Sandstone reservoir, and confirm the existence of the Chuar in subcrop. USGS geochemical analyses of Tapeats oil shows in two wells have been tentatively correlated to Chuar bitumen extracts. Distribution of the Chuar in the subsurface is poorly constrained with only five well penetrations, but recently published gravity/aeromagnetic interpretations provide further insight into the Chuar subcrop distribution. The Chuar petroleum system was reexamined as part of the USGS Paradox Basin resource assessment in 2011. A map was constructed to delineate the Chuar petroleum system that encompasses the projected Chuar source rock distribution and all oil shows in the Tapeats Sandstone, assuming that the Chuar is the most likely source for such oil shows. Two hypothetical plays were recognized but not assessed: (1) a conventional play with a Chuar source and Tapeats reservoir, and (2) an unconventional play with a Chuar source and reservoir. The conventional play has been discouraging because most surface structures have been tested by drilling with minimal petroleum shows, and there is some evidence that petroleum may have been flushed by CO2 from Tertiary volcanism. The unconventional play is untested and remains promising even though the subcrop distribution of source facies within the Chuar Group is largely unknown.

Fe-oxide grain coatings support bacterial Fe-reducing metabolisms in 1.7−2.0 km-deep subsurface quartz arenite sandstone reservoirs of the Illinois Basin (USA)

PubMed Central

Dong, Yiran; Sanford, Robert A.; Locke, Randall A.; Cann, Isaac K.; Mackie, Roderick I.; Fouke, Bruce W.

2014-01-01

The Cambrian-age Mt. Simon Sandstone, deeply buried within the Illinois Basin of the midcontinent of North America, contains quartz sand grains ubiquitously encrusted with iron-oxide cements and dissolved ferrous iron in pore-water. Although microbial iron reduction has previously been documented in the deep terrestrial subsurface, the potential for diagenetic mineral cementation to drive microbial activity has not been well studied. In this study, two subsurface formation water samples were collected at 1.72 and 2.02 km, respectively, from the Mt. Simon Sandstone in Decatur, Illinois. Low-diversity microbial communities were detected from both horizons and were dominated by Halanaerobiales of Phylum Firmicutes. Iron-reducing enrichment cultures fed with ferric citrate were successfully established using the formation water. Phylogenetic classification identified the enriched species to be related to Vulcanibacillus from the 1.72 km depth sample, while Orenia dominated the communities at 2.02 km of burial depth. Species-specific quantitative analyses of the enriched organisms in the microbial communities suggest that they are indigenous to the Mt. Simon Sandstone. Optimal iron reduction by the 1.72 km enrichment culture occurred at a temperature of 40°C (range 20–60°C) and a salinity of 25 parts per thousand (range 25–75 ppt). This culture also mediated fermentation and nitrate reduction. In contrast, the 2.02 km enrichment culture exclusively utilized hydrogen and pyruvate as the electron donors for iron reduction, tolerated a wider range of salinities (25–200 ppt), and exhibited only minimal nitrate- and sulfate-reduction. In addition, the 2.02 km depth community actively reduces the more crystalline ferric iron minerals goethite and hematite. The results suggest evolutionary adaptation of the autochthonous microbial communities to the Mt. Simon Sandstone and carries potentially important implications for future utilization of this reservoir for CO2 injection. PMID:25324834

Understanding CO2 Plume Behavior and Basin-Scale Pressure Changes during Sequestration Projects through the use of Reservoir Fluid Modeling

USGS Publications Warehouse

Leetaru, H.E.; Frailey, S.M.; Damico, J.; Mehnert, E.; Birkholzer, J.; Zhou, Q.; Jordan, P.D.

2009-01-01

Large scale geologic sequestration tests are in the planning stages around the world. The liability and safety issues of the migration of CO2 away from the primary injection site and/or reservoir are of significant concerns for these sequestration tests. Reservoir models for simulating single or multi-phase fluid flow are used to understand the migration of CO2 in the subsurface. These models can also help evaluate concerns related to brine migration and basin-scale pressure increases that occur due to the injection of additional fluid volumes into the subsurface. The current paper presents different modeling examples addressing these issues, ranging from simple geometric models to more complex reservoir fluid models with single-site and basin-scale applications. Simple geometric models assuming a homogeneous geologic reservoir and piston-like displacement have been used for understanding pressure changes and fluid migration around each CO2 storage site. These geometric models are useful only as broad approximations because they do not account for the variation in porosity, permeability, asymmetry of the reservoir, and dip of the beds. In addition, these simple models are not capable of predicting the interference between different injection sites within the same reservoir. A more realistic model of CO2 plume behavior can be produced using reservoir fluid models. Reservoir simulation of natural gas storage reservoirs in the Illinois Basin Cambrian-age Mt. Simon Sandstone suggest that reservoir heterogeneity will be an important factor for evaluating storage capacity. The Mt. Simon Sandstone is a thick sandstone that underlies many significant coal fired power plants (emitting at least 1 million tonnes per year) in the midwestern United States including the states of Illinois, Indiana, Kentucky, Michigan, and Ohio. The initial commercial sequestration sites are expected to inject 1 to 2 million tonnes of CO2 per year. Depending on the geologic structure and permeability anisotropy, the CO2 injected into the Mt. Simon are expected to migrate less than 3 km. After 30 years of continuous injection followed by 100 years of shut-in, the plume from a 1 million tonnes a year injection rate is expected to migrate 1.6 km for a 0 degree dip reservoir and over 3 km for a 5 degree dip reservoir. The region where reservoir pressure increases in response to CO2 injection is typically much larger than the CO2 plume. It can thus be anticipated that there will be basin wide interactions between different CO2 injection sources if multiple, large volume sites are developed. This interaction will result in asymmetric plume migration that may be contrary to reservoir dip. A basin- scale simulation model is being developed to predict CO2 plume migration, brine displacement, and pressure buildup for a possible future sequestration scenario featuring multiple CO2 storage sites within the Illinois Basin Mt. Simon Sandstone. Interactions between different sites will be evaluated with respect to impacts on pressure and CO2 plume migration patterns. ?? 2009 Elsevier Ltd. All rights reserved.

Mineral resource potential map of the Gee Creek Wilderness, Polk and Monroe counties, Tennessee

USGS Publications Warehouse

Epstein, Jack B.; Gazdik, Gertrude C.; Behum, Paul T.

1983-01-01

The major rock types in the wilderness area consist of sandstone, shale, and conglomerate of the Chilhowee Group of Cambrian and Cambrian(?) age. Faulting appears to have controlled the location of minor subeconomic iron deposits, but no potential mineral resources were detected by the present survey. Shales, useful for brick or lightweight aggregate, and sandstone, useful for crushed stone or sand, have little economic interest because these rock types are common throughout the region and are found closer to potential markets. The possibility of natural gas occurring in untested rocks structurally beneath the Chilhowee strata cannot be discounted. No potential was found for any other mineral resource.

Uranophane at Silver Cliff mine, Lusk, Wyoming

USGS Publications Warehouse

Wilmarth, Verl R.; Johnson, D.H.

1954-01-01

The uranium deposit at the Silver Cliff mine near Lusk, Wyo., consists primarily of uranophane which occurs as fracture fillings and small replacement pockets in faulted and fractured calcareous sandstone of Cambrian (?) age. The country rock in the vicinity of the mine is schist of pre-Cambrian age intruded by pegmatite dikes and is unconformably overlain by almost horizontal sandstone of Cambrian(?) age. The mine is on the southern end of the Lusk Dome, a local structure probably related to the Hartville uplift. In the immediate vicinity of the mine, the dome is cut by the Silver Cliff fault, a north-trending high-angle reverse fault about 1,200 feet in length with a stratigraphic throw of 70 feet. Uranophane, metatorbernite, pitchblende, calcite, native silver, native copper, chalcocite, azurite, malachite, chrysocolla, and cuprite have been deposited in fractured sandstone. The fault was probably mineralized throughout its length, but because of erosion, the mineralized zone is discontinuous. The principal ore body is about 800 feet long. The width and depth of the mineralized zone are not accurately known but are at least 20 feet and 60 feet respectively. The uranium content of material sampled in the mine ranges from 0.001 to 0.23 percent uranium, whereas dump samples range from 0.076 to 3.39 percent uranium.

Genesis analysis of high-gamma ray sandstone reservoir and its log evaluation techniques: a case study from the Junggar basin, northwest China.

PubMed

Wang, Liang; Mao, Zhiqiang; Sun, Zhongchun; Luo, Xingping; Song, Yong; Liu, Zhen

2013-01-01

In the Junggar basin, northwest China, many high gamma-ray (GR) sandstone reservoirs are found and routinely interpreted as mudstone non-reservoirs, with negative implications for the exploration and exploitation of oil and gas. Then, the high GR sandstone reservoirs' recognition principles, genesis, and log evaluation techniques are systematically studied. Studies show that the sandstone reservoirs with apparent shale content greater than 50% and GR value higher than 110API can be regarded as high GR sandstone reservoir. The high GR sandstone reservoir is mainly and directly caused by abnormally high uranium enrichment, but not the tuff, feldspar or clay mineral. Affected by formation's high water sensitivity and poor borehole quality, the conventional logs can not recognize reservoir and evaluate the physical property of reservoirs. Then, the nuclear magnetic resonance (NMR) logs is proposed and proved to be useful in reservoir recognition and physical property evaluation.

Genesis Analysis of High-Gamma Ray Sandstone Reservoir and Its Log Evaluation Techniques: A Case Study from the Junggar Basin, Northwest China

PubMed Central

Wang, Liang; Mao, Zhiqiang; Sun, Zhongchun; Luo, Xingping; Song, Yong; Liu, Zhen

2013-01-01

In the Junggar basin, northwest China, many high gamma-ray (GR) sandstone reservoirs are found and routinely interpreted as mudstone non-reservoirs, with negative implications for the exploration and exploitation of oil and gas. Then, the high GR sandstone reservoirs' recognition principles, genesis, and log evaluation techniques are systematically studied. Studies show that the sandstone reservoirs with apparent shale content greater than 50% and GR value higher than 110API can be regarded as high GR sandstone reservoir. The high GR sandstone reservoir is mainly and directly caused by abnormally high uranium enrichment, but not the tuff, feldspar or clay mineral. Affected by formation's high water sensitivity and poor borehole quality, the conventional logs can not recognize reservoir and evaluate the physical property of reservoirs. Then, the nuclear magnetic resonance (NMR) logs is proposed and proved to be useful in reservoir recognition and physical property evaluation. PMID:24078797

Evolution of oceanic molybdenum and uranium reservoir size around the Ediacaran-Cambrian transition: Evidence from western Zhejiang, South China

NASA Astrophysics Data System (ADS)

Xiang, Lei; Schoepfer, Shane D.; Shen, Shu-zhong; Cao, Chang-qun; Zhang, Hua

2017-04-01

The "Cambrian explosion" is one of the most fascinating episodes of diversification in the history of life; however, its relationship to the oxygenation of the oceans and atmosphere around the Ediacaran-Cambrian transition is not fully understood. Marine inventories of redox-sensitive trace elements reflect the relative balance of oxidative weathering on land and deposition in anoxic water masses, and can be used to explore the evolution of oceanic and atmospheric redox conditions. For this study, we conducted a series of geochemical analyses on the upper Lantian, Piyuancun, and Hetang formations in the Chunye-1 well, part of the lower Yangtze Block in western Zhejiang. Iron speciation results indicate that the entire studied interval was deposited under anoxic conditions, with three intervals of persistent euxinia occurring in the uppermost Lantian Fm., the lower Hetang Formation (Fm.), and the upper Hetang Fm. Molybdenum (Mo) and uranium (U) contents and Mo/TOC and U/TOC ratios from the anoxic/euxinic intervals of the Chunye-1 well, combined with published data from the sections in the middle and upper Yangtze Block, suggest that the oceanic Mo reservoir declined consistently from the Ediacaran to Cambrian Stage 3, while the size of the oceanic U reservoir remained relatively constant. Both metals were depleted in the ocean in lower Cambrian Stage 4, before increasing markedly at the end of Stage 4. The lack of an apparent increase in the size of the marine Mo and U reservoir from the upper Ediacaran to Cambrian Stage 3 suggests that oxic water masses did not expand until Cambrian Stage 4. The increase in marine Mo and U availability in the upper Hetang Fm. may have been due to the expansion of oxic water masses in the oceans, associated with oxygenation of the atmosphere during Cambrian Stage 4. This expansion of oxic waters in the global ocean postdates the main phase of Cambrian diversification, suggesting that pervasive oxygenation of the ocean on a large scale was not the primary control on animal diversity following the Ediacaran-Cambrian transition.

Geology of Paleozoic Rocks in the Upper Colorado River Basin in Arizona, Colorado, New Mexico, Utah, and Wyoming, Excluding the San Juan Basin

USGS Publications Warehouse

Geldon, Arthur L.

2003-01-01

The geology of the Paleozoic rocks in the Upper Colorado River Basin in Arizona, Colorado, New Mexico, Utah, and Wyoming, was studied as part of the U.S. Geological Survey's Regional Aquifer-System Analysis Program to provide support for hydrogeological interpretations. The study area is segmented by numerous uplifts and basins caused by folding and faulting that have recurred repeatedly from Precambrian to Cenozoic time. Paleozoic rocks in the study area are 0-18,000 feet thick. They are underlain by Precambrian igneous, metamorphic, and sedimentary rocks and are overlain in most of the area by Triassic formations composed mostly of shale. The overlying Mesozoic and Tertiary rocks are 0-27,000 feet thick. All Paleozoic systems except the Silurian are represented in the region. The Paleozoic rocks are divisible into 11 hydrogeologic units. The basal hydrogeologic unit consisting of Paleozoic rocks, the Flathead aquifer, predominantly is composed of Lower to Upper Cambrian sandstone and quartzite. The aquifer is 0-800 feet thick and is overlain gradationally to unconformably by formations of Cambrian to Mississippian age. The Gros Ventre confining unit consists of Middle to Upper Cambrian shale with subordinate carbonate rocks and sandstone. The confining unit is 0-1,100 feet thick and is overlain gradationally to unconformably by formations of Cambrian to Mississippian age. The Bighom aquifer consists of Middle Cambrian to Upper Ordovician limestone and dolomite with subordinate shale and sandstone. The aquifer is 0-3,000 feet thick and is overlain unconformably by Devonian and Mississipplan rocks. The Elbert-Parting confining unit consists of Lower Devonian to Lower Mississippian limestone, dolomite, sandstone, quartzite, shale, and anhydrite. It is 0-700 feet thick and is overlain conformably to unconformably by Upper Devonian and Mississippian rocks. The Madison aquifer consists of two zones of distinctly different lithology. The lower (Redwall-Leadville) zone is 0-2,500 feet thick and is composed almost entirely of Upper Devonian to Upper Mississippian limestone, dolomite, and chert. The overlying (Darwin-Humbug) zone is 0-800 feet thick and consists of Upper Mississippian limestone, dolomite, sandstone, shale, gypsum, and solution breccia. The Madison aquifer is overlain conformably by Upper Mississippian and Pennsylvanian rocks. The Madison aquifer in most areas is overlain by Upper Mississippian to Middle Pennsylvanian rocks of the Four Comers confining unit. The lower part of this confining unit, the Belden-Molas subunit, consists of as much as 4,300 feet of shale with subordinate carbonate rocks, sandstone, and minor gypsum. The upper part of the confining unit, the Paradox-Eagle Valley subunit, in most places consists of as much as 9,700 feet of interbedded limestone, dolomite, shale, sandstone, gypsum, anhydrite, and halite. Locally, the evaporitic rocks are deformed into diapirs as much as 15,000 feet thick. The Four Corners confining unit is overlain gradationally to disconformably by Pennsylvanian rocks. The uppermost Paleozoic rocks comprise the Canyonlands aquifer, which is composed of three zones with distinctly different lithologies. The basal (Cutler-Maroon) zone consists of as much as 16,500 feet of Lower Pennsylvanian to Lower Permian sandstone, conglomerate, shale, limestone, dolomite, and gypsum. The middle (Weber-De Chelly) zone consists of as much as 4,000 feet of Middle Pennsylvanian to Lower Permian quartz sandstone with minor carbonate rocks and shale. The upper (Park City-State Bridge) zone consists of as much as 800 feet of Lower to Upper Permian limestone, dolomite, shale, sandstone, phosphorite, chert, and gypsum. The Canyonlands aquifer is overlain disconformably to unconformably by formations of Triassic and Jurassic age.

Subdivision of the Cambrian-Ordovician Upper Sandstone Aquifer'' in the Fox Cities area, east-central Wisconsin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Erikson, K.A.; Smith, G.L.

The informally-named Upper Sandstone Aquifer,'' a lithologically heterogeneous unit, has been subdivided into three thinner hydrostratigraphic units, the Upper Cambrian Jordan Formation (sandstone), the Lower Ordovician Prairie du Chien Group (dolomite), and the Middle Ordovician St. Peter Formation (mostly sandstone). Reevaluation of the Upper Sandstone Aquifer'' in the Fox Cities area (Appleton, Neenah, Menasha) was based on detailed analysis of 125 geologic well logs and 200 well-construction reports. Isopach maps and geologic cross-sections of these units in the Fox Cities area show extreme variations in thickness over short lateral distances. Although the Jordan Formation has a uniform thickness of 13more » m (40 ft), the Prairie du Chien Group varies from 0--88 m (0--275 ft). The St. Peter Formation varies in thickness from 0--108 m (0--335 ft). The Prairie du Chien Group is relatively thin or absent in the Fox Cities area in locations where the overlying St. Peter Formation is relatively thick. St Peter can be further subdivided into Readstown, Tonti, and Glenwood Members. The Readstown Member is a lithologically heterogeneous unit of variable thickness and distribution. The Tonti Member is a poorly cemented, fine-medium quartz arenite with which is lumped the Glenwood Member, a conglomeratic, silty medium-coarse sandstone. Maximum St. Peter thicknesses represent filled paleokarst depressions developed on top of the Prairie du Chien Group, with profound implications for estimates of hydraulic conductivity.« less

500 Myr of thermal history elucidated by multi-method detrital thermochronology of North Gondwana Cambrian sandstone (Eilat area, Israel)

NASA Astrophysics Data System (ADS)

Vermeesch, P.; Avigad, D.

2009-04-01

Following the Neoproterozoic Pan-African orogeny, the Arabian-Nubian Shield (ANS) of North Africa and Arabia was eroded and then covered by Cambrian sandstones that record the onset of platform sedimentation. We applied K-feldspar 40Ar/39Ar, zircon and apatite fission track and apatite (U-Th)/He thermochronology to detritus from Cambrian sandstones of southern Israel deposited at about 500 Ma. U-Pb detrital zircon ages from these sandstones predate deposition and record the earlier Neoproterozoic crustal evolution of the Pan-African orogens. 40Ar/39Ar ages from 50 single grains of K-feldspar yield a Cambrian mean of approximately 535 Ma. The 40Ar/39Ar age spectrum of a multi-grain K-feldspar aliquot displays diffusion behaviour compatible with >560 Ma cooling later affected by a heating event. Assuming that the high temperature domains of the K-feldspars have not been affected by subsequent (hydro)thermal events, and taking previously published K-Ar and Rb-Sr ages from other parts of the East African Orogen at face value, these ages apparently record Pan-African thermal resetting below a thick volcano-sedimentary pile similar to the Saramuj conglomerate in Jordan and/or the Hammamat in Egypt. Detrital zircon fission track (ZFT) ages cluster around 380 Ma, consistent with previous ZFT results from Neoproterozoic basement and sediments of the region, revealing that the Cambrian platform sequence experienced a middle Devonian thermal event and low-grade metamorphism. Regional correlation indicates that during Devonian time the sedimentary cover atop the Cambrian in Israel was never in excess of 2.5 km, requiring an abnormally steep geothermal gradient to explain the complete ZFT annealing. A basal Carboniferous unconformity can be traced from Syria to southern Saudi Arabia, suggesting that the observed Devonian ZFT ages represent a regional tectonothermal event. Similar Devonian ZFT ages were reported from ANS basement outcrops in the Eastern Desert, 500 km south of Eilat. The detrital apatites we studied all have extremely rounded cores suggestive of a distant provenance, but some grains also feature distinct euhedral U-rich apatite overgrowth rims. Authigenic apatite may have grown during the late Devonian thermal event we dated by ZFT, coinciding with existing Rb-Sr ages from authigenic clays in the same deposits and leading to the conclusion that the Devonian event was probably hydrothermal. Like the ZFT ages, the detrital apatite fission track (AFT) ages were also completely reset after deposition. Sixty single grain detrital apatite fission track (AFT) ages group at ~270 Ma with significant dispersion. Inverse modeling of the AFT data indicate extended and/or repeated residence in the AFT partial annealing zone, in turn suggesting an episodic burial-erosion history during the Mesozoic caused by low-amplitude vertical motions. Seven detrital apatite (U-Th)/He ages scatter between 33 and 77 Ma, possibly resulting from extreme compositional zonation associated with the authigenic U-rich overgrowths. The ~70 Ma (U-Th)/He ages are more likely to be accurate, setting 1-2 km as an upper limit (depending on the geothermal gradient) on the post-Cretaceous exhumation of the Cambrian sandstone and showing no evidence for substantial denudation related to Tertiary rifting of the Red Sea.

Factors controlling reservoir quality in tertiary sandstones and their significance to geopressured geothermal production

DOE Office of Scientific and Technical Information (OSTI.GOV)

Loucks, R.G.; Richmann, D.L.; Milliken, K.L.

1981-01-01

Variable intensity of diagenesis is the factor primarily responsible for contrasting regional reservoir quality of Tertiary sandstones from the upper and lower Texas coast. Detailed comparison of Frio sandstone from the Chocolate Bayou/Danbury Dome area, Brazoria County, and Vicksburg sandstones from the McAllen Ranch Field area, Hidalgo County, reveals that extent of diagenetic modification is most strongly influenced by (1) detrital mineralogy and (2) regional geothermal gradients. The regional reservoir quality of Frio sandstones from Brazoria County is far better than that characterizing Vicksburg sandstones from Hidalgo County, especially at depths suitable for geopressured geothermal energy production. However, in predictingmore » reservoir quality on a site-specific basis, locally variable factors such as relative proportions for porosity types, pore geometry as related to permeability, and local depositional environment must also be considered. Even in an area of regionally favorable reservoir quality, such local factors can significantly affect reservoir quality and, hence, the geothermal production potential of a specific sandstone unit.« less

Origin of northern Gondwana Cambrian sandstone revealed by detrital zircon SHRIMP dating

USGS Publications Warehouse

Avigad, D.; Kolodner, K.; McWilliams, M.; Persing, H.; Weissbrod, T.

2003-01-01

Voluminous Paleozoic sandstone sequences were deposited in northern Africa and Arabia following an extended Neoproterozoic orogenic cycle that culminated in the assembly of Gondwana. We measured sensitive high-resolution ion microprobe (SHRIMP) U-Pb ages of detrital zircons separated from several Cambrian units in the Elat area of southern Israel in order to unravel their provenance. This sandstone forms the base of the widespread siliciclastic section now exposed on the periphery of the Arabian-Nubian shield in northeastern Africa and Arabia. Most of the detrital zircons we analyzed yielded Neoproterozoic concordant ages with a marked concentration at 0.55–0.65 Ga. The most likely provenance of the Neoproterozoic detritus is the Arabian-Nubian shield; 0.55–0.65 Ga was a time of posttectonic igneous activity, rift-related volcanism, and strike-slip faulting there. Of the zircons, 30% yielded pre-Neoproterozoic ages grouped at 0.9–1.1 Ga (Kibaran), 1.65–1.85 Ga, and 2.45–2.7 Ga. The majority of the pre-Neoproterozoic zircons underwent Pb loss, possibly as a consequence of the Pan-African orogeny resetting their provenance. Rocks of the Saharan metacraton and the southern Afif terrane in Saudi Arabia (∼1000 km south of Elat) are plausible sources of these zircons. Kibaran basement rocks are currently exposed more than 3000 km south of Elat (flanking the Mozambique belt), but the shape of the detrital zircons of that age and the presence of feldspar in the host sandstone are not fully consistent with such a long-distance transport. Reworking of Neoproteorozoic glacial detritus may explain the presence of Kibaran detrital zircons in the Cambrian of Elat, but the possibility that the Arabian-Nubian shield contains Kibaran rocks (hitherto not recognized) should also be explored.

Evidence of the coupled geology system and its impact on the evolution of South China during the transformation from Sinian to Cambrian

NASA Astrophysics Data System (ADS)

Yang, C.; Wang, T.; Chen, Z.

2016-12-01

Separate interpretation of the evidence on tectonic, sedimentology or climate is insufficient to reappear the dynamic process of the evolution of the Earth surface, thus, tectonic, sedimentology and climate should be considered as a coupled system. Thick carbonate succession is overlaying on the paleo-uplift which is divided into two parts by a fluted belt in the center of Sichuan Basin. Sinian carbonate rocks is commonly composed by algae dolomite, while at the top of the Sinian succession the rocks had experienced meteoric karstification. Grain dolostones, fine-grained siliciclastic sandstones with mudstone appeare as the regional sediment of Cambrian. However, extraordinary thick mudstone had settled in the fluted belt, and the succession could be divided in to siliciclastic mud of the lower and clay-carbonate mud of the upper. The geochemistry and well log synthesized profile of Z4 well indicate that the chemical condition of siliciclastic mud and clay-carbonate mud had changed from oxidation to reduction, however the siliciclastic mud only appeared within the fluted belt. The fluted belt does not exist on the map of the gravity anomaly, but it had been convinced by the seismic data. The precursor of the fluted belt might be a sag within the platform basement, while with the sea level gradually raising up, the growth of algal mound exacerbated the geomorphology difference. Then a regression had happened at the end of the Sinian, starved all the algae and caused weather crust. Meanwhile, the fluted belt became a closed lagoon, received the sediment including algal mound fragment and biosilic crystals. Afterwards, rapidly increasing of the sea level deposited thick cay-carbonate mud that could be recognized as the sediment of maximum flooding surface. Then with the sea level decreasing, siliciclastic sandstones and inorganic grain carbonate became the main petrology of the Cambrian strata. Fine-grained eolian siliciclastic sandstones within the Cambrian carbonate indicate the influence of the continent, but this terrigenous clastics not exist in Sinian carbonate because the location of the platform moved closer to the continent in Cambrian. Meanwhile, there is no algal within Cambrian carbonate, it means the platform might drift to inhospitable place for the algal during the period.

Reservoir assessment of the Nubian sandstone reservoir in South Central Gulf of Suez, Egypt

NASA Astrophysics Data System (ADS)

El-Gendy, Nader; Barakat, Moataz; Abdallah, Hamed

2017-05-01

The Gulf of Suez is considered as one of the most important petroleum provinces in Egypt and contains the Saqqara and Edfu oil fields located in the South Central portion of the Gulf of Suez. The Nubian sandstone reservoir in the Gulf of Suez basin is well known for its great capability to store and produce large volumes of hydrocarbons. The Nubian sandstone overlies basement rocks throughout most of the Gulf of Suez region. It consists of a sequence of sandstones and shales of Paleozoic to Cretaceous age. The Nubian sandstone intersected in most wells has excellent reservoir characteristics. Its porosity is controlled by sedimentation style and diagenesis. The cementation materials are mainly kaolinite and quartz overgrowths. The permeability of the Nubian sandstone is mainly controlled by grain size, sorting, porosity and clay content especially kaolinite and decreases with increase of kaolinite. The permeability of the Nubian Sandstone is evaluated using the Nuclear Magnetic Resonance (NMR technology) and formation pressure data in addition to the conventional logs and the results were calibrated using core data. In this work, the Nubian sandstone was investigated and evaluated using complete suites of conventional and advanced logging techniques to understand its reservoir characteristics which have impact on economics of oil recovery. The Nubian reservoir has a complicated wettability nature which affects the petrophysical evaluation and reservoir productivity. So, understanding the reservoir wettability is very important for managing well performance, productivity and oil recovery.

Sedimentological reservoir characteristics of the Paleocene fluvial/lacustrine Yabus Sandstone, Melut Basin, Sudan

NASA Astrophysics Data System (ADS)

Mahgoub, M. I.; Padmanabhan, E.; Abdullatif, O. M.

2016-11-01

Melut Basin in Sudan is regionally linked to the Mesozoic-Cenozoic Central and Western African Rift System (CWARS). The Paleocene Yabus Formation is the main oil producing reservoir in the basin. It is dominated by channel sandstone and shales deposited in fluvial/lacustrine environment during the third phase of rifting in the basin. Different scales of sedimentological heterogeneities influenced reservoir quality and architecture. The cores and well logs analyses revealed seven lithofacies representing fluvial, deltaic and lacustrine depositional environments. The sandstone is medium to coarse-grained, poorly to moderately-sorted and sub-angular to sub-rounded, arkosic-subarkosic to sublitharenite. On the basin scale, the Yabus Formation showed variation in sandstone bodies, thickness, geometry and architecture. On macro-scale, reservoir quality varies vertically and laterally within Yabus Sandstone where it shows progressive fining upward tendencies with different degrees of connectivity. The lower part of the reservoir showed well-connected and amalgamated sandstone bodies, the middle to the upper parts, however, have moderate to low sandstone bodies' connectivity and amalgamation. On micro-scale, sandstone reservoir quality is directly affected by textures and diagenetic changes such as compaction, cementation, alteration, dissolution and kaolinite clays pore fill and coat all have significantly reduced the reservoir porosity and permeability. The estimated porosity in Yabus Formation ranges from 2 to 20% with an average of 12%; while permeability varies from 200 to 500 mD and up to 1 Darcy. The understanding of different scales of sedimentological reservoir heterogeneities might contribute to better reservoir quality prediction, architecture, consequently enhancing development and productivity.

Geology and hydrocarbon potential of the Oued Mya basin, Algeria

DOE Office of Scientific and Technical Information (OSTI.GOV)

Benamrane, O.; Messaoudi, M.; Messelles, H.

1993-09-01

The Oued Mya hydrocarbon system is located in the Sahara basin. It is one of the best producing basins in Algeria, along with the Ghadames and Illizi basins. The stratigraphic section consists of Paleozoic and Mesozoic, and is about 5000 m thick. This intracratonic basin is limited to the north by the Toughourt saddle, and to the west and east it is flanked by regional arches, Allal-Tilghemt and Amguid-Hassi Messaoud, which culminate in the super giant Hassi Messaoud and Hassi R'mel hydrocarbon accumulations, respectively, producing oil from the Cambrian sands and gas from the Trissic sands. The primary source rockmore » in this basin is lower Silurian shale, with an average thickness of 50 m and a total organic carbon of 6% (14% in some cases). Results of maturation modeling indicate that the lower Silurian source is in the oil window. The Ordovician shales are also source rocks, but in a second order. Clastic reservoirs are in the Trissic sequence, which is mainly fluvial deposits with complex alluvial channels, and the main target in the basin. Clastic reservoirs in the lower Devonian section have a good hydrocarbon potential east of the basin through a southwest-northwest orientation. The Late Trissic-Early Jurassic evaporites that overlie the Triassic clastic interval and extend over the entire Oued Mya basin, are considered to be a super-seal evaporite package, which consists predominantly of anhydrite and halite. For paleozoic targets, a large number of potential seals exist within the stratigraphic column. This super seal does not present oil dismigration possibilities. We can infer that a large amount of the oil generated by the Silurian source rock from the beginning of Cretaceous until now still is not discovered and significantly greater volumes could be trapped within structure closures and mixed or stratigraphic traps related to the fluvial Triassic sandstones, marine Devonian sands, and Cambrian-Ordovician reservoirs.« less

Geology and hydrocarbon potential of the Oued Mya Basin, Algeria

DOE Office of Scientific and Technical Information (OSTI.GOV)

Benamrane, O.; Messaoudi, M.; Messelles, H.

1992-01-01

The hydrocarbon System Ourd Mya is located in the Sahara Basin. It is one of the producing basin in Algeria. The stratigraphic section consists of Paleozoic and Mesosoic, it is about 5000m thick. In the eastern part, the basin is limited by the Hassi-Messaoud high zone which is a giant oil field producing from the Cambrian sands. The western part is limited by Hassi R'mel which is one of the biggest gas field in the world, it is producing from the triassic sands. The Mesozoic section is laying on the lower Devonian and in the eastern part, on the Cambrian.more » The main source rock is the Silurian shale with an average thickness of 50m and a total organic matter of 6% (14% in some cases). Results of maturation modeling indicate that the lower Silurian source is in the oil window. The Ordovician shales are also a source rock, but in a second order. Clastic reservoirs are in the Triassic sequence which is mainly fluvial deposits with complex alluvial channels, it is the main target in the basin. Clastic reservoirs within the lower Devonian section have a good hydrocarbon potential in the east of the basin through a southwest-northeast orientation. The late Triassic-Early Jurassic evaporites overlie the Triassic clastic interval and extend over the entire Oued Mya Basin. This is considered as a super-seal evaporate package, which consists predominantly of anhydrite and halite. For Paleozoic targets, a large number of potential seals exist within the stratigraphic column. The authors infer that a large amount of the oil volume generated by the Silurian source rock from the beginning of Cretaceous until now, still not discovered could be trapped within structure closures and mixed or stratigraphic traps related to the fluvial Triassic sandstones, marine Devonian sands and Cambro-Ordovician reservoirs.« less

The structural evolution of the Ghadames and Illizi basins during the Paleozoic, Mesozoic and Cenozoic: Petroleum implications

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gauthier, F.J.; Boudjema, A.; Lounis, R.

1995-08-01

The Ghadames and Illizi basins cover the majority of the eastern Sahara of Algeria. Geologicaly, this part of the Central Saharan platform has been influenced by a series of structural arches and {open_quotes}moles{close_quotes} (continental highs) which controlled sedimentation and structure through geologic time. These features, resulting from and having been affected by nine major tectonic phases ranging from pre-Cambrian to Tertiary, completely bound the Ghadames and Illizi Basins. During the Paleozoic both basins formed one continuous depositional entity with the Ghadames basin being the distal portion of the continental sag basin where facies and thickness variations are observed over largemore » distances. It is during the Mesozoic-Cenozoic that the Ghadames basin starts to evolve differently from the Illizi Basin. Eustatic low-stand periods resulted in continental deposition yielding the major petroleum-bearing reservoir horizons (Cambrian, Ordovician, Siluro-Devonian and Carboniferous). High-stand periods corresponds to the major marine transgressions covering the majority of the Saharan platform. These transgressions deposited the principal source rock intervals of the Silurian and Middle to Upper Devonian. The main reservoirs of the Mesozoic and Cenozoic are Triassic sandstone sequences which are covered by a thick evaporite succession forming a super-seal. Structurally, the principal phases affecting this sequence are the extensional events related to the breakup of Pangea and the Alpine compressional events. The Ghadames and Illizi basins, therefore, have been controlled by a polphase tectonic history influenced by Pan African brittle basement fracturing which resulted in complex structures localized along the major basin bounding trends as well as several subsidiary trends within the basin. These trends, as demonstrated with key seismic data, have been found to contain the majority of hydrocarbons trapped.« less

CHARACTERIZATION OF SANDSTONE RESERVOIRS FOR ENHANCED OIL RECOVERY: THE PERMIAN UPPER MINNELUSA FORMATION, POWDER RIVER BASIN, WYOMING.

USGS Publications Warehouse

Schenk, C.J.; Schmoker, J.W.; Scheffler, J.M.

1986-01-01

Upper Minnelusa sandstones form a complex group of reservoirs because of variations in regional setting, sedimentology, and diagenetic alteration. Structural lineaments separate the reservoirs into northern and southern zones. Production in the north is from a single pay sand, and in the south from multi-pay sands due to differential erosion on top of the Upper Minnelusa. The intercalation of eolian dune, interdune, and sabkha sandstones with marine sandstones, carbonates, and anhydrites results in significant reservoir heterogeneity. Diagenetic alterations further enhance heterogeneity, because the degree of cementation and dissolution is partly facies-related.

Geology and ground-water resources of the Rawlins area, Carbon County, Wyoming

USGS Publications Warehouse

Berry, Delmar W.

1960-01-01

The Rawlins area in west-central Carbon County, south-central Wyoming includes approximately 634 square miles of plains and valleys grading into relatively rugged uplifts. The climate is characterized by low precipitation, rapid evaporation, and a wide range of temperature. Railroading and ranching are the principal occupations in the area. The exposed rocks in the area range in age from Precambrian through Recent. The older formations are exposed in the uplifted parts, the oldest being exposed along the apex of the Rawlins uplift. The formations dip sharply away from the anticlines and other uplifts and occur in the subsurface throughout the remainder of the area. The Cambrian rocks (undifferentiated), Madison limestone, Tensleep sandstone, Sun dance formation, Cloverly formation, Frontier formation, and Miocene and Pliocene rocks (undifferentiated) yield water to domestic and stock wells in the area. In the vicinity of the Rawlins uplift, the rocks of Cambrian age, Madison limestone, and Tensleep sandstone yield water to a few public-supply wells. The Cloverly formation yields water to public-supply wells in the Miller Hill and Sage Creek basin area. Wells that tap the Madison limestone, Tensleep sandstone, and Cloverly formation yield water under sufficient artesian pressure to flow at the land surface. The Browns Park formation yields water to springs that supply most of the Rawlins city water and supply water for domestic and stock use. Included on the geologic map are location of wells and test wells, depths to water below land surface, and location of springs. Depths to water range from zero in the unconsolidated deposits along the valley of Sugar Creek at the southern end of the Rawlins uplift to as much as 129 feet below the land surface in the Tertiary sedimentary rocks along the Continental Divide in the southern part of the area. The aquifers are recharged principally by precipitation that falls upon the area, by percolation from streams and ponds, and by movement of ground water from adjacent areas. Water is discharged from the ground-water reservoir by evaporation and transpiration, by seeps and springs, through wells, and by underflow out of the area. Although most water supplies in the area are obtained from springs, some domestic, stock, and public supplies are obtained from drilled wells, many yielding water under artesian pressure, and some flowing. Dissolved solids in the water from several geologic sources, ranging from 181 to 6,660 parts per million (ppm), indicate the varied chemical quality of ground water in the Rawlins area. Water from the Cambrian rocks, Tensleep sandstone, Cloverly formation, Frontier formation, Browns Park formation, and Miocene and Pliocene rocks is generally suitable for domestic and stock use. However, water yielded to the only well sampled in the lower part of the Frontier formation contained a high concentration of fluoride. Water from the rocks mentioned above contains less than 1,000 ppm of dissolved solids but in some places may contain iron in troublesome amounts. Water from the Madison limestone and Tensleep sandstone combined, Permian rocks, and Sundance formation contains more than 1,000 ppm of dissolved solids. Water in the Sundance, Cloverly, and Frontier :formations is very soft. More ground water can be obtained in the Rawlins area than is now being used. Many springs are undeveloped, and water can be obtained from additional wells without unduly lowering ground-water levels.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Hamlin, H.S.; Dutton, S.P.; Tyler, N.

The Tirrawarra Sandstone contains 146 million bbl of oil in Tirrawarra field in the Cooper basin of South Australia. We used core, well logs, and petro-physical data to construct a depositional-facies-based flow-unit model of the reservoir, which describes rock properties and hydrocarbon saturations in three dimensions. Using the model to calculate volumes and residency of original and remaining oil in place, we identified an additional 36 million bbl of oil in place and improved understanding of past production patterns. The Tirrawarra Sandstone reservoir was deposited in a Carboniferous-Permian proglacial intracratonic setting and is composed of lacustrine and fluvial facies assemblages.more » The stratigraphic framework of these nonmarine facies is defined by distinctive stacking patterns and erosional unconformities. Mudstone dominated zones that are analogous to marine maximum flooding surfaces bound the reservoir. At its base a progradational lacustrine-delta system, composed of lenticular mud-clast-rich sandstones enclosed in mudstone, is truncated by an unconformity. Sandstones in these lower deltaic facies lost most of their porosity by mechanical compaction of ductile grains. Sediment reworking by channel migration and locally shore-zone processes created by quartz-rich, multilateral sandstones, which retained the highest porosity and permeability of all the reservoir facies and contained most of the original oil in place. Braided-channel sandstones, however, are overlain by lenticular meandering-channel sandstones, which in turn grade upward into widespread mudstones and coals. Thus, this uppermost part of the reservoir displays a retrogradational stacking pattern and upward-decreasing reservoir quality. Our results demonstrate that depositional variables are the primary controls on reservoir quality and productivity in the Tirrawarra Sandstone.« less

Geological and physicochemical controls of the spatial distribution of partition coefficients for radionuclides (Sr-90, Cs-137, Co-60, Pu-239,240 and Am-241) at a site of nuclear reactors and radioactive waste disposal (St. Petersburg region, Russian Federation).

PubMed

Rumynin, Vyacheslav G; Nikulenkov, Anton M

2016-10-01

The paper presents a study of the sorption properties of sediments of different geological ages and lithological types, governing radionuclide retention in the subsurface (up to 160 m beneath the surface) within the area of potential influence of the Northwestern Center of Atomic Energy (NWCAE), St. Petersburg region, RF. The focus of this work is mostly on the sedimentary rocks of two types, i.e., weakly cemented sandstone and lithified clay formations of Cambrian and Vendian series. The first lithological unit is associated with a groundwater reservoir (Lomonosov aquifer), and the second one, with both a relative aquitard in the upper part of the Vendian formation (Kotlin clay) and a regional aquifer (Gdov aquifer) in the lower part of the formation. The main mechanisms responsible for the variability of the sorption distribution coefficient (Kd, defined as the ratio of the concentration of solute on solid phase to its concentration in solution at equilibrium) was identified for radionuclides such as Sr-90, Cs-137, Co-60, Pu-239,240, and Am-241. It was shown that the main factors contributing to the chemical heterogeneity of the Cambrian sandstone were related to the presence of secondary minerals (iron and magnesium oxides and hydroxides produced by the weathering process) in trace amounts, forming correlated layer structures. The statistical analysis of nonlinear isotherms confirmed this conclusion. For the Vendian formation, a determinate trend was established in the Kd change over depth as a result of temporal trends in the sedimentation process and pore-water chemistry. The geostatistical characteristics and the spatial correlation models for describing linear sorption of different radionuclides are not identical, and the exhibition of chemical heterogeneity of sedimentary rock of a particular lithological type depends on radionuclide chemistry. Moreover, variogram analysis for some Kd data sets (both in Cambrian and Vendian formations) demonstrates the total absence of auto-correlation (pure nugget effect). It can be supposed that sampling distances did not allow the evaluation of small-scale variability in sediment sorption properties. Copyright © 2016 Elsevier Ltd. All rights reserved.

Diagenesis and reservoir quality of the Lower Cretaceous Quantou Formation tight sandstones in the southern Songliao Basin, China

NASA Astrophysics Data System (ADS)

Xi, Kelai; Cao, Yingchang; Jahren, Jens; Zhu, Rukai; Bjørlykke, Knut; Haile, Beyene Girma; Zheng, Lijing; Hellevang, Helge

2015-12-01

The Lower Cretaceous Quantou Formation in the southern Songliao Basin is the typical tight oil sandstone in China. For effective exploration, appraisal and production from such a tight oil sandstone, the diagenesis and reservoir quality must be thoroughly studied first. The tight oil sandstone has been examined by a variety of methods, including core and thin section observation, XRD, SEM, CL, fluorescence, electron probing analysis, fluid inclusion and isotope testing and quantitative determination of reservoir properties. The sandstones are mostly lithic arkoses and feldspathic litharenites with fine to medium grain size and moderate to good sorting. The sandstones are dominated by feldspar, quartz, and volcanic rock fragments showing various stages of disintegration. The reservoir properties are quite poor, with low porosity (average 8.54%) and permeability (average 0.493 mD), small pore-throat radius (average 0.206 μm) and high displacement pressure (mostly higher than 1 MPa). The tight sandstone reservoirs have undergone significant diagenetic alterations such as compaction, feldspar dissolution, quartz cementation, carbonate cementation (mainly ferrocalcite and ankerite) and clay mineral alteration. As to the onset time, the oil emplacement was prior to the carbonate cementation but posterior to the quartz cementation and feldspar dissolution. The smectite to illite reaction and pressure solution at stylolites provide a most important silica sources for quartz cementation. Carbonate cements increase towards interbedded mudstones. Mechanical compaction has played a more important role than cementation in destroying the reservoir quality of the K1q4 sandstone reservoirs. Mixed-layer illite/smectite and illite reduced the porosity and permeability significantly, while chlorite preserved the porosity and permeability since it tends to be oil wet so that later carbonate cementation can be inhibited to some extent. It is likely that the oil emplacement occurred later than the tight rock formation (with the porosity close to 10%). However, thicker sandstone bodies (more than 2 m) constitute potential hydrocarbon reservoirs.

Controls on the quality of Miocene reservoirs, southern Gulf of Mexico

NASA Astrophysics Data System (ADS)

Gutiérrez Paredes, Hilda Clarisa; Catuneanu, Octavian; Hernández Romano, Ulises

2018-01-01

An investigation was conducted to determine the main controls on the reservoir quality of the middle and upper Miocene sandstones in the southern Gulf of Mexico based on core descriptions, thin section petrography and petrophysical data; as well as to explore the possible link between the sequence stratigraphic framework, depositional facies and diagenetic alterations. The Miocene deep marine sandstones are attributed to the falling-stage, lowstand, and transgressive systems tracts. The middle Miocene falling-stage systems tract includes medium-to very fine-grained, and structureless sandstones deposited in channels and frontal splays, and muddy sandstones, deposited in lobes of debrites. The lowstand and transgressive systems tracts consist of medium-to very fine-grained massive and normally graded sandstones deposited in channel systems within frontal splay complexes. The upper Miocene falling-stage systems tract includes medium-to coarse-grained, structureless sandstones deposited in channel systems and frontal splay, as well as lobes of debrites formed by grain flows and hybrid-flow deposits. The lowstand and transgressive systems tracts include fine-grained sandstones deposited in overbank deposits. The results reveal that the depositional elements with the best reservoir quality are the frontal splays deposited during the falling-stage system tracts. The reservoir quality of the Miocene sandstones was controlled by a combination of depositional facies, sand composition and diagenetic factors (mainly compaction and calcite cementation). Sandstone texture, controlled primarily by depositional facies appears more important than sandstone composition in determining reservoir quality; and compaction was more important than cementation in porosity destruction. Compaction was stopped, when complete calcite cementation occurred.

Petroleum geology of Carter sandstone (upper Mississippian), Black Warrior Basin, Alabama

DOE Office of Scientific and Technical Information (OSTI.GOV)

Bearden, B.L.; Mancini, E.A.

1985-03-01

The presence of combination petroleum traps makes the Black Warrior basin of northwestern Alabama an attractive area for continued hydrocarbon exploration. More than 1,500 wells have been drilled, and more than 90 separate petroleum pools have been discovered. The primary hydrocarbon reservoirs are Upper Mississippian sandstones. The Carter sandstone is the most productive petroleum reservoir in the basin. Productivity of the Carter sandstone is directly related to its environment of deposition. The Carter accumulated within a high constructive elongate to lobate delta, which prograded into the basin from the northwest to the southeast. Carter bar-finger and distal-bar lithofacies constitute themore » primary hydrocarbon reservoirs. Primary porosity in the Carter sandstone has been reduced by quartz overgrowths and calcite cementation. Petroleum traps in the Carter sandstone in central Fayette and Lamar Counties, Alabama, are primarily stratigraphic and combination (structural-stratigraphic) traps. The potential is excellent for future development of hydrocarbon reservoirs in the Upper Mississippian Carter sandstone. Frontier regions south and east of the known productive limits of the Black Warrior basin are ideal areas for continued exploration.« less

Integrated interpretation of C-8 and G-61 sandstones at Badak and Nilam fields in Sanga-Sanga block of east Kalimantan, Indonesia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ade, W.C.; Suwarlan, W.

1989-03-01

Huffco's Badak and Nilam fields are giant gas fields that together currently produce more than 1.0 bcf of gas per day from sandstones within the Miocene Balikpapan beds. The reservoir sandstones were deposited within a thick regressive deltaic sequence that includes coals, shales, and occasional limestones. Wells typically encounter multiple stacked pay sandstones at depths ranging from about 5500 ft to more than 13,000 ft. Individual sandstone thicknesses can vary from several feet to more than 20 ft. Abrupt lateral stratigraphic variations in sandstone thickness are the rule rather than the exception. Sandstone reservoir interpretations are based on an integratedmore » approach by incorporating the study of well logs, cores, seismic sections, normal moveout-corrected gathers, amplitude variations with offset (AVO) graphs, and pressure and reservoir performance data.« less

Development of diagenetic seals in carbonates and sandstones

DOE Office of Scientific and Technical Information (OSTI.GOV)

Schmidt, V.; Almon, W.

1983-03-01

Diagenetic seals effectively block the movement of reservoir hydrocarbons in many sandstone and carbonate rock units. Diagenetic seals in sandstones and carbonate rocks encase reservoir rocks with either depositional or diagenetic porosity. Diagenetic reservoir porosity may originate before or after the establishment of an effective diagenetic seal. Hydrocarbon traps with diagenetic seals may conform in their geometry as well to structure or stratigraphy as to diagenetic facies. Therefore, some structural and stratigraphic traps may, in part or entirely, depend on diagenetic seals. Detailed analysis of diagenetic seals in sandstones and carbonate rocks can considerably improve our ability to predict theirmore » occurrence and to recognize their spatial and temporal relationship to reservoir rocks and hydrocarbon migration.« less

Cambrian-lower Middle Ordovician passive carbonate margin, southern Appalachians: Chapter 14

USGS Publications Warehouse

Read, J. Fred; Repetski, John E.

2012-01-01

The southern Appalachian part of the Cambrian–Ordovician passive margin succession of the great American carbonate bank extends from the Lower Cambrian to the lower Middle Ordovician, is as much as 3.5 km (2.2 mi) thick, and has long-term subsidence rates exceeding 5 cm (2 in.)/k.y. Subsiding depocenters separated by arches controlled sediment thickness. The succession consists of five supersequences, each of which contains several third-order sequences, and numerous meter-scale parasequences. Siliciclastic-prone supersequence 1 (Lower Cambrian Chilhowee Group fluvial rift clastics grading up into shelf siliciclastics) underlies the passive margin carbonates. Supersequence 2 consists of the Lower Cambrian Shady Dolomite–Rome-Waynesboro Formations. This is a shallowing-upward ramp succession of thinly bedded to nodular lime mudstones up into carbonate mud-mound facies, overlain by lowstand quartzose carbonates, and then a rimmed shelf succession capped by highly cyclic regressive carbonates and red beds (Rome-Waynesboro Formations). Foreslope facies include megabreccias, grainstone, and thin-bedded carbonate turbidites and deep-water rhythmites. Supersequence 3 rests on a major unconformity and consists of a Middle Cambrian differentiated rimmed shelf carbonate with highly cyclic facies (Elbrook Formation) extending in from the rim and passing via an oolitic ramp into a large structurally controlled intrashelf basin (Conasauga Shale). Filling of the intrashelf basin caused widespread deposition of thin quartz sandstones at the base of supersequence 4, overlain by widespread cyclic carbonates (Upper Cambrian lower Knox Group Copper Ridge Dolomite in the south; Conococheague Formation in the north). Supersequence 5 (Lower Ordovician upper Knox in the south; Lower to Middle Ordovician Beekmantown Group in the north) has a basal quartz sandstone-prone unit, overlain by cyclic ramp carbonates, that grade downdip into thrombolite grainstone and then storm-deposited deep-ramp carbonates. Passive margin deposition was terminated by arc-continent collision when the shelf was uplifted over a peripheral bulge while global sea levels were falling, resulting in the major 0- to 10-m.y. Knox–Beekmantown unconformity. The supersequences and sequences appear to relate to regionally traceable eustatic sea level cycles on which were superimposed high-frequency Milankovitch sea level cycles that formed the parasequences under global greenhouse conditions.

Factors controlling reservoir quality in tertiary sandstones and their significance to geopressured geothermal production. Annual report, May 1, 1979-May 31, 1980

DOE Office of Scientific and Technical Information (OSTI.GOV)

Loucks, R.G.; Richmann, D.L.; Milliken, K.L.

1980-07-01

Differing extents of diagenetic modification is the factor primarily responsible for contrasting regional reservoir quality of Tertiary sandstones from the Upper and Lower Texas Gulf Coast. Detailed comparison of Frio sandstones from the Chocolate Bayou/Danbury Dome area, Brazoria County, and Vicksburg sandstones from the McAllen Ranch Field area, Hidalgo County, reveals that extent of diagenetic modification is most strongly influenced by (1) detrital mineralogy and (2) regional geothermal gradients. Vicksburg sandstones from the McAllen Ranch Field area are less stable, chemically and mechanically, than Frio sandstones from the Chocolate Bayou/Danbury dome area. Vicksburg sandstones are mineralogically immature and contain greatermore » proportions of feldspars and rock fragments than do Frio sandstones. Thr reactive detrital assemblage of Vicksubrg sandstones is highly susceptible to diagenetic modification. Susceptibility is enhanced by higher than normal geothermal gradients in the McAllen Ranch Field area. Thus, consolidation of Vicksburg sandstones began at shallower depth of burial and precipitation of authigenic phases (especially calcite) was more pervasive than in Frio sandstones. Moreover, the late-stage episode of ferroan calcite precipitation that occluded most secondary porosity in Vicksburg sandstones did not occur significantly in Frio sandstones. Therefore, regional reservoir quality of Frio sandstones from Brazoria County is far better than that characterizing Vicksburg sandstones from Hidalgo County, especially at depths suitable for geopressured geothermal energy production.« less

Discussion of case study of a stimulation experiment in a fluvial, tight-sandstone gas reservoir

DOE Office of Scientific and Technical Information (OSTI.GOV)

Azari, M.; Wooden, W.

The authors found Warpinski et al.'s paper (Case Study of a Stimulation Experiment in Fluvial, Tight-Sandstone Gas Reservoir. Nov. 1990 SPE Production Engineering, Pages 403-10) to be very thorough and informative. That paper considered geological, logging, completion, and pressure-transient data to produce a comprehensive formation evaluation of a fluvial, tight-sandstone gas reservoir. The purpose of this paper is to present the author's view on the peculiar pressure-transient responses shown.

Origin and implications of a thrust-bound gypsiferous unit along the western edge of Jabal Sumeini, northern Oman Mountains

NASA Astrophysics Data System (ADS)

Cooper, David J. W.; Ali, Mohammed Y.; Searle, Michael P.

2018-04-01

The Oman Mountains comprise a series of thrust sheets of Neo-Tethyan oceanic rocks that were emplaced onto the Arabian continental margin during obduction of the Semail Ophiolite during the Late Cretaceous. Three separate groups of anomalous gypsiferous bodies intrude the allochthonous units along faults over a distance of about 150 km in the Hawasina Window, Jabal Qumayrah and Jabal Sumeini. The bodies at Jabal Sumeini form a band about 4 km long and up to 100 m wide along a late-stage thrust that restacks the allochthon over a post-emplacement Maastrichtian-Palaeogene sedimentary succession. The gypsum shows evidence of flow-folding and contains numerous clasts and rafts of a range of quartzose sandstones, but with only a minor component from carbonates from the Neo-Tethyan Sumeini Group in the hanging-wall. Palaeogene limestones from the footwall succession are essentially absent. Strontium isotope ratios are high and intersect with the open ocean-water reference curve for the Late Cambrian-Ordovician and Late Miocene-Pliocene. They are also noticeably higher than the ratios from the two other gypsiferous outcrop areas in the Oman Mountains and from outcrops of Ediacaran-Early Cambrian salt domes in central Oman. However, the regional stratigraphy points towards a source of the gypsum from either an Ediacaran-Early Cambrian Ara Group salt basin or from the Lower Fars Formation (Early-Middle Miocene), and derivation of the sandstone clasts and rafts from thick Lower Palaeozoic clastic sequences. The discrepancy with the ages inferred from the strontium isotope data can be attributed to deposition of the gypsum in restricted conditions not in equilibrium with the prevailing ocean water. Two models are presented, for an Ediacaran-Early Cambrian and an Early-Middle Miocene source. While the latter cannot be wholly discounted, the stratigraphic and structural context point more strongly towards an Ediacaran-Early Cambrian Ara Group source of the gypsum. This was extruded along deep-rooted Late Cretaceous thrust faults that were reactivated during a period of Cenozoic compression, incorporating Lower Palaeozoic sandstone clasts from adjacent strata during extrusion, or during an earlier phase of possible halokinesis. This is consistent with existing models for the emplacement of the other two identified groups of gypsiferous bodies in the Oman Mountains and provides further evidence for the presence of smaller evaporite basins between the major Hormuz and central/ southern Oman salt basins.

Petrography and geochemistry of clastic sedimentary rocks as evidences for provenance of the Lower Cambrian Lalun Formation, Posht-e-badam block, Central Iran

NASA Astrophysics Data System (ADS)

Etemad-Saeed, N.; Hosseini-Barzi, M.; Armstrong-Altrin, John S.

2011-09-01

Petrography and geochemistry (major, trace and rare earth elements) of clastic rocks from the Lower Cambrian Lalun Formation, in the Posht-e-badam block, Central Iran, have been investigated to understand their provenance. Petrographical analysis suggests that the Lalun conglomerates are dominantly with chert clasts derived from a proximal source, probably chert bearing Precambrian Formations. Similarly, purple sandstones are classified as litharenite (chertarenite) and white sandstones as quartzarenite types. The detrital modes of purple and white sandstones indicate that they were derived from recycled orogen (uplifted shoulders of rift) and stable cratonic source. Most major and trace element contents of purple sandstones are generally similar to upper continental crust (UCC) values. However, white sandstones are depleted in major and trace elements (except SiO 2, Zr and Co) relative to UCC, which is mainly due to the presence of quartz and absence of other Al-bearing minerals. Shale samples have considerably lower content in most of the major and trace elements concentration than purple sandstones, which is possibly due to intense weathering and recycling. Modal composition (e.g., quartz, feldspar, lithic fragments) and geochemical indices (Th/Sc, La/Sc, Co/Th, Cr/Th, Cr/V and V/Ni ratios) of sandstones, and shales (La/Sc and La/Cr ratios) indicate that they were derived from felsic source rocks and deposited in a passive continental margin. The chondrite-normalized rare earth element (REE) patterns of the studied samples are characterized by LREE enrichment, negative Eu anomaly and flat HREE similar to an old upper continental crust composed chiefly of felsic components in the source area. The study of paleoweathering conditions based on modal composition, chemical index of alteration (CIA), plagioclase index of alteration (PIA) and A-CN-K (Al 2O 3 - CaO + Na 2O - K 2O) relationships indicate that probably chemical weathering in the source area and recycling processes have been more important in shale and white sandstones relative to purple sandstones. The results of this study suggest that the main source for the Lalun Formation was likely located in uplifted shoulders of a rifted basin (probably a pull-apart basin) in its post-rift stage (Pan-African basement of the Posht-e-badam block).

Reservoir heterogeneity in Carter Sandstone, North Blowhorn Creek oil unit and vicinity, Black Warrior Basin, Alabama

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kugler, R.L.; Pashin, J.C.

1992-05-01

This report presents accomplishments made in completing Task 3 of this project which involves development of criteria for recognizing reservoir heterogeneity in the Black Warrior basin. The report focuses on characterization of the Upper Mississippian Carter sandstone reservoir in North Blowhorn Creek and adjacent oil units in Lamar County, Alabama. This oil unit has produced more than 60 percent of total oil extracted from the Black Warrior basin of Alabama. The Carter sandstone in North Blowhorn Creek oil unit is typical of the most productive Carter oil reservoirs in the Black Warrior basin of Alabama. The first part of themore » report synthesizes data derived from geophysical well logs and cores from North Blowhorn Creek oil unit to develop a depositional model for the Carter sandstone reservoir. The second part of the report describes the detrital and diagenetic character of Carter sandstone utilizing data from petrographic and scanning electron microscopes and the electron microprobe. The third part synthesizes porosity and pore-throat-size-distribution data determined by high-pressure mercury porosimetry and commercial core analyses with results of the sedimentologic and petrographic studies. The final section of the report discusses reservoir heterogeneity within the context of the five-fold classification of Moore and Kugler (1990).« less

Improved reservoir characterisation using fuzzy logic platform: an integrated petrophysical, seismic structural and poststack inversion study

NASA Astrophysics Data System (ADS)

Jafri, Muhammad Kamran; Lashin, Aref; Ibrahim, El-Khedr Hassan; Hassanein, Kamal A.; Al Arifi, Nassir; Naeem, Muhammad

2017-06-01

There is a tendency for applying different integrated geophysical approaches for better hydrocarbon reservoir characterisation and interpretation. In this study, petrophysical properties, seismic structural and poststack seismic inversion results are integrated using the fuzzy logic AND operator to characterise the Tensleep Sandstone Formation (TSF) at Powder River Basin (PRB), Wyoming, USA. TSF is deposited in a coastal plain setting during the Pennsylvanian era, and contains cross-bedded sandstone of Aeolian origin as a major lithology with alternative sabkha dolomite/carbonates. Wireline logging datasets from 17 wells are used for the detailed petrophysical evaluation. Three units of the TSF (A-sandstone, B-dolomite and B-sandstone) are targeted and their major rock properties estimated (i.e. shale/clay volume, Vsh; porosity, φEff permeability, K; fluid saturations, Sw and SH; and bulk volume water, BVW). The B-sandstone zone, with its petrophysical properties of 5-20% effective porosity, 0.10-250 mD permeability and hydrocarbon potential up to 72%, is considered the best reservoir zone among the three studied units. Distributions of the most important petrophysical parameters of the B-sandstone reservoir (Vsh, φEff, K, Sw) are generated as GIS thematic layers. The two-dimensional (2D) and three-dimensional (3D) seismic structural interpretations revealed that the hydrocarbons are entrapped in an anticlinal structure bounded with fault closures at the west of the study area. Poststack acoustic impedance (PSAI) inversion is performed on 3D seismic data to extract the inverted acoustic impedance (AI) cube. Two attribute slices (inverted AI and seismic amplitude) were extracted at the top of the B-sandstone unit as GIS thematic layers. The reservoir properties and inverted seismic attributes were then integrated using fuzzy AND operator. Finally, a fuzzy reservoir quality map was produced, and a prospective reservoir area with best reservoir characteristics is proposed for future exploration. The current study showed that integration of petrophysical, seismic structural and poststack inversion under a fuzzy logic platform can be used as an effective tool for interpreting multiple reservoir zones.

Evidence for preferential flow through sandstone aquifers in Southern Wisconsin

USGS Publications Warehouse

Swanson, S.K.; Bahr, J.M.; Bradbury, K.R.; Anderson, K.M.

2006-01-01

Sandstones often escape extensive hydrogeologic characterization due to their high primary porosity and perceived homogeneity of permeability. This study provides evidence for laterally extensive, high permeability zones in the Tunnel City Group, an undeformed, Cambrian-aged sandstone unit that exists in the subsurface throughout much of central and southern Wisconsin, USA. Several discrete high-permeability zones were identified in boreholes using flow logging and slug tests, and the interconnectedness of the features was tested using a site-specific numerical model for springs in the region. Explicit incorporation of a high-permeability layer leads to improvements in the flux calibration over simulations that lack the features, thus supporting the hydraulic continuity of high-permeability zones in the sandstone aquifer over tens of kilometers. The results suggest that stratigraphically controlled heterogeneities like contrasts in lithology or bedding-plane fractures, which have been shown to strongly influence the flow of groundwater in more heterogeneous sedimentary rocks, may also deserve close examination in sandstone aquifers. ?? 2005 Elsevier B.V. All rights reserved.

Sedimentology and Reservoir Characteristics of Early Cretaceous Fluvio-Deltaic and Lacustrine Deposits, Upper Abu Gabra Formation, Sufyan Sub-basin, Muglad Rift Basin, Sudan

NASA Astrophysics Data System (ADS)

Yassin, Mohamed; Abdullatif, Osman; Hariri, Mustafa

2017-04-01

Sufyan Sub-basin is an East-West trending Sub-basin located in the northwestern part of the Muglad Basin (Sudan), in the eastern extension of the West and Central Africa Rift System (WCARS). The Early Cretaceous Abu Gabra Formation considered as the main source rock in the Muglad Basin. In Sufyan Sub-basin the Early Cretaceous Upper Abu Gabra Formation is the main oil-producing reservoir. It is dominated by sandstone and shales deposited in fluvio-deltaic and lacustrine environment during the first rift cycle in the basin. Depositional and post-depositional processes highly influenced the reservoir quality and architecture. This study investigates different scales of reservoir heterogeneities from macro to micro scale. Subsurface facies analysis was analyzed based on the description of six conventional cores from two wells. Approaches include well log analysis, thin sections and scanning electron microscope (SEM) investigations, grain-size, and X-ray diffraction (XRD) analysis of the Abu Gabra sandstone. The cores and well logs analyses revealed six lithofacies representing fluvio-deltaic and lacustrine depositional environment. The sandstone is medium to coarse-grained, poorly to moderately sorted and sub-angular to subrounded, Sub-feldspathic arenite to quartz arenite. On macro-scale, reservoir quality varies within Abu Gabra reservoir where it shows progressive coarsening upward tendencies with different degrees of connectivity. The upper part of the reservoir showed well connected and amalgamated sandstone bodies, the middle to lower parts, however, have moderate to low sandstone bodies' connectivity and amalgamation. On micro-scale, sandstone reservoir quality is directly affected by textures and diagenesis.The XRD and SEM analyses show that kaolinite and chlorite clay are the common clay minerals in the studied samples. Clay matrix and quartz overgrowth have significantly reduced the reservoir porosity and permeability, while the dissolution of feldspars during the diagenetic process increase it. The estimated porosity in Abu Gabra Formation ranges from 10 to 21% with an average of 15%; while permeability varies from 200 to 400 md. The results of this study might contribute to better understanding of reservoir heterogeneities and help in reservoir quality prediction, therefore enhancing the hydrocarbon productivity.

Assessment of potential shale oil and tight sandstone gas resources of the Assam, Bombay, Cauvery, and Krishna-Godavari Provinces, India, 2013

USGS Publications Warehouse

Klett, Timothy R.; Schenk, Christopher J.; Wandrey, Craig J.; Brownfield, Michael E.; Charpentier, Ronald R.; Tennyson, Marilyn E.; Gautier, Donald L.

2014-01-01

Using a well performance-based geologic assessment methodology, the U.S. Geological Survey estimated a technically recoverable mean volume of 62 million barrels of oil in shale oil reservoirs, and more than 3,700 billion cubic feet of gas in tight sandstone gas reservoirs in the Bombay and Krishna-Godavari Provinces of India. The term “provinces” refer to geologically defined units assessed by the USGS for the purposes of this report and carries no political or diplomatic connotation. Shale oil and tight sandstone gas reservoirs were evaluated in the Assam and Cauvery Provinces, but these reservoirs were not quantitatively assessed.

Shallow, low-permeability reservoirs of northern Great Plains - assessment of their natural gas resources.

USGS Publications Warehouse

Rice, D.D.; Shurr, G.W.

1980-01-01

Major resources of natural gas are entrapped in low-permeability, low-pressure reservoirs at depths less than 1200m in the N.Great Plains. This shallow gas is the product of the immature stage of hydrocarbon generation and is referred to as biogenic gas. Prospective low-permeability, gas-bearing reservoirs range in age from late Early to Late Cretaceous. The following facies were identified and mapped: nonmarine rocks, coastal sandstones, shelf sandstones, siltstones, shales, and chalks. The most promising low-permeability reservoirs are developed in the shelf sandstone, siltstone, and chalk facies. Reservoirs within these facies are particularly attractive because they are enveloped by thick sequences of shale which serve as both a source and a seal for the gas.-from Author

Comparison of transgressive and regressive clastic reservoirs, late Albian Viking Formation, Alberta basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Reinson, G.E.

1996-06-01

Detailed stratigraphic analysis of hydrocarbon reservoirs from the Basal Colorado upwards through the Viking/Bow Island and Cardium formations indicates that the distributional trends, overall size and geometry, internal heterogeneity, and hydrocarbon productivity of the sand bodies are related directly to a transgressive-regressive (T-R) sequence stratigraphic model. The Viking Formation (equivalent to the Muddy Sandstone of Wyoming) contains examples of both transgressive and regressive reservoirs. Viking reservoirs can be divided into progradational shoreface bars associated with the regressive systems tract, and bar/sheet sands and estuary/channel deposits associated with the transgressive systems tract. Shoreface bars, usually consisting of fine- to medium-grained sandstones,more » are tens of kilometers long, kilometers in width, and in the order of five to ten meters thick. Transgressive bar and sheet sandstones range from coarse-grained to conglomeratic, and occur in deposits that are tens of kilometers long, several kilometers wide, and from less than one to four meters in thickness. Estuary and valley-fill reservoir sandstones vary from fine-grained to conglomeratic, occur as isolated bodies that have channel-like geometries, and are usually greater than 10 meters thick. From an exploration viewpoint the most prospective reservoir trends in the Viking Formation are those associated with transgressive systems tracts. In particular, bounding discontinuities between T-R systems tracts are the principal sites of the most productive hydrocarbon-bearing sandstones.« less

Fluvial sandstone reservoirs of Travis Peak (Hosston) Formation, east Texas basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Tye, R.S.

1989-03-01

Gas production (7.2 billion ft/sup 3/) from low-permeability sandstones in the Travis Peak Formation, North Appleby field, Nacogdoches County, Texas, is enhanced through massive hydraulic fracturing of stacked sandstones that occur at depths between 8000 and 10,000 ft. stratigraphic reservoirs were formed in multilateral tabular sandstones owing to impermeable mudstone interbeds that encase blocky to upward-fining sandstones. Pervasive quartz cement in the sandstones decreases porosity and permeability and augments the reservoir seal. Subsurface data indicate that much of this 2000-ft thick section represents aggradation of alluvial-valley deposits. Multiple channel belts form a network of overlapping, broad, tabular sandstones having thickness-to-widthmore » ratios of 1:850 (8-44 ft thick; widths exceed 4-5 mi). Six to eight channel belts, each containing 80-90% medium to fine-grained sandstone, can occupy a 200-ft thick interval. In a vertical sequence through one channel belt sandstone, basal planar cross-bedding grades upward into thinly interbedded sets of planar cross-beds and ripple cross-lamination. Clay-clast conglomerates line scoured channel bases. Adjacent to the channels, interbedded mudstones accumulated in well-drained swamps and lakes. Poorly sorted sandstones represent overbank deposition (crevasse splays and lacustrine deltas). During Travis Peak deposition, fluvial styles evolved from dominantly braided systems near the base of the formation to more mud-rich, meandering systems at the top.« less

Cambrian Sauk transgression in the Grand Canyon region redefined by detrital zircons

NASA Astrophysics Data System (ADS)

Karlstrom, Karl; Hagadorn, James; Gehrels, George; Matthews, William; Schmitz, Mark; Madronich, Lauren; Mulder, Jacob; Pecha, Mark; Giesler, Dominique; Crossey, Laura

2018-06-01

The Sauk transgression was one of the most dramatic global marine transgressions in Earth history. It is recorded by deposition of predominantly Cambrian non-marine to shallow marine sheet sandstones unconformably above basement rocks far into the interiors of many continents. Here we use dating of detrital zircons sampled from above and below the Great Unconformity in the Grand Canyon region to bracket the timing of the Sauk transgression at this classic location. We find that the Sixtymile Formation, long considered a Precambrian unit beneath the Great Unconformity, has maximum depositional ages that get younger up-section from 527 to 509 million years old. The unit contains angular unconformities and soft-sediment deformation that record a previously unknown period of intracratonic faulting and epeirogeny spanning four Cambrian stages. The overlying Tapeats Sandstone has youngest detrital zircon ages of 505 to 501 million years old. When linked to calibrated trilobite zone ages of greater than 500 million years old, these age constraints show that the marine transgression across a greater than 300-km-wide cratonic region took place during an interval 505 to 500 million years ago—more recently and more rapidly than previously thought. We redefine this onlap as the main Sauk transgression in the region. Mechanisms for this rapid flooding of the continent include thermal subsidence following the final breakup of Rodinia, combined with abrupt global eustatic changes driven by climate and/or mantle buoyancy modifications.

Geomechanical Framework for Secure CO 2 Storage in Fractured Reservoirs and Caprocks for Sedimentary Basins in theMidwest United States

DOE Office of Scientific and Technical Information (OSTI.GOV)

Sminchak, Joel

This report presents final technical results for the project Geomechanical Framework for Secure CO 2 Storage in Fractured Reservoirs and Caprocks for Sedimentary Basins in the Midwest United States (DE-FE0023330). The project was a three-year effort consisting of seven technical tasks focused on defining geomechanical factors for CO 2 storage applications in deep saline rock formations in Ohio and the Midwest United States, because geomechancial issues have been identified as a significant risk factor for large-scale CO 2 storage applications. A basin-scale stress-strain analysis was completed to describe the geomechanical setting for rock formations of Ordovician-Cambrian age in Ohio andmore » adjacent areas of the Midwest United States in relation to geologic CO 2 storage applications. The tectonic setting, stress orientation-magnitude, and geomechanical and petrophysical parameters for CO 2 storage zones and caprocks in the region were cataloged. Ten geophysical image logs were analyzed for natural fractures, borehole breakouts, and drilling-induced fractures. The logs indicated mostly less than 10 fractures per 100 vertical feet in the borehole, with mostly N65E principal stress orientation through the section. Geophysical image logs and other logs were obtained for three wells located near the sites where specific models were developed for geomechanical simulations: Arches site in Boone County, Kentucky; Northern Appalachian Basin site in Chautauqua County, New York; and E-Central Appalachian Basin site in Tuscarawas County, Ohio. For these three wells, 9,700 feet of image logs were processed and interpreted to provide a systematic review of the distribution within each well of natural fractures, wellbore breakouts, faults, and drilling induced fractures. There were many borehole breakouts and drilling-induced tensile fractures but few natural fractures. Concentrated fractures were present at the Rome-basal sandstone and basal sandstone-Precambrian contacts at the Arches and East-Central Appalachian Basin sites. Geophysical logs were utilized to develop local-scale geologic models by determining geomechanical and petrophysical parameters within the geologic formations. These data were ported to coupled fluid-flow and reservoir geomechanics multi-phase CO 2 injection simulations. The models were developed to emphasize the geomechanical layers within the CO 2 storage zones and caprocks. A series of simulations were completed for each site to evaluate whether commercial-scale CO 2 could be safely injected into each site, given site-specific geologic and geomechanical controls. This involved analyzing the simulation results for the integrity of the caprock, intermediate, and reservoir zones, as well quantifying the areal uplift at the surface. Simulation results were also examined to ensure that the stress-stress perturbations were isolated within the subsurface, and that there was only limited upward migration of the CO 2. Simulations showed capacity to inject more than 10 million metric tons of CO 2 in a single well at the Arches and East Central Appalachian Basin sites without excessive geomechanical risks. Low-permeability rock layers at the Northern Appalachian Basin study area well resulted in very low CO 2 injection capacity. Fracture models developed for the sites suggests that the sites have sparse fracture network in the deeper Cambrian rocks. However, there were indicators in image logs of a moderate fracture matrix in the Rose Run Sandstone at the Northern Appalachian Basin site. Dual permeability fracture matrix simulations suggest the much higher injection rates may be feasible in the fractured interval. Guidance was developed for geomechanical site characterization in the areas of geophysical logging, rock core testing, well testing, and site monitoring. The guidance demonstrates that there is a suitable array of options for addressing geomechanical issues at CO 2 storage sites. Finally, a review of Marcellus and Utica-Point Pleasant shale gas wells and CO 2 storage intervals indicates that these items are vertically separated, except for the Oriskany sandstone and Marcellus wells in southwest Pennsylvania and northern West Virginia. Together, project results present a more realistic portrayal of geomechanical risk factors related to CO 2 storage for existing and future coal-fired power plants in Ohio.« less

Reservoir characterization of the Mt. Simon Sandstone, Illinois Basin, USA

USGS Publications Warehouse

Frailey, S.M.; Damico, J.; Leetaru, H.E.

2011-01-01

The integration of open hole well log analyses, core analyses and pressure transient analyses was used for reservoir characterization of the Mt. Simon sandstone. Characterization of the injection interval provides the basis for a geologic model to support the baseline MVA model, specify pressure design requirements of surface equipment, develop completion strategies, estimate injection rates, and project the CO2 plume distribution.The Cambrian-age Mt. Simon Sandstone overlies the Precambrian granite basement of the Illinois Basin. The Mt. Simon is relatively thick formation exceeding 800 meters in some areas of the Illinois Basin. In the deeper part of the basin where sequestration is likely to occur at depths exceeding 1000 m, horizontal core permeability ranges from less than 1 ?? 10-12 cm 2 to greater than 1 ?? 10-8 cm2. Well log and core porosity can be up to 30% in the basal Mt. Simon reservoir. For modeling purposes, reservoir characterization includes absolute horizontal and vertical permeability, effective porosity, net and gross thickness, and depth. For horizontal permeability, log porosity was correlated with core. The core porosity-permeability correlation was improved by using grain size as an indication of pore throat size. After numerous attempts to identify an appropriate log signature, the calculated cementation exponent from Archie's porosity and resistivity relationships was used to identify which porosity-permeability correlation to apply and a permeability log was made. Due to the relatively large thickness of the Mt. Simon, vertical permeability is an important attribute to understand the distribution of CO2 when the injection interval is in the lower part of the unit. Only core analyses and specifically designed pressure transient tests can yield vertical permeability. Many reservoir flow models show that 500-800 m from the injection well most of the CO2 migrates upward depending on the magnitude of the vertical permeability and CO2 injection rate (CO2 velocity). Assigning a specific value of vertical permeability to model cells is dependent on the vertical height of the model cell. Measured vertical permeability on core is scale dependent, such that lower vertical permeability is expected over longer core lengths compared to smaller lengths. Consequently, a series of vertical permeability tests were conducted on whole core varying in lengths of samples from 7 cm to 30 cm that showed vertical perm could change by an order of magnitude over a 30 cm height. For one well, the results from a series of pressure transient tests over a perforated interval much smaller than the gross thickness (<2%) confirmed the core-log based geologic model for vertical and horizontal permeability. A partial penetration model was used to estimate the horizontal and vertical permeability over a portion of the modeled area using series and parallel flow averaging techniques. ?? 2011 Published by Elsevier Ltd.

Hydrocarbon Potential in Sandstone Reservoir Isolated inside Low Permeability Shale Rock (Case Study: Beruk Field, Central Sumatra Basin)

NASA Astrophysics Data System (ADS)

Diria, Shidqi A.; Musu, Junita T.; Hasan, Meutia F.; Permono, Widyo; Anwari, Jakson; Purba, Humbang; Rahmi, Shafa; Sadjati, Ory; Sopandi, Iyep; Ruzi, Fadli

2018-03-01

Upper Red Bed, Menggala Formation, Bangko Formation, Bekasap Formation and Duri Formationare considered as the major reservoirs in Central Sumatra Basin (CSB). However, Telisa Formation which is well-known as seal within CSB also has potential as reservoir rock. Field study discovered that lenses and layers which has low to high permeability sandstone enclosed inside low permeability shale of Telisa Formation. This matter is very distinctive and giving a new perspective and information related to the invention of hydrocarbon potential in reservoir sandstone that isolated inside low permeability shale. This study has been conducted by integrating seismic data, well logs, and petrophysical data throughly. Facies and static model are constructed to estimate hydrocarbon potential resource. Facies model shows that Telisa Formation was deposited in deltaic system while the potential reservoir was deposited in distributary mouth bar sandstone but would be discontinued bedding among shale mud-flat. Besides, well log data shows crossover between RHOB and NPHI, indicated that distributary mouth bar sandstone is potentially saturated by hydrocarbon. Target area has permeability ranging from 0.01-1000 mD, whereas porosity varies from 1-30% and water saturation varies from 30-70%. The hydrocarbon resource calculation approximates 36.723 MSTB.

Geological Carbon Sequestration Storage Resource Estimates for the Ordovician St. Peter Sandstone, Illinois and Michigan Basins, USA

DOE Office of Scientific and Technical Information (OSTI.GOV)

Barnes, David; Ellett, Kevin; Leetaru, Hannes

The Cambro-Ordovician strata of the Midwest of the United States is a primary target for potential geological storage of CO2 in deep saline formations. The objective of this project is to develop a comprehensive evaluation of the Cambro-Ordovician strata in the Illinois and Michigan Basins above the basal Mount Simon Sandstone since the Mount Simon is the subject of other investigations including a demonstration-scale injection at the Illinois Basin Decatur Project. The primary reservoir targets investigated in this study are the middle Ordovician St Peter Sandstone and the late Cambrian to early Ordovician Knox Group carbonates. The topic of thismore » report is a regional-scale evaluation of the geologic storage resource potential of the St Peter Sandstone in both the Illinois and Michigan Basins. Multiple deterministic-based approaches were used in conjunction with the probabilistic-based storage efficiency factors published in the DOE methodology to estimate the carbon storage resource of the formation. Extensive data sets of core analyses and wireline logs were compiled to develop the necessary inputs for volumetric calculations. Results demonstrate how the range in uncertainty of storage resource estimates varies as a function of data availability and quality, and the underlying assumptions used in the different approaches. In the simplest approach, storage resource estimates were calculated from mapping the gross thickness of the formation and applying a single estimate of the effective mean porosity of the formation. Results from this approach led to storage resource estimates ranging from 3.3 to 35.1 Gt in the Michigan Basin, and 1.0 to 11.0 Gt in the Illinois Basin at the P10 and P90 probability level, respectively. The second approach involved consideration of the diagenetic history of the formation throughout the two basins and used depth-dependent functions of porosity to derive a more realistic spatially variable model of porosity rather than applying a single estimate of porosity throughout the entire potential reservoir domains. The second approach resulted in storage resource estimates of 3.0 to 31.6 Gt in the Michigan Basin, and 0.6 to 6.1 Gt in the Illinois Basin. The third approach attempted to account for the local-scale variability in reservoir quality as a function of both porosity and permeability by using core and log analyses to calculate explicitly the net effective porosity at multiple well locations, and interpolate those results throughout the two basins. This approach resulted in storage resource estimates of 10.7 to 34.7 Gt in the Michigan Basin, and 11.2 to 36.4 Gt in the Illinois Basin. A final approach used advanced reservoir characterization as the most sophisticated means to estimating storage resource by defining reservoir properties for multiple facies within the St Peter formation. This approach was limited to the Michigan Basin since the Illinois Basin data set did not have the requisite level of data quality and sampling density to support such an analysis. Results from this approach led to storage resource estimates of 15.4 Gt to 50.1 Gt for the Michigan Basin. The observed variability in results from the four different approaches is evaluated in the context of data and methodological constraints, leading to the conclusion that the storage resource estimates from the first two approaches may be conservative, whereas the net porosity based approaches may over-estimate the resource.« less

Architecture and sedimentology of turbidite reservoirs from Miocene Moco T and Webster zones, Midway-Sunset field, California

DOE Office of Scientific and Technical Information (OSTI.GOV)

Link, M.H.; Hall, B.R.

1989-03-01

Thirty-five turbidite sandstone bodies from the Moco T and Webster reservoir zones were delineated for enhanced oil recovery projects in Mobil's MOCO FEE property, south Midway-Sunset field. The recognition of these sand bodies is based on mappable geometries determined from wireline log correlations, log character, core facies, reservoir characteristics, and comparison to nearby age-equivalent outcrops. These turbidite sands are composed of unconsolidated arkosic late Miocene sandstones (Stevens equivalent, Monterey Formation). They were deposited normal to paleoslope and trend southwest-northeast in an intraslope basin. Reservoir quality in the sandstone is very good, with average porosities of 33% and permeabilities of 1more » darcy.« less

Evaluation of stratigraphic relations of sandstone-producing reservoirs in upper Council Grove and Chase groups (Permian) in north-central Oklahoma

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chaplin, J.R.

1989-08-01

Poor well control and the absence of surface stratigraphic control made previous interpretations of the stratigraphic relations of sandstone-producing reservoirs tenuous. Recent extensive analyses of surface outcrops and well and core data support the contention that the major sandstone-producing reservoirs can be physically correlated with formations in the outcrop section. Sandstone bodies within the upper Council Grove Group include Neva sand and Blackwell sand (Neva Limestone), Hotson-Kisner sand (Eskridge Shale), and the Whitney-Hodges sand. The Whitney-Hodges sand correlates, in part, with the Speiser Shale (Garrison Formation) of the outcrop section. However, previous usage suggested tentative correlations with sandstone bodies stratigraphicallymore » lower in the section. These sands were probably deposited in channels that were, in part, fluvial, tidal, or estuarine. Production from the Chase Group occurs locally within channelform sandstone bodies referred to as the Hoy-Matfield sand. These sands appear to be equivalent, occupying essentially the position of the Kinney Limestone Member (Matfield Shale) of the outcrop section. Detailed core-hole data at and in the vicinity of Kaw Dam, southeastern Kay County, and outcrops along the shoreline of Kaw Lake at Kaw City, Kay County, clearly demonstrate the facies distribution of the Hoy sand. Core-hole data has also delineated additional potential sandstone reservoirs within and near or at the top of the Fort Riley Limestone Member (Barneston Limestone). The Wolfe sand, a producing sandstone locally, occupies a stratigraphic position within the Doyle Shale.« less

EBSD characterization of pre-Cambrian deformations in conglomerate pebbles (Sierra de la Demanda, Northern Spain)

NASA Astrophysics Data System (ADS)

Puelles, Pablo; Ábalos, Benito; Fernández-Armas, Sergio

2010-05-01

Pre-Cambrian and unconformable earliest Cambrian rocks from the Sierra de la Demanda (N Spain) exhibit field and microstructural relationships that attest to orogenic events recorded by concealed basement rocks. Neoproterozoic foliated slates ("Anguiano Schists") crop out under up to 300 m thick, unfoliated quartz-rich conglomerates ("Anguiano Conglomerates") and quartzites which are stratigraphically ca. 600 m below the oldest, paleontologically dated, pre-trilobitic Cambrian layers (likely older than 520 Ma). The Anguiano Conglomerates contain mm to cm grainsized well-rounded pebbles of various types including monocrystalline quartz, detrital zircon and tourmaline-bearing sandstones, black cherts and metamorphic poly-crystalline quartz aggregates. The undeformed matrix is made of much smaller (diagenetically overgrown) monocrystaline quartz grains and minor amounts of accesory zircon, tourmaline and mica. Black chert pebbles exhibit microstructural evidence of brittle deformation (microfaults and thin veins of syntaxial fibrous quartz). These and the fine-grained sandstone pebbles can also exhibit ductile deformations (microfolds with thickened hinges and axial planar continuous foliations), too. Polycrystalline quartz pebbles exhibit a variety of microstructures that resulted from syn-metamorphic ductile deformations. These are recognisable under the petrographic microscope and include continuous foliations, quartz shape fabrics, various types of subgrain or recrystallized new grain microtextures, and lattice preferred orientations (LPOs). Conventional characterization of quartz fabrics (after oriented structural sections) is challenged in conglomerate pebble thin sections by the difficulty of unraveling in them the complete structural reference framework provided by foliation (whose trace can be unraveled) and lineation orientation (which cannot be directly identified). Quartz in various metamorphic polycrystalline pebbles was studied with the Electron Back-Scatter Diffraction (EBSD) technique. The identification of quartz c-axis point maxima or girdles and their geometrical relationships with respect to -axis arrangements and pebble foliation traces enabled us to identify the operation of basal and prism- and occasionally prism-[c] intracrystalline slip systems. This points to upper-greenschists and amphibolite facies syn-metamorphic deformations. By contrast, black chert and sandstone pebbles and matrix quartz aggregates lack any LPO. The source area of the conglomerates was likely a pre-Cambrian basement that contained penetratively deformed low- to medium-grade metamorphic rocks. Radiometric dating of this metamorphism has not been accomplished so far though it is known that inherited Precambrian sources in the Iberian Peninsula relate notably to Neoproterozoic (Pan-African and Cadomian) orogens, and to a lesser extent to Paleoproterozoic (1.8-2.1 Ga) or Neoarchean (2.4-2.8 Ga) ones. Neoproterozoic (Cadomian) metamorphism of this grade has only been recognized in SW Iberia. If the fabrics here studied were Cadomian, they might be related to the arc-related igneous suites that have been detected or inferred in other realms of the northern Iberian Massif.

Upper Cretaceous Shannon Sandstone reservoirs, Powder River Basin, Wyoming: evidence for organic acid diagenesis?

USGS Publications Warehouse

Hansley, P.L.; Nuccio, V.F.

1992-01-01

Comparison of the petrology of shallow and deep oil reservoirs in the Upper Cretaceous Shannon Sandstone Beds of the Steele Member of the Cody Shale strongly suggests that organic acids have had a more significant impact on the diagenetic alteration of aluminosilicate grains and carbonate cements in the deep reservoirs than in the shallow reservoirs. Vitrinite reflectance and Rock-Eval measurements, as well as the time-temperature index and kinetic modeling, indicate that deep reservoirs have been subjected to maximum temperatures of approximately 110-120??C, whereas shallow reservoirs have reached only 75??C. -from Authors

Geological fieldwork in the Libyan Sahara: A multidisciplinary approach

NASA Astrophysics Data System (ADS)

Meinhold, Guido; Whitham, Andrew; Howard, James P.; Morton, Andrew; Abutarruma, Yousef; Bergig, Khaled; Elgadry, Mohamed; Le Heron, Daniel P.; Paris, Florentin; Thusu, Bindra

2010-05-01

Libya is one of the most hydrocarbon-rich countries in the world. Its large oil and gas reserves make it attractive to international oil and gas companies, which provide the impetus for field-based research in the Libyan Sahara. North Africa is made up of several enormous intracratonic basins, two of which are found in southern Libya: the Murzuq Basin, in the southwest, and the Kufra Basin, in the southeast, separated by the Tibesti Massif. Both basins are filled with Palaeozoic and Mesozoic clastic sedimentary rocks reaching up to 5 km in thickness. These basins developed from the Cambrian onwards following an earlier period of orogenesis (the Panafrican Orogeny) in the Neoproterozoic. Precambrian metasediments and granitoids are unconformably overlain by Cambrian and Ordovician conglomerates and sandstones. They show a transitional environment from continental to shallow marine. Skolithos-bearing sandstone is common in Ordovician strata. By the Late Ordovician, ice masses had developed across West Gondwana. Upon melting of the ice sheets in the latest Hirnantian, large volumes of melt water and sediment were released that were transported to the periphery of Gondwana. In Libya, these sediments are predominantly highly mature sandstones, which, in many places, are excellent hydrocarbon reservoirs. Polished and striated surfaces in these sandstones clearly point to their glaciogenic origin. Following Late Ordovician deglaciation, black shale deposition occurred in the Silurian. Some of the shales are characterised by high values of total organic carbon (TOC). These shales are commonly referred to as ‘hot shales' due to their associated high uranium content, and are the major source rock for Early Palaeozoic-sourced hydrocarbons in North Africa. Late Ordovician glaciogenic sediments and the Early Silurian ‘hot shales' are therefore the main focus of geological research in the Libyan Sahara. Fluvial conglomerates and sandstones of Devonian age unconformably overlie these strata. Marine intervals occur in the Late Devonian, and the Carboniferous is characterised by shallow marine clastic sediments with carbonate horizons. Permian rocks are only known from subsurface drill cores and comprise continental and deltaic facies. The centre of the Murzuq Basin has been relatively well investigated by drilling and seismic profiles. The basin margins, however, lack detailed geological investigation. In comparison, the Kufra Basin is underexplored with few boreholes drilled. Our studies have focused on the eastern and northern margins of the Murzuq Basin and the northern, eastern and western margins of the Kufra Basin. The main objective of fieldwork has been to characterise the Infracambrian-Lower Palaeozoic stratigraphy, deduce the structural evolution of each study area, and to collect samples for follow-up analyses including provenance studies and biostratigraphy. In addition to outcrop-based fieldwork shallow boreholes up to 70 m depth were successfully drilled in the Early Silurian shales. The unweathered samples retrieved from two of the boreholes have been used for biostratigraphical and whole-rock geochemical investigations. The provenance study of the sandstone succession with conventional heavy mineral analysis together with U-Pb zircon dating provides, for the first time, an understanding of the ancient source areas. Because most of the Early Palaeozoic succession in southern Libya is barren of fossils, heavy mineral chemostratigraphy is moreover used as a correlation test on surface outcrops in the Kufra and Murzuq basins.

Sandstone-filled normal faults: A case study from central California

NASA Astrophysics Data System (ADS)

Palladino, Giuseppe; Alsop, G. Ian; Grippa, Antonio; Zvirtes, Gustavo; Phillip, Ruy Paulo; Hurst, Andrew

2018-05-01

Despite the potential of sandstone-filled normal faults to significantly influence fluid transmissivity within reservoirs and the shallow crust, they have to date been largely overlooked. Fluidized sand, forcefully intruded along normal fault zones, markedly enhances the transmissivity of faults and, in general, the connectivity between otherwise unconnected reservoirs. Here, we provide a detailed outcrop description and interpretation of sandstone-filled normal faults from different stratigraphic units in central California. Such faults commonly show limited fault throw, cm to dm wide apertures, poorly-developed fault zones and full or partial sand infill. Based on these features and inferences regarding their origin, we propose a general classification that defines two main types of sandstone-filled normal faults. Type 1 form as a consequence of the hydraulic failure of the host strata above a poorly-consolidated sandstone following a significant, rapid increase of pore fluid over-pressure. Type 2 sandstone-filled normal faults form as a result of regional tectonic deformation. These structures may play a significant role in the connectivity of siliciclastic reservoirs, and may therefore be crucial not just for investigation of basin evolution but also in hydrocarbon exploration.

The Point Lookout Sandstone: a tale of two cores, or petrology, diagenesis, and reservoir properties of Point Lookout Sandstone, Southern Ute Indian Reservation, San Juan Basin, Colorado

USGS Publications Warehouse

Keighin, C.W.; Zech, R.S.; Dunbar, R.W.

1993-01-01

The Point Lookout sandstones are quartz-rich, fine to very-fine grained, and contain moderately variable quantities of potassium feldspar (2 to 20 modal percent) and lithic fragments (9 to 20 modal percent). Locally, sandstone is tightly cemented by carbonate cement; clays are not important as cementing agents, although they significantly reduce permeability of some samples. Pores are small; many are intergranular micropores between crystals of authigenic clay. Depositional environments are highly variable and range from lower shoreface to coastal plain and include minor deltaic environments. The best reservoir characteristics are generally in the upper shoreface sandstones. -from Authors

The interplay of fractures and sedimentary architecture: Natural gas from reservoirs in the Molina sandstones, Piceance Basin, Colorado

DOE Office of Scientific and Technical Information (OSTI.GOV)

Lorenz, J.C.

1997-03-01

The Molina Member of the Wasatch Formation produces natural gas from several fields along the Colorado River in the Piceance Basin, northwestern Colorado. The Molina Member is a distinctive sandstone that was deposited in a unique fluvial environment of shallow-water floods. This is recorded by the dominance of plane-parallel bedding in many of the sandstones. The Molina sandstones crop out on the western edge of the basin, and have been projected into the subsurface and across the basin to correlate with thinner sandy units of the Wasatch Formation at the eastern side of the basin. Detailed study, however, has shownmore » that the sedimentary characteristics of the type-section Molina sandstones are incompatible with a model in which the eastern sandstones are its distal facies equivalent. Rather, the eastern sandstones represent separate and unrelated sedimentary systems that prograded into the basin from nearby source-area highlands. Therefore, only the subsurface {open_quotes}Molina{close_quotes} reservoirs that are in close proximity to the western edge of the basin are continuous with the type-section sandstones. Reservoirs in the Grand Valley and Rulison gas fields were deposited in separate fluvial systems. These sandstones contain more typical fluvial sedimentary structures such as crossbeds and lateral accretion surfaces. Natural fractures play an important role in enhancing the conductivity and permeability of the Molina and related sandstones of the Wasatch Formation.« less

Geologic Model for Oil and Gas Assessment of the Kemik-Thomson Play, Central North Slope, Alaska

USGS Publications Warehouse

Schenk, Christopher J.; Houseknecht, David W.

2008-01-01

A geologic model was developed to assess undiscovered oil and gas resources in the Kemik-Thomson Play of the Central North Slope, Alaska. In this model, regional erosion during the Early Cretaceous produced an incised valley system on the flanks and crest of the Mikkelsen High and formed the Lower Cretaceous unconformity. Locally derived, coarse-grained siliciclastic and carbonate detritus from eroded Franklinian-age basement rocks, Carboniferous Kekiktuk Conglomerate (of the Endicott Group), Lisburne Group, and Permian-Triassic Sadlerochit Group may have accumulated in the incised valleys during lowstand and transgression, forming potential reservoirs in the Lower Cretaceous Kemik Sandstone and Thomson sandstone (informal term). Continued transgression resulted in the deposition of the mudstones of the over-lying Cretaceous pebble shale unit and Hue Shale, which form top seals to the potential reservoirs. Petroleum from thermally mature facies of the Triassic Shublik Formation, Jurassic Kingak Shale, Hue Shale (and pebble shale unit), and the Cretaceous-Tertiary Canning Formation might have charged Thomson and Kemik sandstone reservoirs in this play during the Tertiary. The success of this play depends largely upon the presence of reservoir-quality units in the Kemik Sandstone and Thomson sandstone.

Sedimentologic and reservoir characteristics under the tectono-sequence stratigraphic framework: A case study from the Early Cretaceous, upper Abu Gabra sandstones, Sufyan Sub-basin, Muglad Basin, Sudan

NASA Astrophysics Data System (ADS)

Yassin, Mohamed A.; Hariri, Mustafa M.; Abdullatif, Osman M.; Makkawi, M.; Bertotti, G.; Kaminski, Michael A.

2018-06-01

The Sufyan Sub-basin is an east-west trending Sub-basin located in the northwestern part of the Muglad Basin, in the eastern extension of the West and Central Africa Rift System (WCARS). Exploration results showed the occurrence of accumulations of hydrocarbon. The source rock for these hydrocarbons is believed to be the lacustrine shale of the Abu Gabra Formation. Fluvio-deltaic sandstones within the Abu Gabra Formation represent the primary reservoir. Depositional and post-depositional processes influence reservoir heterogeneity, quality, and architecture. This study investigates different scales of reservoir heterogeneities from basin to micro scale and discusses the impact of depositional facies and diagenesis on reservoir quality. Approaches include seismic interpretation, seismic attribute analysis, well log analysis, thin sections and scanning electron microscope (SEM) investigations, and X-ray diffraction (XRD) analysis of the Abu Gabra Formation. Sedimentologic interpretation in this study was performed based on core cuttings, well logs, and seismic data. Subsurface facies analysis was analyzed based on the description of six conventional cores from two wells. Seven lithofacies in Abu Gabra Formation are identified. Four types of depositional systems are identified in the studied succession. These are braided delta, fan delta, sublacustrine fan, and lacustrine systems. The sandstone is medium to coarse-grained, poorly to moderately sorted and sub-angular to sub-rounded, sub-feldspathic arenite to quartz arenite. At the basin scale, the Abu Gabra Formation showed different sandstone bodies thickness, geometry, and architecture and are ascribed to different depositional systems. At macro and meso-scales, reservoir quality varies within the Abu Gabra reservoir where it shows progressive coarsening upward tendencies with different degrees of connectivity. The upper part of the reservoir is well connected with amalgamated sandstone bodies, however, the middle to lower parts have moderate to low sandstone body connectivity and amalgamation. At a micro-scale, sandstone reservoir quality is directly affected by texture and diagenesis. The XRD and SEM analyses show that kaolinite and chlorite clay are the common clay minerals in the studied samples. Clay matrix and quartz overgrowth have significantly reduced the reservoir porosity and permeability, while the dissolution of feldspars during the diagenetic process increase it. The estimated porosity in Abu Gabra Formation ranges from 5 to 21% with an average of 13%; while permeability varies from 0.22 to 732 mD with an average of 240 mD. The results of this study contribute to a better understanding of reservoir heterogeneities and help in reservoir quality prediction, therefore enhancing the hydrocarbon productivity.

Petrophysics of Lower Silurian sandstones and integration with the tectonic-stratigraphic framework, Appalachian basin, United States

USGS Publications Warehouse

Castle, J.W.; Byrnes, A.P.

2005-01-01

Petrophysical properties were determined for six facies in Lower Silurian sandstones of the Appalachian basin: fluvial, estuarine, upper shoreface, lower shoreface, tidal channel, and tidal flat. Fluvial sandstones have the highest permeability for a given porosity and exhibit a wide range of porosity (2-18%) and permeability (0.002-450 md). With a transition-zone thickness of only 1-6 m (3-20 ft), fluvial sandstones with permeability greater than 5 md have irreducible water saturation (Siw) less than 20%, typical of many gas reservoirs. Upper shoreface sandstones exhibit good reservoir properties with high porosity (10-21%), high permeability (3-250 md), and low S iw (<20%). Lower shoreface sandstones, which are finer grained, have lower porosity (4-12%), lower permeability (0.0007-4 md), thicker transition zones (6-180 m [20-600 ft]), and higher S iw. In the tidal-channel, tidal-flat, and estuarine facies, low porosity (average < 6%), low permeability (average < 0.02 md), and small pore throats result in large transition zones (30-200 m; 100-650 ft) and high water saturations. The most favorable reservoir petrophysical properties and the best estimated production from the Lower Silurian sandstones are associated with fluvial and upper shoreface facies of incised-valley fills, which we interpret to have formed predominantly in areas of structural recesses that evolved from promontories along a collisional margin during the Taconic orogeny. Although the total thickness of the sandstone may not be as great in these areas, reservoir quality is better than in adjacent structural salients, which is attributed to higher energy depositional processes and shallower maximum burial depth in the recesses than in the salients. Copyright ??2005. The American Association of Petroleum Geologists. All rights reserved.

Saline-water resources of Texas

USGS Publications Warehouse

Winslow, Allen George; Kister, Lester Ray

1956-01-01

Most of the aquifers in Texas contain saline water in some parts, and a few are capable of producing large quantities of saline water. Of the early Paleozoic formations, the Hickory sandstone member of the Riley formation of Cambrian age and the Ellenburger group of Ordovician age are potential sources of small to moderate supplies of saline water in parts of central and west-central Texas.

Seeking new potential in the early-late Permian Gharif Play, West Central Oman

DOE Office of Scientific and Technical Information (OSTI.GOV)

Guit, F.; Al-Lawati, M.; Nederlof, P.

1995-08-01

West Central Oman is a relatively underexplored area where the hydrocarbons found to date occur mainly within the Early-Late Permian Gharif Formation. Structural definition of the low relief closures is hampered by seismic velocity variations caused by dune terrain. Recent exploration activity resulted in several Gharif discoveries, but highlighted reservoir distribution problems. The Gharif Formation, which consists of fluvio-marine sediments, conformably overlies the glacio-lacustine sediments of the Early Permian Al Khlata Formation. It is overlain by shallow marine carbonates of the Late Permian Khuff Formation, the main regional seal. The area is located distally from the main sediment sources tomore » the east. Reservoir development and lateral continuity are seen as the main risk. Most reservoirs are beyond seismic resolution, only the stacked sandstones of the incised valley fills could provide sufficient acoustic contrast to be recognized on seismic. Geochemical typing indicates that the hydrocarbons in the Gharif can be grouped in two main families: the Huqf and Q-hydrocarbons, which are believed to originate from Cambrian to Precambrian source rocks. Although the two hydrocarbon families are sometimes found in one well, they have very different spatial distributions. The Q-oils form continuous strings of accumulations below the main regional seal, whereas the Huqf hydrocarbons occur scattered throughout the area. Mixed accumulations are found where cross-faults or salt domes intercept a Q-oil fairway. Future exploration activities will be guided by refined sedimentological, stratigraphical and hydrocarbon migration models and by the continued efforts to recognize incised valley fills on seismic.« less

Effect of chemical environment and rock composition on fracture mechanics properties of reservoir lithologies in context of CO2 sequestration

NASA Astrophysics Data System (ADS)

Major, J. R.; Eichhubl, P.; Callahan, O. A.

2015-12-01

The coupled chemical and mechanical response of reservoir and seal rocks to injection of CO2 have major implications on the short and long term security of sequestered carbon. Many current numerical models evaluating behavior of reservoirs and seals during and after CO2 injection in the subsurface consider chemistry and mechanics separately and use only simple mechanical stability criteria while ignoring time-dependent failure parameters. CO2 injection irreversibly alters the subsurface chemical environment which can then affect geomechanical properties on a range of time scales by altering rock mineralogy and cements through dissolution, remobilization, and precipitation. It has also been documented that geomechanical parameters such as fracture toughness (KIC) and subcritical index (SCI) are sensitive to chemical environment. Double torsion fracture mechanics testing of reservoir lithologies under controlled environmental conditions relevant to CO2 sequestration show that chemical environment can measurably affect KIC and SCI. This coupled chemical-mechanical behavior is also influenced by rock composition, grains, amount and types of cement, and fabric. Fracture mechanics testing of the Aztec Sandstone, a largely silica-cemented, subarkose sandstone demonstrate it is less sensitive to chemical environment than Entrada Sandstone, a silty, clay-rich sandstone. The presence of de-ionized water lowers KIC by approximately 20% and SCI 30% in the Aztec Sandstone relative to tests performed in air, whereas the Entrada Sandstone shows reductions on the order of 70% and 90%, respectively. These results indicate that rock composition influences the chemical-mechanical response to deformation, and that the relative chemical reactivity of target reservoirs should be recognized in context of CO2 sequestration. In general, inert grains and cements such as quartz will be less sensitive to the changing subsurface environment than carbonates and clays.

The Sirte Basin province of Libya; Sirte-Zelten total petroleum system

USGS Publications Warehouse

Ahlbrandt, Thomas S.

2001-01-01

The Sirte (Sirt) Basin province ranks 13th among the world?s petroleum provinces, having known reserves of 43.1 bil-lion barrels of oil equivalent (36.7 billion barrels of oil, 37.7 tril-lion cubic feet of gas, 0.1 billion barrels of natural gas liquids). It includes an area about the size of the Williston Basin of the north-ern United States and southern Canada (?490,000 square kilome-ters). The province contains one dominant total petroleum system, the Sirte-Zelten, based on geochemical data. The Upper Cretaceous Sirte Shale is the primary hydrocarbon source bed. Reservoirs range in rock type and age from fractured Precam-brian basement, clastic reservoirs in the Cambrian-Ordovician Gargaf sandstones, and Lower Cretaceous Nubian (Sarir) Sand-stone to Paleocene Zelten Formation and Eocene carbonates commonly in the form of bioherms. More than 23 large oil fields (>100 million barrels of oil equivalent) and 16 giant oil fields (>500 million barrels of oil equivalent) occur in the province. Abstract 1 Production from both clastic and carbonate onshore reservoirs is associated with well-defined horst blocks related to a triple junc-tion with three arms?an eastern Sarir arm, a northern Sirte arm, and a southwestern Tibesti arm. Stratigraphic traps in combina-tion with these horsts in the Sarir arm are shown as giant fields (for example, Messla and Sarir fields in the southeastern portion of the province). Significant potential is identified in areas marginal to the horsts, in the deeper grabens and in the offshore area. Four assessment units are defined in the Sirte Basin prov-ince, two reflecting established clastic and carbonate reservoir areas and two defined as hypothetical units. Of the latter, one is offshore in water depths greater than 200 meters, and the other is onshore where clastic units, mainly of Mesozoic age, may be res-ervoirs for laterally migrating hydrocarbons that were generated in the deep-graben areas. The Sirte Basin reflects significant rifting in the Early Cre-taceous and syn-rift sedimentary filling during Cretaceous through Eocene time, and post-rift deposition in the Oligocene and Miocene. Multiple reservoirs are charged largely by verti-cally migrating hydrocarbons along horst block faults from Upper Cretaceous source rocks that occupy structurally low posi-tions in the grabens. Evaporites in the middle Eocene, mostly post-rift, provide an excellent seal for the Sirte-Zelten hydrocarbon system. The offshore part of the Sirte Basin is complex, with subduction occurring to the northeast of the province boundary, which is drawn at the 2,000-meter isobath. Possible petroleum systems may be present in the deep offshore grabens on the Sirte Rise such as those involving Silurian and Eocene rocks; however, potential of these systems remains speculative and was not assessed.

Facies Distribution and Petrophysical Properties of Shoreface-Offshore Transition Environment in Sandakan Formation, NE Sabah Basin

NASA Astrophysics Data System (ADS)

Majid, M. Firdaus A.; Suhaili Ismail, M.; Rahman, A. Hadi A.; Azfar Mohamed, M.

2017-10-01

Newly exposed outcrop of Miocene shallow marine sandstone in Sandakan Formation, allows characterization of the facies distribution and petrophysical properties of shoreface to offshore transition environment. Six facies are defined: (1) Poorly bioturbated Hummocky Cross Stratified (HCS) sandstone (F1), (2) Moderately bioturbated HCS sandstone (F2), (3) Well bioturbated HCS sandstone (F3), (4) Poorly bioturbated Swaley Cross Stratified (SCS) sandstone (F4), (5) Interbedded HCS sandstone with sand-silt mudstone, (6) Heterolithic mudstone. The sedimentary successions were deposited in upper to lower shoreface, and offshore transition environment. Facies F3, F4 and F5 shows good reservoir quality with good porosity and fair permeability values from 20% to 21% and 14 mD to 33 mD respectively. While Facies F1 exhibits poor reservoir quality with low permeability values 3.13 mD.

Radium content of oil- and gas-field produced waters in the northern Appalachian Basin (USA)—Summary and discussion of data

USGS Publications Warehouse

Rowan, E.L.; Engle, M.A.; Kirby, C.S.; Kraemer, T.F.

2011-01-01

Radium activity data for waters co-produced with oil and gas in New York and Pennsylvania have been compiled from publicly available sources and are presented together with new data for six wells, including one time series. When available, total dissolved solids (TDS), and gross alpha and gross beta particle activities also were compiled. Data from the 1990s and earlier are from sandstone and limestone oil/gas reservoirs of Cambrian-Mississippian age; however, the recent data are almost exclusively from the Middle Devonian Marcellus Shale. The Marcellus Shale represents a vast resource of natural gas the size and significance of which have only recently been recognized. Exploitation of the Marcellus involves hydraulic fracturing of the shale to release tightly held gas. Analyses of the water produced with the gas commonly show elevated levels of salinity and radium. Similarities and differences in radium data from reservoirs of different ages and lithologies are discussed. The range of radium activities for samples from the Marcellus Shale (less than detection to 18,000 picocuries per liter (pCi/L)) overlaps the range for non-Marcellus reservoirs (less than detection to 6,700 pCi/L), and the median values are 2,460 pCi/L and 734 pCi/L, respectively. A positive correlation between the logs of TDS and radium activity can be demonstrated for the entire dataset, and controlling for this TDS dependence, Marcellus shale produced water samples contain statistically more radium than non-Marcellus samples. The radium isotopic ratio, Ra-228/Ra-226, in samples from the Marcellus Shale is generally less than 0.3, distinctly lower than the median values from other reservoirs. This ratio may serve as an indicator of the provenance or reservoir source of radium in samples of uncertain origin.

Research on the Log Interpretation Method of Tuffaceous Sandstone Reservoirs of X Depression in Hailar-Tamtsag Basin

NASA Astrophysics Data System (ADS)

Liu, S.; Pan, B.

2015-12-01

The logging evaluation of tuffaceous sandstone reservoirs is always a difficult problem. Experiments show that the tuff and shale have different logging responses. Since the tuff content exerts an influence on the computation of shale content and the parameters of the reservoir, and the accuracy of saturation evaluation is reduced. Therefore, the effect of tuff on the calculation of saturation cannot be ignored. This study takes the tuffaceous sandstone reservoirs in the X depression of Hailar-Tamtsag basin as an example to analyze. And the electric conduction model of tuffaceous sandstone reservoirs is established. The method which combines bacterial foraging algorithm and particle swarm optimization algorithm is used to calculate the content of reservoir components in well logging for the first time, and the calculated content of tuff and shale corresponds to the results analysis of thin sections. The experiment on cation exchange capacity (CEC) proves that tuff has conductivity, and the conversion relationship between CEC and resistivity proposed by Toshinobu Iton has been improved. According to the rock electric experiment under simulated reservoir conditions, the rock-electro parameters (a, b, m and n) are determined. The improved relationship between CEC and resistivity and the rock-electro parameters are used in the calculation of saturation. Formula (1) shows the saturation equation of the tuffaceous reservoirs:According to the comparative analysis between irreducible water saturation and the calculated saturation, we find that the saturation equation used CEC data and rock-electro parameters has a better application effect at oil layer than Archie's formulas.

A refined genetic model for the Laisvall and Vassbo Mississippi Valley-type sandstone-hosted deposits, Sweden: constraints from paragenetic studies, organic geochemistry, and S, C, N, and Sr isotope data

NASA Astrophysics Data System (ADS)

Saintilan, Nicolas J.; Spangenberg, Jorge E.; Samankassou, Elias; Kouzmanov, Kalin; Chiaradia, Massimo; Stephens, Michael B.; Fontboté, Lluís

2016-06-01

The current study has aimed to refine the previously proposed two-fluid mixing model for the Laisvall (sphalerite Rb-Sr age of 467 ± 5 Ma) and Vassbo Mississippi Valley-type deposits hosted in Ediacaran to Cambrian sandstone, Sweden. Premineralization cements include authigenic monazite, fluorapatite, and anatase in the Upper Sandstone at Laisvall, reflecting anoxic conditions during sandstone burial influenced by the euxinic character of the overlying carbonaceous middle Cambrian to Lower Ordovician Alum Shale Formation ( δ 13Corg = -33.0 to -29.5 ‰, δ 15Norg = 1.5 to 3.3 ‰, 0.33 to 3.03 wt% C, 0.02 to 0.08 wt% N). The available porosity for epigenetic mineralization, including that produced by subsequent partial dissolution of pre-Pb-Zn sulfide calcite and barite cements, was much higher in calcite- and barite-cemented sandstone paleoaquifers (29 % by QEMSCAN mapping) than in those mainly cemented by quartz (8 %). A major change in the Laisvall plumbing system is recognized by the transition from barite cementation to Pb-Zn sulfide precipitation in sandstone. Ba-bearing, reduced, and neutral fluids had a long premineralization residence time (highly radiogenic 87S/86Sr ratios of 0.718 to 0.723) in basement structures. As a result of an early Caledonian arc-continent collision and the development of a foreland basin, fluids migrated toward the craton and expelled Ba-bearing fluids from their host structures into overlying sandstone where they deposited barite upon mixing with a sulfate pool ( δ 34Sbarite = 14 to 33 ‰). Subsequently, slightly acidic brines initially residing in pre-Ediacaran rift sediments in the foredeep of the early Caledonian foreland basin migrated through the same plumbing system and acquired metals on the way. The bulk of Pb-Zn mineralization formed at temperatures between 120 and 180 °C by mixing of these brines with a pool of H2S ( δ 34S = 24 to 29 ‰) produced via thermochemical sulfate reduction (TSR) with oxidation of hydrocarbons in sandstone. Other minor H2S sources are identified. Upward migration and fluctuation of the hydrocarbon-water interface in sandstone below shale aquicludes and the formation of H2S along this interface explain the shape of the orebodies that splay out like smoke from a chimney and the conspicuous alternating layers of galena and sphalerite. Intimate intergrowth of bitumen with sphalerite suggests that subordinate amounts of H2S might have been produced by TSR during Pb-Zn mineralization. Gas chromatograms of the saturated hydrocarbon fraction from organic-rich shale and from both mineralized and barren sandstone samples indicate that hydrocarbons migrated from source rocks in the overlying Alum Shale Formation buried in the foredeep into sandstone, where they accumulated in favorable traps in the forebulge setting.

Muddy and dolomitic rip-up clasts in Triassic fluvial sandstones: Origin and impact on potential reservoir properties (Argana Basin, Morocco)

NASA Astrophysics Data System (ADS)

Henares, Saturnina; Arribas, Jose; Cultrone, Giuseppe; Viseras, Cesar

2016-06-01

The significance of rip-up clasts as sandstone framework grains is frequently neglected in the literature being considered as accessory components in bulk sandstone composition. However, this study highlights the great value of muddy and dolomitic rip-up clast occurrence as: (a) information source about low preservation potential from floodplain deposits and (b) key element controlling host sandstone diagenetic evolution and thus ultimate reservoir quality. High-resolution petrographic analysis on Triassic fluvial sandstones from Argana Basin (T6 and T7/T8 units) highlights the significance of different types of rip-up clasts as intrabasinal framework components of continental sediments from arid climates. On the basis of their composition and ductility, three main types are distinguished: (a) muddy rip-up clasts, (b) dolomitic muddy rip-up clasts and (c) dolomite crystalline rip-up clasts. Spatial distribution of different types is strongly facies-related according to grain size. Origin of rip-up clasts is related to erosion of coeval phreatic dolocretes, in different development stages, and associated muddy floodplain sediments. Cloudy cores with abundant inclusions and clear outer rims of dolomite crystals suggest a first replacive and a subsequent displacive growth, respectively. Dolomite crystals are almost stoichiometric. This composition is very similar to that of early sandstone dolomite cement, supporting phreatic dolocretes as dolomite origin in both situations. Sandstone diagenesis is dominated by mechanical compaction and dolomite cementation. A direct correlation exists between: (1) muddy rip-up clast abundance and early reduction of primary porosity by compaction with irreversible loss of intergranular volume (IGV); and (2) occurrence of dolomitic rip-up clasts and dolomite cement nucleation in host sandstone, occluding adjacent pores but preserving IGV. Both processes affect reservoir quality by generation of vertical and 3D fluid flow baffles and barriers that compartmentalize the reservoir. These findings may provide quantitative useful data for the better understanding of reservoir quality in analogous hydrocarbon-bearing basins such as the Bay of Fundy, Nova Scotia (Canada).

Sedimentology and reservoir heterogeneity of a valley-fill deposit-A field guide to the Dakota Sandstone of the San Rafael Swell, Utah

USGS Publications Warehouse

Kirschbaum, Mark A.; Schenk, Christopher J.

2010-01-01

Valley-fill deposits form a significant class of hydrocarbon reservoirs in many basins of the world. Maximizing recovery of fluids from these reservoirs requires an understanding of the scales of fluid-flow heterogeneity present within the valley-fill system. The Upper Cretaceous Dakota Sandstone in the San Rafael Swell, Utah contains well exposed, relatively accessible outcrops that allow a unique view of the external geometry and internal complexity of a set of rocks interpreted to be deposits of an incised valley fill. These units can be traced on outcrop for tens of miles, and individual sandstone bodies are exposed in three dimensions because of modern erosion in side canyons in a semiarid setting and by exhumation of the overlying, easily erodible Mancos Shale. The Dakota consists of two major units: (1) a lower amalgamated sandstone facies dominated by large-scale cross stratification with several individual sandstone bodies ranging in thickness from 8 to 28 feet, ranging in width from 115 to 150 feet, and having lengths as much as 5,000 feet, and (2) an upper facies composed of numerous mud-encased lenticular sandstones, dominated by ripple-scale lamination, in bedsets ranging in thickness from 5 to 12 feet. The lower facies is interpreted to be fluvial, probably of mainly braided stream origin that exhibits multiple incisions amalgamated into a complex sandstone body. The upper facies has lower energy, probably anastomosed channels encased within alluvial and coastal-plain floodplain sediments. The Dakota valley-fill complex has multiple scales of heterogeneity that could affect fluid flow in similar oil and gas subsurface reservoirs. The largest scale heterogeneity is at the formation level, where the valley-fill complex is sealed within overlying and underlying units. Within the valley-fill complex, there are heterogeneities between individual sandstone bodies, and at the smallest scale, internal heterogeneities within the bodies themselves. These different scales of fluid-flow compartmentalization present a challenge to hydrocarbon exploration targeting paleovalley deposits, and producing fields containing these types of reservoirs may have significant bypassed pay, especially where well spacing is large.

Petroleum geology and resources of the Baykit High province, East Siberia, Russia

USGS Publications Warehouse

Ulmishek, Gregory F.

2001-01-01

The Baykit High province consists of two principal structural units?the Baykit regional high in the west, which occupies most of the province, and the Katanga structural saddle in the east. The province is on the western margin of the Siberian craton east of theYenisey Ridge foldbelt. The province is an exploration frontier and only a few prospects have been drilled. The oldest sedimentary rocks of the province, Riphean carbonate and clastic strata of Late Proterozoic age (1,650?650 million years old) that were deposited on the passive margin, cover the Archean?Lower Proterozoic basement. Basal Vendian (uppermost Proterozoic, 650?570 million years old) clastic rocks unconformably overlie various units of the Riphean and locally lie directly on the basement. Younger Vendian and lowermost Cambrian rocks are primarily dolomites. The Vendian/Cambrian boundary is con-formable, and its exact stratigraphic position has not been identified with certainty. The Lower Cambrian section is thick, and it consists of alternating beds of dolomite and evaporites (mostly salt). Middle and Upper Cambrian strata are composed of shale and dolomite. Ordovician-Silurian and upper Paleozoic rocks are thin, and they are present only in the northern areas of the province. Structural pattern of Riphean rocks differs substantially from that of Vendian-Cambrian rocks. A single total petroleum system (TPS) was identified in the Baykit High province. Discovered oil of the system is chiefly concentrated in Riphean carbonate reservoirs of the Yurubchen-Tokhom zone that is currently being explored and that has the Abstract 1 potential to become a giant field (or group of fields). The TPS also contains about 5 trillion cubic feet of discovered recover-able gas in clastic reservoir rocks at the base of the Vendian section. Petroleum source rocks are absent in the stratigraphic succession over most of the TPS area. Riphean organic-rich shales and carbonates that crop out in the Yenisey Ridge foldbelt west of the Baykit high are probable source rocks. Their areal distribution extends from the foldbelt into the foredeep along the province?s western margin. Potential source rocks also are present in platform depressions in eastern areas of the province. Hydrocarbon generation and migration west of the province started as early as Riphean time, before the beginning of the deformation in the Yenisey Ridge foldbelt that occurred about 820?850 million years ago. However, the presently known oil and gas accumulations were formed after deposition of the Lower Cambrian salt seal. Available data allow identification of only one assessment unit, and it covers the entire TPS area. Undiscovered oil and gas resources are moderate, primarily due to the poor quality of reservoir rocks. However, the reserve growth in the Yurubchen-Tokhom zone may be large and may exceed the volume of undiscovered resources in the rest of the province. Most oil and gas resourcesareexpectedtobeinstructuralandstratigraphictrapsin Riphean carbonate reservoirs. Vendian clastic reservoirs are probably gas-prone.

Evidence for Cambrian petroleum source rocks in the Rome trough of West Virginia and Kentucky, Appalachian basin: Chapter G.8 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Ryder, Robert T.; Harris, David C.; Gerome, Paul; Hainsworth, Timothy J.; Burruss, Robert A.; Lillis, Paul G.; Jarvie, Daniel M.; Pawlewicz, Mark J.; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

The bitumen extract from the Rogersville Shale compares very closely with oils or condensates from Cambrian reservoirs in the Carson Associates No. 1 Kazee well, Homer gas field, Elliott County, Ky.; the Inland No. 529 White well, Boyd County, Ky.; and the Miller No. 1 well, Wolfe County, Ky. These favorable oil-source rock correlations suggest a new petroleum system in the Appalachian basin that is characterized by a Conasauga Group source rock and Rome Formation and Conasauga Group reservoirs. This petroleum system probably extends along the Rome trough from eastern Kentucky to at least central West Virginia.

Reservoir sedimentology of the Big Injun sandstone in Granny Creek field, West Virginia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Zou, Xiangdong; Donaldson, K.; Donaldson, A.C.

1992-01-01

Big Injun sandstones of Granny Creek oil field (WV) are interpreted as fluvial-deltaic deposits from core and geophysical log data. The reservoir consists of two distinctive lithologies throughout the field; fine-grained sandstones overlain by pebbly and coarse-grained sandstones. Lower fine-grained sandstones were deposited in westward prograding river-mouth bars, where distal, marine-dominant proximal, and fluvial-dominant proximal bar subfacies are recognized. Principal pay is marine-influenced proximal bar, where porosity ranges from 13 to 23% and permeability, up to 24 md. Thin marine transgressive shales and their laterally equivalent low-permeability sandstones bound time-rock sequences generally less than 10 meters thick. Where field mapped,more » width of prograding bar sequence is approximately 2.7 km (dip trend), measured from truncated eastern edge (pre-coarse-grained member erosional surface) to distal western margin. Dip-trending elongate lobes occur within marine-influenced proximal mouth-bar area, representing thickest part of tidally influenced preserved bar. Upper coarse-grained part of reservoir consists of pebbly sandstones of channel fill from bedload streams. Laterally persistent low permeability cemented interval in lower part commonly caps underlying pay zone and probably serves as seal to vertical oil migration. Southwest paleoflow trends based on thickness maps of unit portent emergence of West Virginia dome, which influences erosion patterns of pre-Greenbrier unconformity for this combination oil trap.« less

Petroleum geology and resources of the Nepa-Botuoba High, Angara-Lena Terrace, and Cis-Patom Foredeep, southeastern Siberian Craton, Russia

USGS Publications Warehouse

Ulmishek, Gregory F.

2001-01-01

Three structural provinces of this report, the Nepa-Botuoba High, the Angara-Lena Terrace, and the Cis-Patom Foredeep, occupy the southeastern part of the Siberian craton northwest of the Baikal-Patom folded region (fig. 1). The provinces are similar in many aspects of their history of development, stratigraphic composition, and petroleum geology characteristics. The sedimentary cover of the provinces overlies the Archean?Lower Proterozoic basement of the Siberian craton. Over most of the area of the provinces, the basement is covered by Vendian (uppermost Proterozoic, 650?570 Ma) clastic and carbonate rocks. Unlike the case in the more northwestern areas of the craton, older Riphean sedimentary rocks here are largely absent and they appear in the stratigraphic sequence only in parts of the Cis-Patom Foredeep province. Most of the overlying sedimentary section consists of Cambrian and Ordovician carbonate and clastic rocks, and it includes a thick Lower Cambrian salt-bearing formation. Younger rocks are thin and are present only in marginal areas. 1 A single total petroleum system (TPS) embraces all three provinces. The TPS is unique in two aspects: (1) its rich hydro-carbon reserves are derived from Precambrian source rocks and (2) preservation of oil and gas fields is extremely long owing to the presence of the Lower Cambrian undeformed salt seal. Discovered reserves of the TPS are about 2 billion barrels of oil and more than 30 trillion cubic feet of gas. The stratigraphic distribution of oil and gas reserves is narrow; all fields are in Vendian to lowermost Cambrian clastic and carbonate reservoirs that occur below Lower Cambrian salt. Both structural and stratigraphic traps are known. Source rocks are absent in the sedimentary cover of the provinces, with the possible exception of a narrow zone on the margin of the Cis-Patom Foredeep province. Source rocks are interpreted here to be Riphean and Vendian organic-rich shales of the Baikal-Patom folded region. These rocks presently are deformed and metamorphosed, but they generated oil and gas before the deformation occurred in Late Silurian and Devonian time. Generated hydrocarbons migrated updip onto the craton margin. The time of migration and formation of fields is constrained by the deposition of Lower Cambrian salt and by the Late Silurian or Devonian metamorphism of source rocks. This time frame indicates that the TPS is one of the oldest petroleum systems in the world. All three provinces are exploration frontiers, and available geologic data are limited; therefore, only one assessment unit has been identified. The largest undiscovered hydrocarbon resources are expected to be in Vendian clastic reservoirs in both structural and stratigraphic traps of the Nepa-Botuoba High province. The petroleum potential of Vendian?lowermost Cambrian carbonate reservoirs is smaller. Nevertheless, these reservoirs may contain significant resources. Gas is expected to dominate over oil in the resource base.

Electrofacies vs. lithofacies sandstone reservoir characterization Campanian sequence, Arshad gas/oil field, Central Sirt Basin, Libya

NASA Astrophysics Data System (ADS)

Burki, Milad; Darwish, Mohamed

2017-06-01

The present study focuses on the vertically stacked sandstones of the Arshad Sandstone in Arshad gas/oil field, Central Sirt Basin, Libya, and is based on the conventional cores analysis and wireline log interpretation. Six lithofacies types (F1 to F6) were identified based on the lithology, sedimentary structures and biogenic features, and are supported by wireline log calibration. From which four types (F1-F4) represent the main Campanian sandstone reservoirs in the Arshad gas/oil field. Lithofacies F5 is the basal conglomerates at the lower part of the Arshad sandstones. The Paleozoic Gargaf Formation is represented by lithofacies F6 which is the source provenance for the above lithofacies types. Arshad sediments are interpreted to be deposited in shallow marginal and nearshore marine environment influenced by waves and storms representing interactive shelf to fluvio-marine conditions. The main seal rocks are the Campanian Sirte shale deposited in a major flooding events during sea level rise. It is contended that the syn-depositional tectonics controlled the distribution of the reservoir facies in time and space. In addition, the post-depositional changes controlled the reservoir quality and performance. Petrophysical interpretation from the porosity log values were confirmed by the conventional core measurements of the different sandstone lithofacies types. Porosity ranges from 5 to 20% and permeability is between 0 and 20 mD. Petrophysical cut-off summary of the lower part of the clastic dominated sequence (i. e. Arshad Sandstone) calculated from six wells includes net pay sand ranging from 19.5‧ to 202.05‧, average porosity from 7.7 to 15% and water saturation from 19 to 58%.

An Intensive Survey of Archaeological Resources in the Proposed Long Branch Reservoir. Volume 2B

DTIC Science & Technology

1977-01-01

GcGb - Gneissic Gabbro Hematite TGn - Talc Gneiss c - chipped ShGb - Schistic Gabbro a - scratched ShD - Schistic Dolerite f - flake FH/SS - Flint...Hill Sandstone g - ground Mss - Micaceous Sandstone fss - Ferruginous Sandstone A - Argillite c - chert Qtz - Quartz FGQtt - Fine-grained Quartzite Qtt...ARTIFACTS - LONG BRANCI RESERVOIR 41 0 Points Contracti~ng-@ taed, square-based points l a 23MC55 4-4 50 25 9 9.6g b 23MCSS 2-1 74 39 9 22.8g c

DOE Office of Scientific and Technical Information (OSTI.GOV)

Hohn, M.E.; Patchen, D.G.; Heald, M.

Non-uniform composition and permeability of a reservoir, commonly referred to as reservoir heterogeneity, is recognized as a major factor in the efficient recovery of oil during primary production and enhanced recovery operations. Heterogeneities are present at various scales and are caused by various factors, including folding and faulting, fractures, diagenesis and depositional environments. Thus, a reservoir consists of a complex flow system, or series of flow systems, dependent on lithology, sandstone genesis, and structural and thermal history. Ultimately, however, fundamental flow units are controlled by the distribution and type of depositional environments. Reservoir heterogeneity is difficult to measure and predict,more » especially in more complex reservoirs such as fluvial-deltaic sandstones. The Appalachian Oil and Natural Gas Research Consortium (AONGRC), a partnership of Appalachian basin state geological surveys in Kentucky, Ohio, Pennsylvania, and West Virginia, and West Virginia University, studied the Lower Mississippian Big Injun sandstone in West Virginia. The Big Injun research was multidisciplinary and designed to measure and map heterogeneity in existing fields and undrilled areas. The main goal was to develop an understanding of the reservoir sufficient to predict, in a given reservoir, optimum drilling locations versus high-risk locations for infill, outpost, or deeper-pool tests.« less

Influence of depositional environment on diagenesis in St. Peter sandstone, Michigan basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Lundgren, C.E. Jr.; Barnes, D.A.

1989-03-01

The Middle Ordovician St. Peter Sandstone in the Michigan basin was deposited in marine peritidal to storm-dominated, outer shelf depositional environments that evolved in a regionally significant transgressive pattern. The formation is bounded by carbonate and shaly clastic strata of the Prairie du Chien Group below and is transitional to condensed sequence clastics and carbonates of the Glenwood Formation above. Sedimentologic and petrographic analysis of conventional core from 25 wells suggests that reservoir quality in the formation is strongly dependent on a complex diagenetic history, especially the nature and subsequent dissolution of intergranular carbonate in the sandstone. Petrographic evidence indicatesmore » that porosity in the formation formed by dissolution of precursor dolomite of various origins and, locally, the formation of pore-filling authigenic clay (chlorite-illite). Authigenic clay is the incongruent dissolution product of dolomite, detrital K-feldspar, and, possibly, muscovite and results in diminished reservoir quality where abundant in the St. Peter Sandstone. Authigenic clay is volumetrically more significant in the upper portions of the formation and is associated with higher concentrations of detrital K-feldspar. Depositional facies controlled the distribution and types of intergranular carbonate (now dolomite) and detrital K-feldspar in the St. Peter Sandstone and hence reservoir quality; both components were more significant in storm-shelf sandstone facies.« less

Lithostratigraphic controls on bedding-plane fractures and the potential for discrete groundwater flow through a siliciclastic sandstone aquifer, southern Wisconsin

NASA Astrophysics Data System (ADS)

Swanson, Susan K.

2007-04-01

Outcrop-analog studies of the Upper Cambrian Tunnel City Group sandstones in southern Wisconsin show the utility of lithostratigraphic information in hydrostratigraphic studies of siliciclastic sandstone aquifers. Recent work supports the lateral continuity of discrete groundwater flow through these sandstones. Lithologic description of the Reno Member of the Lone Rock Formation (Tunnel City Group) in outcrop and core reveals repeating sequences of three dominant lithofacies, including flat-pebble intraclast conglomerate with a glauconite-rich matrix; glauconitic and feldspathic subquartzose sandstone with horizontal-planar, low-angle, and hummocky lamination; and feldspathic subquartzose sandstone with dolomite-filled burrows. The vertically stacked Reno Member sequences have been interpreted as having a storm-related origin, and they are laterally continuous on the scale of an outcrop. Horizontal fracture locations correlate with bedding planes at contacts between lithofacies. They are most commonly associated with the base of the flat-pebble intraclast conglomerate or with partings along laminae and erosional surfaces in the laminated subquartzose sandstone lithofacies. Sequences show upward increases in natural gamma radiation due to increasing potassium feldspar content. The incorporation of the detailed lithostratigraphic information allows a more accurate interpretation of borehole natural gamma logs where the rocks are buried and saturated and clarifies the role of sedimentary structures in the distribution of features that might promote discrete flow through these rocks.

Maquoketa Shale Caprock Integrity Evaluation

DOE Office of Scientific and Technical Information (OSTI.GOV)

Leetaru, Hannes

2014-09-30

The Knox Project objective is to evaluate the potential of formations within the Cambrian-Ordovician strata above the Mt. Simon Sandstone (St. Peter Sandstone and Potosi Dolomite) as potential targets for carbon dioxide (CO2) sequestration in the Illinois and Michigan Basins. The suitability of the St. Peter Sandstone and Potosi Dolomite to serve as reservoirs for CO2 sequestration is discussed in separate reports. In this report the data gathered from the Knox project, the Illinois Basin – Decatur Project (IBDP) and Illinois Industrial Carbon Capture and Sequestration project (IL-ICCS) are used to make some conclusions about the suitability of the Maquoketamore » shale as a confining layer for CO2 sequestration. These conclusions are then upscaled to basin-wide inferences based on regional knowledge. Data and interpretations (stratigraphic, petrophysical, fractures, geochemical, risk, seismic) applicable to the Maquoketa Shale from the above mentioned projects was inventoried and summarized. Based on the analysis of these data and interpretations, the Maquoketa Shale is considered to be an effective caprock for a CO2 injection project in either the Potosi Dolomite or St. Peter Sandstone because it has a suitable thickness (~200ft. ~61m), advantageous petrophysical properties (low effective porosity and low permeability), favorable geomechanical properties, an absence of observable fractures and is regionally extensive. Because it is unlikely that CO2 would migrate upward through the Maquoketa Shale, CO2, impact to above lying fresh water aquifers is unlikely. Furthermore, the observations indicate that CO2 injected into the St. Peter Sandstone or Potosi Dolomite may never even migrate up into the Maquoketa Shale at a high enough concentrations or pressure to threaten the integrity of the caprock. Site specific conclusions were reached by unifying the data and conclusions from the IBDP, ICCS and the Knox projects. In the Illinois Basin, as one looks further away from these sites, the formation characteristics are expected to vary. The degree of how well this data can be extrapolated throughout the Basins (regionalized) is difficult to quantify because of the limited amount of data collected on the Maquoketa Shale away from IBDP, IL-ICCS and the Knox projects. Data gathered from the IBDP/IL-ICCS/Knox projects were used to make conclusions about the suitability of the Maquoketa shale as a confining layer for CO2 sequestration. This study indicates that the Maquoketa Shale would be a suitable caprock for a CO2 injection program in either the Potosi Dolomite or St. Peter Sandstone.« less

Reservoir zonation based on statistical analyses: A case study of the Nubian sandstone, Gulf of Suez, Egypt

NASA Astrophysics Data System (ADS)

El Sharawy, Mohamed S.; Gaafar, Gamal R.

2016-12-01

Both reservoir engineers and petrophysicists have been concerned about dividing a reservoir into zones for engineering and petrophysics purposes. Through decades, several techniques and approaches were introduced. Out of them, statistical reservoir zonation, stratigraphic modified Lorenz (SML) plot and the principal component and clustering analyses techniques were chosen to apply on the Nubian sandstone reservoir of Palaeozoic - Lower Cretaceous age, Gulf of Suez, Egypt, by using five adjacent wells. The studied reservoir consists mainly of sandstone with some intercalation of shale layers with varying thickness from one well to another. The permeability ranged from less than 1 md to more than 1000 md. The statistical reservoir zonation technique, depending on core permeability, indicated that the cored interval of the studied reservoir can be divided into two zones. Using reservoir properties such as porosity, bulk density, acoustic impedance and interval transit time indicated also two zones with an obvious variation in separation depth and zones continuity. The stratigraphic modified Lorenz (SML) plot indicated the presence of more than 9 flow units in the cored interval as well as a high degree of microscopic heterogeneity. On the other hand, principal component and cluster analyses, depending on well logging data (gamma ray, sonic, density and neutron), indicated that the whole reservoir can be divided at least into four electrofacies having a noticeable variation in reservoir quality, as correlated with the measured permeability. Furthermore, continuity or discontinuity of the reservoir zones can be determined using this analysis.

Detrital Record of Phanerozoic Tectonics in Iran: Evidence From U-Pb Zircon Geochronology

NASA Astrophysics Data System (ADS)

Horton, B. K.; Gillis, R. J.; Stockli, D. F.; Hassanzadeh, J.; Axen, G. J.; Grove, M.

2004-12-01

Ion-microprobe U-Pb ages of 91 detrital zircon grains supplement ongoing investigations of the tectonic history of Iran, a critical region bridging the gap between the Alpine and Himalayan orogenic belts. These data improve understanding of the distribution of continental blocks during a complex history of Late Proterozoic (Pan-African) crustal growth, Paleozoic passive-margin sedimentation, early Mesozoic collision with Eurasia, and Cenozoic collision with Arabia. U-Pb analyses of detrital zircon grains from four sandstone samples (two Lower Cambrian, one uppermost Triassic-Lower Jurassic, one Neogene) collected from the Alborz mountains of northern Iran reveal a spectrum of ages ranging from 50 to 2900 Ma. Most analyses yield concordant to moderately discordant ages. The Lower Cambrian Lalun and Barut sandstones yield age distribution peaks at approximately 550-650, 1000, and 2500 Ma, consistent with a Gondwanan source area presently to the south and west in parts of Iran and the Arabian-Nubian shield (Saudi Arabia and northwestern Africa). The uppermost Triassic-Lower Jurassic Shemshak Formation exhibits a broad range of U-Pb ages, including peaks of approximately 200-260, 330, 430, 600, and 1900 Ma, requiring a Eurasian source area presently to the north and east in the Turan plate (Turkmenistan and southwestern Asia). Neogene strata display both the youngest and oldest ages (approximately 50 and 2900 Ma) of any samples, a result of substantial sedimentary recycling of older Phanerozoic cover rocks. Because the youngest zircon ages for three of the four samples are indistinguishable from their stratigraphic (depositional) ages, these data suggest rapid exhumation and help constrain the termination age of Late Proterozoic-Early Cambrian (Pan-African) orogenesis and the timing of the Iran-Eurasia collision.

Provenance of north Gondwana Cambrian-Ordovician sandstone: U-Pb SHRIMP dating of detrital zircons from Israel and Jordan

USGS Publications Warehouse

Kolodner, K.; Avigad, D.; McWilliams, M.; Wooden, J.L.; Weissbrod, T.; Feinstein, S.

2006-01-01

A vast sequence of quartz-rich sandstone was deposited over North Africa and Arabia during Early Palaeozoic times, in the aftermath of Neoproterozoic Pan-African orogeny and the amalgamation of Gondwana. This rock sequence forms a relatively thin sheet (1-3 km thick) that was transported over a very gentle slope and deposited over a huge area. The sense of transport indicates unroofing of Gondwana terranes but the exact provenance of the siliciclastic deposit remains unclear. Detrital zircons from Cambrian arkoses that immediately overlie the Neoproterozoic Arabian-Nubian Shield in Israel and Jordan yielded Neoproterozoic U-Pb ages (900-530 Ma), suggesting derivation from a proximal source such as the Arabian-Nubian Shield. A minor fraction of earliest Neoproterozoic and older age zircons was also detected. Upward in the section, the proportion of old zircons increases and reaches a maximum (40%) in the Ordovician strata of Jordan. The major earliest Neoproterozoic and older age groups detected are 0.95-1.1, 1.8-1.9 and 2.65-2.7 Ga, among which the 0.95-1.1 Ga group is ubiquitous and makes up as much as 27% in the Ordovician of Jordan, indicating it is a prominent component of the detrital zircon age spectra of northeast Gondwana. The pattern of zircon ages obtained in the present work reflects progressive blanketing of the northern Arabian-Nubian Shield by Cambrian-Ordovician sediments and an increasing contribution from a more distal source, possibly south of the Arabian-Nubian Shield. The significant changes in the zircon age signal reflect many hundreds of kilometres of southward migration of the provenance. ?? 2006 Cambridge University Press.

Diagenesis of an 'overmature' gas reservoir: The Spiro sand of the Arkoma Basin, USA

USGS Publications Warehouse

Spotl, C.; Houseknecht, D.W.; Burns, S.J.

1996-01-01

The Spiro sand is a laterally extensive thin sandstone of earliest Atokan (Pennsylvanian) age that forms a major natural gas reservoir in the western Arkoma Basin, Oklahoma. Petrographic analysis reveals a variety of diagenetic alterations, the majority of which occurred during moderate to deep burial. Early diagenetic processes include calcite cementation and the formation of Fe-clay mineral peloids and coatings around quartz framework grains. These clays, which underwent transformation to well-crystallized chamosite [polytype Ib(?? = 90??)] on burial, are particularly abundant in medium-grained channel sandstones, whereas illitic clays are predominant in fine-grained interchannel sandstones. Subsequent to mechanical compaction, saddle ankerite precipitated in the reservoir at temperatures in excess of 70??C. Crude oil collected in favourable structural locations during and after ankeritization. Whereas hydrocarbons apparently halted inorganic diagenesis in oil-saturated zones, cementation continued in the underlying water-saturated zones. As reservoir temperatures increased further, hydrocarbons were cracked and a solid pyrobitumen residue remained in the reservoir. At temperatures exceeding ???140-150??C, non-syntaxial quartz cement, ferroan calcite and traces of dickite(?) locally reduced the reservoir quality. Local secondary porosity was created by carbonate cement dissolution. This alteration post-dated hydrocarbon emplacement and is probably related to late-stage infiltration of freshwater along 'leaky' faults. The study shows that the Spiro sandstone locally retained excellent porosities despite deep burial and thermal conditions that correspond to the zone of incipient very low grade metamorphism.

Environmental Assessment: Installation Development at Vance Air Force Base, Oklahoma

DTIC Science & Technology

2007-04-01

intensity, frequency, and duration. Sound is created by acoustic energy, which produces minute pressure waves that travel through a medium, like...acoustic energy increases, the intensity or amplitude of these pressure waves increase, and the ear senses louder noise. The unit used to measure the...shale, siltstone, sandstone, limestone, and dolomite ranging in age from Cambrian-Ordovician through Permian. These sedimentary units rest upon the Pre

Sequence stratigraphy of the Upper Cambrian (Furongian; Jiangshanian and Sunwaptan) Tunnel City Group, Upper Mississippi Valley: Transgressing assumptions of cratonic flooding

USGS Publications Warehouse

Eoff, Jennifer D.

2014-01-01

New data from detailed measured sections permit comprehensive analysis of the sequence framework of the Furongian (Upper Cambrian; Jiangshanian and Sunwaptan stages) Tunnel City Group (Lone Rock Formation and Mazomanie Formation) of Wisconsin and Minnesota. The sequence-stratigraphic architecture of the lower part of the Sunwaptan Stage at the base of the Tunnel City Group, at the contact between the Wonewoc Formation and Lone Rock Formation, records the first part of complex polyphase flooding (Sauk III) of the Laurentian craton, at a scale smaller than most events recorded by global sea-level curves. Flat-pebble conglomerate and glauconite document transgressive ravinement and development of a condensed section when creation of accommodation exceeded its consumption by sedimentation. Thinly-bedded, fossiliferous sandstone represents the most distal setting during earliest highstand. Subsequent deposition of sandstone characterized by hummocky or trough cross-stratification records progradational pulses of shallower, storm- and wave-dominated environments across the craton before final flooding of Sauk III commenced with carbonate deposition during the middle part of the Sunwaptan Stage. Comparison of early Sunwaptan flooding of the inner Laurentian craton to published interpretations from other parts of North America suggests that Sauk III was not a single, long-term accommodation event as previously proposed.

DOE Office of Scientific and Technical Information (OSTI.GOV)

McCollum, L.B.; Buchanan, J.P.; McCollum, M.B.

The Antler orogeny is a textbook example of a Paleozoic mountain building and crustal shortening event in western North America. A relatively complex geologic history of the type Antler at Battle Mountain, Nevada, is interpreted as distinct thrust plates of Lower Cambrian Scott Canyon Formation, Upper Cambrian Harmony Sandstone, and Ordovician Valmy Formation, overlain unconformably by the Middle Pennsylvanian Battle Formation. Mississippian crustal deformation and emplacement of the Roberts Mountain thrust have previously been thought to characterize the Antler orogen. Detailed sedimentology studies of the Scott Canyon and Harmony, and the relationship with the overlying Battle Formation at the typemore » section of the Antler orogeny, cast doubt on the previously accepted geologic history. The Scott Canyon is an interbedded sequence of pillow basalts, Late Devonian radiolarian cherts, and mudstone debris flows with numerous limestone olistoliths, many containing undescribed archaeocyathid fauna. The contact of the Harmony with the Battle Formation appears channeled, but otherwise conformable, and the Battle has been interpreted as an alluvial fan facies. The paleoenvironmental interpretation of these sediments is that the Scott Canyon was deposited upon a Late Devonian active continental margin setting, with prograding fan deposits of the Harmony Sandstone, overlain by Middle Pennsylvanian fanglomerates of the Battle Formation. This conformable sequence appears to preclude any major uplift within the type Antler orogen.« less

Facies heterogeneity, pay continuity, and infill potential in barrier-island, fluvial, and submarine fan reservoirs: examples from the Texas Gulf Coast and Midland basins

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ambrose, W.A.; Tyler, N.

1989-03-01

Three reservoirs representing different depositional environments - barrier island (West Ranch field, south-central Texas), fluvial (La Gloria field, south Texas), and submarine fan (Spraberry trend, Midland basin) - illustrate variations in reservoir continuity. Pay continuity methods based on facies geometry and variations in permeability and thickness between wells can quantify reservoir heterogeneity in each of these examples. Although barrier-island reservoirs are relatively homogeneous, West Ranch field contains wide (1000-5000 ft or 300-1500 m) dip-parallel belts of lenticular inlet-fill facies that disrupt reservoir continuity in the main barrier-core facies. Other reservoir compartments in West Ranch field are in flood-tidal delta depositsmore » partly encased in lagoonal mudstones updip of the barrier core. Fluvial reservoirs have a higher degree of internal complexity than barrier-island reservoirs. In La Gloria field, reservoirs exhibit significant heterogeneity in the form of numerous sandstone stringers bounded vertically and laterally by thin mudstone layers. Successful infill wells in La Gloria field contact partly drained reservoir compartments in splay deposits that pinch out laterally into flood-plain mudstones. Recompletions in vertically isolated sandstone stringers in La Gloria field contact other reservoir compartments. Submarine fan deposits are extremely heterogeneous and may have the greatest potential for infill drilling to tap isolated compartments in clastic reservoirs. The Spraberry trend contains thin discontinuous reservoir sandstones deposited in complex mid-fan channels. Although facies relationships in Spraberry reservoirs are similar to those in fluvial reservoirs in La Gloria field, individual pay stringers are thinner and more completely encased in low-permeability mudstone facies.« less

Multiphase Flow Characteristics of Heterogeneous Rocks From CO2 Storage Reservoirs in the United Kingdom

NASA Astrophysics Data System (ADS)

Reynolds, Catriona A.; Blunt, Martin J.; Krevor, Samuel

2018-02-01

We have studied the impact of heterogeneity on relative permeability and residual trapping for rock samples from the Bunter sandstone of the UK Southern North Sea, the Ormskirk sandstone of the East Irish Sea, and the Captain sandstone of the UK Northern North Sea. Reservoir condition CO2-brine relative permeability measurements were made while systematically varying the ratio of viscous to capillary flow potential, across a range of flow rates, fractional flow, and during drainage and imbibition displacement. This variation resulted in observations obtained across a range of core-scale capillary number 0.2

Depositional environments and sand body morphologies of the muddy sandstones at Kitty Field, Powder River Basin, Wyoming

DOE Office of Scientific and Technical Information (OSTI.GOV)

Larberg, G.M.B.

1980-01-01

Lower Cretaceous muddy sandstones form a stratigraphic trap at Kitty Field, Campbell County, Wyoming. Porosity and permeability are generally low, but the best reservoir develop maximum effective porosity of 17% and maximum permeability of 442 md. Reservoirs sandstones average less than 15 ft and rarely exceed 30 ft in thickness. Ultimate recovery from the field is estimated at 23 million bbl. Based on electric log character, 4 easily recognizable zones within the muddy interval at Kitty were numbered one through 4 in slabbed cores and petrographic analyses of selected core samples, suggest that sandstones in the second, third, and fourthmore » muddy zones were deposited as part of a sequence associated with the overall transgression of the lower Cretaceous sea. Fourth zone sandstones are fluvial in origin, and were deposited in lows on the unconformable surface of the underlying skull creek shale. 18 references.« less

Determination techniques of Archie’s parameters: a, m and n in heterogeneous reservoirs

NASA Astrophysics Data System (ADS)

Mohamad, A. M.; Hamada, G. M.

2017-12-01

The determination of water saturation in a heterogeneous reservoir is becoming more challenging, as Archie’s equation is only suitable for clean homogeneous formation and Archie’s parameters are highly dependent on the properties of the rock. This study focuses on the measurement of Archie’s parameters in carbonate and sandstone core samples around Malaysian heterogeneous carbonate and sandstone reservoirs. Three techniques for the determination of Archie’s parameters a, m and n will be implemented: the conventional technique, core Archie parameter estimation (CAPE) and the three-dimensional regression technique (3D). By using the results obtained by the three different techniques, water saturation graphs were produced to observe the symbolic difference of Archie’s parameter and its relevant impact on water saturation values. The difference in water saturation values can be primarily attributed to showing the uncertainty level of Archie’s parameters, mainly in carbonate and sandstone rock samples. It is obvious that the accuracy of Archie’s parameters has a profound impact on the calculated water saturation values in carbonate sandstone reservoirs due to regions of high stress reducing electrical conduction resulting from the raised electrical heterogeneity of the heterogeneous carbonate core samples. Due to the unrealistic assumptions involved in the conventional method, it is better to use either the CAPE or 3D method to accurately determine Archie’s parameters in heterogeneous as well as homogeneous reservoirs.

Reservoir heterogeneity in Carboniferous sandstone of the Black Warrior basin. Final report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kugler, R.L.; Pashin, J.C.; Carroll, R.E.

1994-04-01

Although oil production in the Black Warrior basin of Alabama is declining, additional oil may be produced through improved recovery strategies, such as waterflooding, chemical injection, strategic well placement, and infill drilling. High-quality characterization of reservoirs in the Black Warrior basin is necessary to utilize advanced technology to recover additional oil and to avoid premature abandonment of fields. This report documents controls on the distribution and producibility of oil from heterogeneous Carboniferous reservoirs in the Black Warrior basin of Alabama. The first part of the report summarizes the structural and depositional evolution of the Black Warrior basin and establishes themore » geochemical characteristics of hydrocarbon source rocks and oil in the basin. This second part characterizes facies heterogeneity and petrologic and petrophysical properties of Carter and Millerella sandstone reservoirs. This is followed by a summary of oil production in the Black Warrior basin and an evaluation of seven improved-recovery projects in Alabama. In the final part, controls on the producibility of oil from sandstone reservoirs are discussed in terms of a scale-dependent heterogeneity classification.« less

Well logging evaluation of water-flooded layers and distribution rule of remaining oil in marine sandstone reservoirs of the M oilfield in the Pearl River Mouth basin

NASA Astrophysics Data System (ADS)

Li, Xiongyan; Qin, Ruibao; Gao, Yunfeng; Fan, Hongjun

2017-03-01

In the marine sandstone reservoirs of the M oilfield the water cut is up to 98%, while the recovery factor is only 35%. Additionally, the distribution of the remaining oil is very scattered. In order to effectively assess the potential of the remaining oil, the logging evaluation of the water-flooded layers and the distribution rule of the remaining oil are studied. Based on the log response characteristics, the water-flooded layers can be qualitatively identified. On the basis of the mercury injection experimental data of the evaluation wells, the calculation model of the initial oil saturation is built. Based on conventional logging data, the evaluation model of oil saturation is established. The difference between the initial oil saturation and the residual oil saturation can be used to quantitatively evaluate the water-flooded layers. The evaluation result of the water-flooded layers is combined with the ratio of the water-flooded wells in the marine sandstone reservoirs. As a result, the degree of water flooding in the marine sandstone reservoirs can be assessed. On the basis of structural characteristics and sedimentary environments, the horizontal and vertical water-flooding rules of the different types of reservoirs are elaborated upon, and the distribution rule of the remaining oil is disclosed. The remaining oil is mainly distributed in the high parts of the structure. The remaining oil exists in the top of the reservoirs with good physical properties while the thickness of the remaining oil ranges from 2-5 m. However, the thickness of the remaining oil of the reservoirs with poor physical properties ranges from 5-8 m. The high production of some of the drilled horizontal wells shows that the above distribution rule of the remaining oil is accurate. In the marine sandstone reservoirs of the M oilfield, the research on the well logging evaluation of the water-flooded layers and the distribution rule of the remaining oil has great practical significance to the prediction of the distribution of the remaining oil and the optimization of well locations.

Middle Jurassic incised valley fill (eolian/estuarine) and nearshore marine petroleum reservoirs, Powder River Basin

USGS Publications Warehouse

Ahlbrandt, T.S.; Fox, J.E.

1997-01-01

Paleovalleys incised into the Triassic Spearfish Formation (Chugwater equivalent) are filled with a vertical sequence of eolian, estuarine, and marine sandstones of the Middle Jurassic (Bathonian age) Canyon Springs Sandstone Member of the Sundance Formation. An outcrop exemplifying this is located at Red Canyon in the southern Black Hills, Fall River County, South Dakota. These paleovalleys locally have more than 300 ft of relief and are as much as several miles wide. Because they slope in a westerly direction, and Jurassic seas transgressed into the area from the west there was greater marine-influence and more stratigraphic complexity in the subsurface, to the west, as compared to the Black Hills outcrops. In the subsurface two distinctive reservoir sandstone beds within the Canyon Springs Sandstone Member fill the paleovalleys. These are the eolian lower Canyon Springs unit (LCS) and the estuarine upper Canyon Springs unit (UCS), separated by the marine "Limestone Marker" and estuarine "Brown Shale". The LCS and UCS contain significant proven hydrocarbon reservoirs in Wyoming (about 500 MMBO in-place in 9 fields, 188 MMBO produced through 1993) and are prospective in western South Dakota, western Nebraska and northern Colorado. Also prospective is the Callovian-age Hulett Sandstone Member which consists of multiple prograding shoreface to foreshore parasequences, as interpreted from the Red Canyon locality. Petrographic, outcrop and subsurface studies demonstrate the viability of both the Canyon Springs Sandstone and Hulett Sandstone members as superior hydrocarbon reservoirs in both stratigraphic and structural traps. Examples of fields with hydrocarbon production from the Canyon Springs in paleovalleys include Lance Creek field (56 MMBO produced) and the more recently discovered Red Bird field (300 MBO produced), both in Niobrara County, Wyoming. At Red Bird field the primary exploration target was the Pennsylvanian "Leo sands" of the Minnelusa Formation, and production from the Canyon Springs was not anticipated. Canyon Springs reservoirs are easily bypassed because they are relatively unconsolidated, underpressured, low-resistivity, and difficult to evaluate from petrophysics, drill-stem tests, or well cuttings.

Sequence stratigraphic controls on reservoir characterization and architecture: case study of the Messinian Abu Madi incised-valley fill, Egypt

NASA Astrophysics Data System (ADS)

Abdel-Fattah, Mohamed I.; Slatt, Roger M.

2013-12-01

Understanding sequence stratigraphy architecture in the incised-valley is a crucial step to understanding the effect of relative sea level changes on reservoir characterization and architecture. This paper presents a sequence stratigraphic framework of the incised-valley strata within the late Messinian Abu Madi Formation based on seismic and borehole data. Analysis of sand-body distribution reveals that fluvial channel sandstones in the Abu Madi Formation in the Baltim Fields, offshore Nile Delta, Egypt, are not randomly distributed but are predictable in their spatial and stratigraphic position. Elucidation of the distribution of sandstones in the Abu Madi incised-valley fill within a sequence stratigraphic framework allows a better understanding of their characterization and architecture during burial. Strata of the Abu Madi Formation are interpreted to comprise two sequences, which are the most complex stratigraphically; their deposits comprise a complex incised valley fill. The lower sequence (SQ1) consists of a thick incised valley-fill of a Lowstand Systems Tract (LST1)) overlain by a Transgressive Systems Tract (TST1) and Highstand Systems Tract (HST1). The upper sequence (SQ2) contains channel-fill and is interpreted as a LST2 which has a thin sandstone channel deposits. Above this, channel-fill sandstone and related strata with tidal influence delineates the base of TST2, which is overlain by a HST2. Gas reservoirs of the Abu Madi Formation (present-day depth ˜3552 m), the Baltim Fields, Egypt, consist of fluvial lowstand systems tract (LST) sandstones deposited in an incised valley. LST sandstones have a wide range of porosity (15 to 28%) and permeability (1 to 5080mD), which reflect both depositional facies and diagenetic controls. This work demonstrates the value of constraining and evaluating the impact of sequence stratigraphic distribution on reservoir characterization and architecture in incised-valley deposits, and thus has an important impact on reservoir quality evolution in hydrocarbon exploration in such settings.

Stratigraphic Framework and Depositional Sequences in the Lower Silurian Regional Oil and Gas Accumulation, Appalachian Basin: From Licking County, Ohio, to Fayette County, West Virginia

USGS Publications Warehouse

Ryder, Robert T.

2006-01-01

The Lower Silurian regional oil and gas accumulation was named by Ryder and Zagorski (2003) for a 400-mile (mi)-long by 200-mi-wide hydrocarbon accumulation in the central Appalachian basin of the Eastern United States and Ontario, Canada. From the early 1880s to 2000, approximately 300 to 400 million barrels of oil and eight to nine trillion cubic feet of gas have been produced from the Lower Silurian regional oil and gas accumulation (Miller, 1975; McCormac and others, 1996; Harper and others, 1999). Dominant reservoirs in the regional accumulation are the Lower Silurian 'Clinton' and Medina sandstones in Ohio and westernmost West Virginia and coeval rocks in the Lower Silurian Medina Group (Grimsby Sandstone (Formation) and Whirlpool Sandstone) in northwestern Pennsylvania and western New York. A secondary reservoir is the Upper Ordovician(?) and Lower Silurian Tuscarora Sandstone in central Pennsylvania and central West Virginia, a more proximal eastern facies of the 'Clinton' sandstone and Medina Group (Yeakel, 1962; Cotter, 1982, 1983; Castle, 1998). The Lower Silurian regional oil and gas accumulation is subdivided by Ryder and Zagorski (2003) into the following three parts: (1) an easternmost part consisting of local gas-bearing sandstone units in the Tuscarora Sandstone that is included with the basin-center accumulation; (2) an eastern part consisting predominantly of gas-bearing 'Clinton' sandstone-Medina Group sandstones that have many characteristics of a basin-center accumulation (Davis, 1984; Zagorski, 1988, 1991; Law and Spencer, 1993); and (3) a western part consisting of oil- and gas-bearing 'Clinton' sandstone-Medina Group sandstones that is a conventional accumulation with hybrid features of a basin-center accumulation (Zagorski, 1999). With the notable exception of the offshore part of Lake Erie (de Witt, 1993), the supply of oil and (or) gas in the hybrid-conventional part of the regional accumulation continues to decline because of the many wells drilled there since the late 1880s. However, new gas and local oil continues to be discovered in the deeper basin-center part (Zagorski, 1991; Pees, 1994; Petroleum Information Corporation, 1994). In general, only small quantities of gas have been produced from the Tuscarora Sandstone fields because of their generally poor reservoir quality and because of the low energy (Btu) content of the gas (Avary, 1996). Although fracture porosity is the dominant porosity type in the Tuscarora Sandstone gas reservoirs (Avary, 1996), there are several fields, such as Indian Creek, where intergranular porosity seems to be important (Bruner, 1983; Castle and Byrnes, 2005). In order to better understand the character and origin of the Lower Silurian regional oil and gas accumulation and its component parts, six cross sections were drawn through the Lower Silurian strata in parts of New York, Ohio, Pennsylvania, and West Virginia. The locations of all six cross sections are shown on sheet 2 (figs. 1 and 2) of this report. Each cross section shows the stratigraphic framework, depositional setting, sequence stratigraphy, and hydrocarbon-producing intervals of the Lower Silurian sandstone reservoirs and adjoining strata. Cross section F-F' presented here is about 215 mi long and trends northwestward, approximately normal to the depositional strike of the Lower Silurian sandstone system, and extends through large stretches of the basin-center and hybrid-conventional parts of the Lower Silurian regional oil and gas accumulation.

The role of sandstone in the development of an Ozark karst system, south-central Missouri

USGS Publications Warehouse

Orndorff, R.C.; Weary, D.J.; Harrison, R.W.

2006-01-01

Cave, spring, and sinkhole development in the Ozarks of south-central Missouri is placed in a geologic framework through detailed geologic mapping. Geologic mapping shows that initial dissolution and inception of cave development is concentrated just beneath sandstone beds within Upper Cambrian and Lower Ordovician dolostone. Although rocks of the Ozarks have systematic and pervasive vertical joints, the development of karst conduits is controlled by bedding planes and stratigraphic variability. In the Salem Plateau of south-central Missouri, sinkholes occur in the lower part of the Ordovician Roubidoux Formation, where sinkholes are rimmed with and contain sandstone that has collapsed into voids in the underlying Ordovician Gasconade Dolomite. Cave diving by the Ozark Cave Diving Alliance into Alley Spring, a large (average flow 3.7 m3/s) spring along the Jacks Fork in the Ozark National Scenic Riverways, shows that although the spring discharges from the middle part of the Gasconade, the source of water is a cave passage just beneath the Gunter Sandstone Member of the Gasconade Dolomite. Artesian conditions cause the upward movement of groundwater from cavernous dolostone beneath the sandstone aquitards to the large springs. We hypothesize that sandstone, which is largely impermeable due to silica cementation, acts as a confining unit where hydraulic pressure, combined with mixing of water of differing chemistry, increases dissolution in the underlying dolostone beds. ?? 2006 Geological Society of America.

Facies-controlled fluid migration patterns and subsequent reservoir collapse by depressurization - the Entrada Sandstone, Utah

NASA Astrophysics Data System (ADS)

Sundal, A.; Skurtveit, E.; Midtkandal, I.; Hope, I.; Larsen, E.; Kristensen, R. S.; Braathen, A.

2016-12-01

The thick and laterally extensive Middle Jurassic Entrada Sandstone forms a regionally significant reservoir both in the subsurface and as outcrops in Utah. Individual layers of fluvial sandstone within otherwise fine-grained aeolian dunes and silty inter-dune deposits of the Entrada Earthy Member are of particular interest as CO2 reservoir analogs to study injectivity, reservoir-caprock interaction and bypass systems. Detailed mapping of facies and deformation structures, including petrographic studies and core plug tests, show significant rock property contrasts between layers of different sedimentary facies. Beds representing fluvial facies appear as white, medium-grained, well-sorted and cross-stratified sandstone, displaying high porosity, high micro-scale permeability, low tensile strength, and low seismic velocity. Subsequent to deposition, these beds were structurally deformed and contain a dense network of deformation bands, especially in proximity to faults and injectites. Over- and underlying low-permeability layers of inter-dune aeolian facies contain none or few deformation bands, display significantly higher rock strengths and high seismic velocities compared to the fluvial inter-beds. Permeable units between low-permeability layers are prone to become over-pressured during burial, and the establishment of fluid escape routes during regional tectonic events may have caused depressurization and selective collapse of weak layers. Through-cutting, vertical sand pipes display large clasts of stratified sandstone suspended in remobilized sand matrix, and may have served as permeable fluid conduits and pressure vents before becoming preferentially cemented and plugged. Bleached zones around faults and fractures throughout the succession indicate leakage and migration of reducing fluids. The fluvial beds are porous and would appear in wireline logs and seismic profiles as excellent reservoirs; whereas due to dense populations of deformation bands they may in fact display reduced horizontal and vertical permeability locally. Facies-related differences in geomechanical properties, pressure distribution and selective structural collapse have significant implications for injectivity and reservoir behavior.

Flow units classification for geostatisitical three-dimensional modeling of a non-marine sandstone reservoir: A case study from the Paleocene Funing Formation of the Gaoji Oilfield, east China

NASA Astrophysics Data System (ADS)

Zhang, Penghui; Zhang, Jinliang; Wang, Jinkai; Li, Ming; Liang, Jie; Wu, Yingli

2018-05-01

Flow units classification can be used in reservoir characterization. In addition, characterizing the reservoir interval into flow units is an effective way to simulate the reservoir. Paraflow units (PFUs), the second level of flow units, are used to estimate the spatial distribution of continental clastic reservoirs at the detailed reservoir description stage. In this study, we investigate a nonroutine methodology to predict the external and internal distribution of PFUs. The methodology outlined enables the classification of PFUs using sandstone core samples and log data. The relationships obtained between porosity, permeability and pore throat aperture radii (r35) values were established for core and log data obtained from 26 wells from the Funing Formation, Gaoji Oilfield, Subei Basin, China. The present study refines predicted PFUs at logged (0.125-m) intervals, whose scale is much smaller than routine methods. Meanwhile, three-dimensional models are built using sequential indicator simulation to characterize PFUs in wells. Four distinct PFUs are classified and located based on the statistical methodology of cluster analysis, and each PFU has different seepage ability. The results of this study demonstrate the obtained models are able to quantify reservoir heterogeneity. Due to different petrophysical characteristics and seepage ability, PFUs have a significant impact on the distribution of the remaining oil. Considering these allows a more accurate understanding of reservoir quality, especially within non-marine sandstone reservoirs.

Cyclicity and reservoir properties of Lower-Middle Miocene sediments of South Kirinsk oil and gas field

NASA Astrophysics Data System (ADS)

Kurdina, Nadezhda

2017-04-01

Exploration and additional exploration of oil and gas fields, connected with lithological traps, include the spreading forecast of sedimentary bodies with reservoir and seal properties. Genetic identification and forecast of geological bodies are possible in case of large-scale studies, based on the study of cyclicity, structural and textural features of rocks, their composition, lithofacies and depositional environments. Porosity and permeability evaluation of different reservoir groups is also an important part. Such studies have been successfully completed for productive terrigenous Dagi sediments (Lower-Middle Miocene) of the north-eastern shelf of Sakhalin. In order to identify distribution of Dagi reservoirs with different properties in section, core material of the one well of South Kirinsk field has been studied (depth interval from 2902,4 to 2810,5 m). Productive Dagi deposits are represented by gray-colored sandstones with subordinate siltstones and claystones (total thickness 90,5 m). Analysis of cyclicity is based on the concepts of Vassoevich (1977), who considered cycles as geological body, which is the physical result of processes that took place during the sedimentation cycle. Well section was divided into I-X units with different composition and set of genetic features due to layered core description and elementary cyclites identification. According to description of thin sections and results of cylindrical samples porosity and permeability studies five groups of reservoirs were determined. There are coarse-grained and fine-coarse-grained sandstones, fine-grained sandstones, fine-grained silty sandstones, sandy siltstones and siltstones. It was found, in Dagi section there is interval of fine-coarse-grained and coarse-grained sandstones with high petrophysical properties: permeability 3000 mD, porosity more than 25%, but rocks with such properties spread locally and their total thickness is 6 meters only. This interval was described in the IV unit. In the IV unit lower cyclites elements consist of conglomerates and upper by above-mentioned sandstones. The appearance of conglomerates indicates a coastal-marine depositional environment. The most widely spread reservoir type of Dagi section is fine-grained sandstones and fine-grained silty sandstones with porosity value 22-24% and permeability 100-500 mD. They present the lower elements of cyclites in I, II, VII and VIII units. These sandstones contain fragments of pelecypods shells and marks of bioturbation. There are long (up to 1 m) vertical burrows, which means shallow basin and a weak hydrodynamics. The most clayey section parts (units V and VI) that are presented by wavy-horizontal interlayering of clayey siltstones and clayey-silty rocks contain reservoirs but of poorer petrophysical properties. Sandy siltstones with 14-23% porosity and permeability value 1-10 mD. In general, units V and VI are characterized by conditions of active hydrodynamic and sandy siltstones appearance - with additional supply of sediments with temporary flows. Presence of different reservoir groups in Dagi section is controlled by sedimentation factors and reflects succession of vertical genetic series. According to the preliminary assessment, rocks accumulated predominantly in coastal-marine and shallow-marine environment. Frequent change of lithotypes in Dagi section in well 5 of South Kirinsk field indicates significant changes of depositional environment whose diagnostic and identification are an integral part of the field exploration works.

Origin of the Nubian and similar sandstones

USGS Publications Warehouse

McKee, E.D.

1963-01-01

The Nubian Sandstone and similar sandstone bodies exposed across much of northern Africa and adjoining parts of Asia are characteristically formed of clean sand that is conspicuously cross stratified throughout. Such sandstone, here called Nubian-type sandstone, ranges from Cambrian through Cretaceous in age and its genesis has been interpreted in many ways. Studies of its primary structures, and of the direction of sand transport, based on statistical measurements of foreset dip directions, have contributed new data on its genesis. By far the most common structure in Nubian-type sandstone is a medium-scale planar-type cross stratification in which sets of evenly dipping cross beds are bounded by essentially flat-lying top and bottom surfaces to form tabular bodies. Other less numerous but typical structures are large-scale, truncated-wedge cross strata, trough-type cross strata, intraformational recumbent folds, small-scale ripple laminae, and dipping sets of tabular-planar cross beds. An analysis of these structures suggests that in the typical Nubian Sandstone of Cretaceous age eolian deposits are not represented and normal marine types probably also are lacking; flood plain, pond or lagoon, and other continental and marginal environments are indicated. In the Carboniferous rocks of Sinai Peninsula some beach sandstone and possibly some eolian, in addition to the types described, form part of the sequence. Direction of sand transport, as determined from cross-bed dips, was northerly in the Cretaceous Nubian of Libya, Sudan, and Egypt; easterly in the Jurassic Adigrat of Ethiopia; westerly in the Carboniferous of Sinai; northwesterly in the early Paleozoic of Jordan. ?? 1963 Ferdinand Enke Verlag Stuttgart.

Distribution and geological sources of selenium in environmental materials in Taoyuan County, Hunan Province, China.

PubMed

Ni, Runxiang; Luo, Kunli; Tian, Xinglei; Yan, Songgui; Zhong, Jitai; Liu, Maoqiu

2016-06-01

The selenium (Se) distribution and geological sources in Taoyuan County, China, were determined by using hydride generation atomic fluorescence spectrometry on rock, soil, and food crop samples collected from various geological regions within the county. The results show Se contents of 0.02-223.85, 0.18-7.05, and 0.006-5.374 mg/kg in the rock, soil, and food crops in Taoyuan County, respectively. The region showing the highest Se content is western Taoyuan County amid the Lower Cambrian and Ediacaran black rock series outcrop, which has banding distributed west to east. A relatively high-Se environment is found in the central and southern areas of Taoyuan County, where Quaternary Limnetic sedimentary facies and Neoproterozoic metamorphic volcanic rocks outcrop, respectively. A relatively low-Se environment includes the central and northern areas of Taoyuan County, where Middle and Upper Cambrian and Ordovician carbonate rocks and Cretaceous sandstones and conglomerates outcrop. These results indicate that Se distribution in Taoyuan County varies markedly and is controlled by the Se content of the bedrock. The Se-enriched Lower Cambrian and Ediacaran black rock series is the primary source of the seleniferous environment observed in Taoyuan County. Potential seleniferous environments are likely to be found near outcrops of the Lower Cambrian and Ediacaran black rock series in southern China.

Some aspects of lithological and exogenic control of sandstone morphology, the Świętokrzyskie (Holy Cross) Mts. case study, Poland

NASA Astrophysics Data System (ADS)

Urban, Jan; Górnik, Marek

2017-10-01

Various morphologies of cliffs built of different quartzose rocks in the Świętokrzyskie (Holy Cross) Mts. (upland region, central Poland) - from Cambrian quartzites and Devonian quartzitic sandstones to Triassic and Jurassic porous sandstones - were described in order to examine the constraints of their lithological and spatial occurrence. The quantitative study of the occurrence of these morphologies on cliffs makes it possible to distinguish two principal groups of morphologies: angular relief produced by rock splitting (crumbling), typical of quartzites indurated in silica and of open porosity less than 1.5%, and morphologies developed due to granular disintegration and exfoliation of sandstones of open porosity higher than 1.5%. Among the relief types of this second group, morphology reflecting sedimentary and diagenetic structures as well as smooth surfaces are the most common and are referred to sandstones of a wide range of porosity, whereas honeycombs and surfaces suffering fast granular decay and scaling are characteristic of rocks of specific porosity (respectively: 5-8% and 3.5-8%). The occurrence of honeycombs on rock surfaces is also conditioned by exogenic factors: sun, wind and rain, since this morphology tends to occur on cliffs with aspects ranging from south-east, through south, to west-north-west.

DHI evaluation by combining rock physics simulation and statistical techniques for fluid identification of Cambrian-to-Cretaceous clastic reservoirs in Pakistan

NASA Astrophysics Data System (ADS)

Ahmed, Nisar; Khalid, Perveiz; Shafi, Hafiz Muhammad Bilal; Connolly, Patrick

2017-10-01

The use of seismic direct hydrocarbon indicators is very common in exploration and reservoir development to minimise exploration risk and to optimise the location of production wells. DHIs can be enhanced using AVO methods to calculate seismic attributes that approximate relative elastic properties. In this study, we analyse the sensitivity to pore fluid changes of a range of elastic properties by combining rock physics studies and statistical techniques and determine which provide the best basis for DHIs. Gassmann fluid substitution is applied to the well log data and various elastic properties are evaluated by measuring the degree of separation that they achieve between gas sands and wet sands. The method has been applied successfully to well log data from proven reservoirs in three different siliciclastic environments of Cambrian, Jurassic, and Cretaceous ages. We have quantified the sensitivity of various elastic properties such as acoustic and extended elastic (EEI) impedances, elastic moduli ( K sat and K sat- μ), lambda-mu-rho method ( λρ and μρ), P-to-S-wave velocity ratio ( V P/ V S), and Poisson's ratio ( σ) at fully gas/water saturation scenarios. The results are strongly dependent on the local geological settings and our modeling demonstrates that for Cambrian and Cretaceous reservoirs, K sat- μ, EEI, V P/ V S, and σ are more sensitive to pore fluids (gas/water). For the Jurassic reservoir, the sensitivity of all elastic and seismic properties to pore fluid reduces due to high overburden pressure and the resultant low porosity. Fluid indicators are evaluated using two metrics: a fluid indicator coefficient based on a Gaussian model and an overlap coefficient which makes no assumptions about a distribution model. This study will provide a potential way to identify gas sand zones in future exploration.

Alxa Block Provenance of Ediacaran (Sinian) Sediments in the Helanshan Area: Constraints from Hf Isotopes and U-Pb Geochronology of Detrital Zircons

NASA Astrophysics Data System (ADS)

Xiaopeng, D.

2016-12-01

The tectonic relationship between the Alxa Block and the North China Craton has long been controversial. The Helanshan area lies at the western margin of the Ordos Block and east of the Alxa Block (Fig.a), and it contains rocks of the lower Zhengmuguan and upper Tuerkeng formations that belong to the Ediacaran system. The Zhengmuguan Formation is made up of abyssal facies rocks including dolomite and glacial conglomerate with dropstones, and the Tuerkeng Formation consists of silty slate of the neritic facies. A discontinuity marks the boundary between the Tuerkeng Formation and the Early Cambrian Suyukou Formation, which is composed mainly of pebbly sandstone towards the base and sandstone towards the top, representing a change in sedimentary facies from terrestrial to littoral.The Neoproterozoic U-Pb ages of zircons from the Ediacaran and Early Cambrian sediments peak at 818 ± 4 Ma (n = 88) and 905 ± 8 Ma (n = 20), consistent with the Neoproterozoic age peaks found in the Precambrian basement of the Alxa Block(Fig.b). There are few Neoproterozoic zircons in the Neoproterozoic strata of the Langshan area, and there are no reports of Neoproterozoic zircons in the Zhuozishan area, northwest of Helanshan, or in the western margin of the neighboring Ordos Basin. A number of Neoproterozoic zircons are found in the Middle Cambrian to Middle Ordovician strata of the Niushoushan area. And while Niushoushan is part of the Hexi Corridor, it did not amalgamate with the NCC before the Early-Middle Cambrian. Therefore, the Neoproterozoic and Early Cambrian sediments in Helanshan record information about Neoproterozoic magmatic events in the Alxa Block, and indicate an Alxa Block provenance(Fig.c).The Hf isotopic characteristics of the Neoproterozoic zircons from the Ediacaran Zhengmuguan Formation in the Helanshan area (eHf(t) = -7.812 to 3.274, TDMC = 2211-1578 Ma, n = 10) are similar to those Neoproterozoic igneous zircons from the Langshan area (eHf(t) = -1.105 to 5.928, TDMC = 1.75-1.38 Ga, n = 23) and Bayinnuoergong area in the Alxa Block(Fig.d). The parental magmas had a long residency time in the crust. It seems, therefore, that in the late Neoproterozoic the provenance of rocks in the Helanshan area was the Alxa Block, and that the Alxa Block was already part of the North China Craton by the late Neoproterozoic.

Characterization of petroleum reservoirs in the Eocene Green River Formation, Central Uinta Basin, Utah

USGS Publications Warehouse

Morgan, C.D.; Bereskin, S.R.

2003-01-01

The oil-productive Eocene Green River Formation in the central Uinta Basin of northeastern Utah is divided into five distinct intervals. In stratigraphically ascending order these are: 1) Uteland Butte, 2) Castle Peak, 3) Travis, 4) Monument Butte, and 5) Beluga. The reservoir in the Uteland Butte interval is mainly lacustrine limestone with rare bar sandstone beds, whereas the reservoirs in the other four intervals are mainly channel and lacustrine sandstone beds. The changing depositional environments of Paleocene-Eocene Lake Uinta controlled the characteristics of each interval and the reservoir rock contained within. The Uteland Butte consists of carbonate and rare, thin, shallow-lacustrine sandstone bars deposited during the initial rise of the lake. The Castle Peak interval was deposited during a time of numerous and rapid lake-level fluctuations, which developed a simple drainage pattern across the exposed shallow and gentle shelf with each fall and rise cycle. The Travis interval records a time of active tectonism that created a steeper slope and a pronounced shelf break where thick cut-and-fill valleys developed during lake-level falls and rises. The Monument Butte interval represents a return to a gentle, shallow shelf where channel deposits are stacked in a lowstand delta plain and amalgamated into the most extensive reservoir in the central Uinta Basin. The Beluga interval represents a time of major lake expansion with fewer, less pronounced lake-level falls, resulting in isolated single-storied channel and shallow-bar sandstone deposits.

Central Antarctic provenance of Permian sandstones in Dronning Maud Land and the Karoo Basin: Integration of U Pb and TDM ages and host-rock affinity from detrital zircons

NASA Astrophysics Data System (ADS)

Veevers, J. J.; Saeed, A.

2007-12-01

In conjugate SE Africa and Antarctica, Early Permian sandstones of the Swartrant Formation of the Ellisras Basin, Vryheid Formation of the Karoo Basin, and Amelang Plateau Formation of Dronning Maud Land (DML) were deposited after Gondwanan glaciation on a westward paleoslope. We analysed detrital zircons for U-Pb ages by a laser ablation microprobe-inductively coupled plasma mass spectrometer (LAM-ICPMS) and attached age significance only to clusters of three or more overlapping analyses. We analysed Hf-isotope compositions by a multi-collector spectrometer (LAM-MC-ICPMS) and trace elements by electron microprobe (EMP) and ICPMS. These analyses indicate the rock type and source (whether crustal or juvenile mantle) of the host magma, and a "crustal" model age ( TDMC). The integrated analysis gives a more distinctive, and more easily interpreted, picture of crustal evolution in the provenance area than age data alone. Zircons from the Ellisras Basin are aged 2700-2540 Ma with minor populations about 2815 Ma and 2040 Ma, which correspond with the ages of the upslope parts of the proximal Kaapvaal Craton and Limpopo Belt. Mafic rock is the dominant host rock, and it reflects the Archean granite-greenstone terrane of the Kaapvaal Craton. The three Karoo Basin samples and the two DML samples have zircons with these common properties: (1) 1160-880 Ma, host magma mafic granitoid (< 65% SiO 2) derived from juvenile depleted mantle sources ( ɛHf positive) at 1.65 Ga and 1.35 Ga, with TDMC of 2.0-0.9 Ga; (2) 760 to 480 Ma, host magma granitoid and low-heavy rare earth element rock (?alkaline rock-carbonatite), derived from mixed crustal and juvenile depleted mantle sources ( ɛHf positive and negative) at 1.50 Ga and 1.35 Ga, with TDMC of 2.0-0.9 Ga. Together with similar detrital zircons in Triassic sandstone of SE Australia, these properties reflect those in upslope central Antarctica, indicating a provenance of ˜ 1000 Ma (Grenville) cratons embedded in 700-500 Ma (Pan-Gondwanaland) fold belts. Detrital zircons in Cambrian sediments of the Ellsworth-Whitmore Mountains block and Cambrian metasediments of the Welch Mountains with comparable properties suggest that the central Antarctic provenance operated also in the ˜ 500 Ma Cambrian.

Upper Cretaceous Shannon Sandstone Reservoirs, Powder River Basin, Wyoming: Evidence for organic acid diagenesis

DOE Office of Scientific and Technical Information (OSTI.GOV)

Hansley, P.L.; Nuccio, V.F.

Comparison of the petrology of shallow and deep oil reservoirs in the Upper Cretaceous Shannon Sandstone Beds of the Steele Member of the Cody Shale strongly suggests that organic acids have had a more significant impact on the diagenetic alteration of aluminosilicate grains and carbonate cements in the deep reservoirs than in the shallow reservoirs. In shallow reservoirs, detrital grains exhibit minor dissolution, sparse and small overgrowths, and secondary porosity created by dissolution of early calcite cement. However, deeper sandstones are characterized by extensive dissolution of detrital K-feldspar and detrital glauconite grains, and precipitation of abundant, large quartz and feldsparmore » overgrowths. Throughout the Shannon and Steele, dissolution of glauconite and degradation of kerogen were probably aided by clay mineral/organic catalysis, which caused simultaneous reduction of iron and oxidation of kerogen. This process resulted in release of ferrous iron and organic acids and was promoted in the deep reservoirs by higher formation temperatures accounting for more extensive dissolution of aluminosilicate grains. Carbonic acid produced from the dissolution of early calcite cement, decarboxylation of organic matter, and influx of meteoric water after Laramide uplift produced additional dissolution of cements and grains. Dissolution by organic acids and complexing by organic acid anions, however, best explain the intensity of diagenesis and absence of dissolution products in secondary pores and on etched surfaces of framework grains in deep reservoirs.« less

Nature, origin, and production characteristics of the Lower Silurian regional oil and gas accumulation, central Appalachian basin, United States

USGS Publications Warehouse

Ryder, R.; Zagorski, W.A.

2003-01-01

Low-permeability sandstones of the Lower Silurian regional oil and gas accumulation cover about 45,000 mi2 (117,000 km2) of the Appalachian basin and may contain as much as 30 tcf of recoverable gas resources. Major reservoirs consist of the "Clinton" sandstone and Medina Group sandstones. The stratigraphically equivalent Tuscarora Sandstone increases the area of the Lower Silurian regional accumulation (LSRA) by another 30,000 mi2 (78,000 km2). Approximately 8.7 tcf of gas and 400 million bbl of oil have been produced from the Clinton/Medina reservoirs since 1880. The eastern predominantly gas-bearing part of the LSRA is a basin-center gas accumulation, whereas the western part is a conventional oil and gas accumulation with hybrid features of a basin-center accumulation. The basin-center accumulations have pervasive gas saturation, water near irreducible saturation, and generally low fluid pressures. In contrast, the hybrid-conventional accumulations have less-pervasive oil and gas saturation, higher mobile-water saturation, and both normal and abnormally low fluid pressures. High mobile-water saturation in the hybrid-conventional reservoirs form the updip trap for the basin-center gas creating a broad transition zone, tens of miles wide, that has characteristics of both end-member accumulation types. Although the Tuscarora Sandstone part of the basin-center gas accumulation is pervasively saturated with gas, most of its constituent sandstone beds have low porosity and permeability. Commercial gas fields in the Tuscarora Sandstone are trapped in naturally fractured, faulted anticlines. The origin of the LSRA includes (1) generation of oil and gas from Ordovician black shales, (2) vertical migration through an overlying 1000-ft (305-m)-thick Ordovician shale; (3) abnormally high fluid pressure created by oil-to-gas transformation; (4) updip displacement of mobile pore water by overpressured gas; (5) entrapment of pervasive gas in the basin center; (6) postorogenic uplift and erosion, causing gas leakage and a marked reduction in fluid pressure. Most future natural-gas production in the Clinton/Medina sandstones is anticipated to come from the basin-center accumulation. The Tuscarora Sandstone has additional gas resources but typically low reservoir porosity and permeability, and the likelihood of low-energy (in British thermal units) gas reduce the incentive to explore for it.

Diagenetic controls on reservoir heterogeneity in St. Peter Sandstone, deep Michigan basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Barnes, D.A.; Turmelle, T.M.; Adam, R.

1989-03-01

The St. Peter Sandstone is a highly productive gas and condensate reservoir throughout the central part of the Michigan basin. Production occurs in several intervals: a laterally continuous zone at the top of the formation typified in the Woodville, Falmouth, and Rose City fields and less continuous intervals lower in the formation typified in the Ruwe Gulf zone of the Reed City field. Porosity is not limited to hydrocarbon productive zones, however. Diagenesis has dramatically modified primary mineralogy and textures in the formation. Dominant diagenetic components are quartz, dolomite, and clay authigenic cements, extensive chemical compaction, and pervasive mineral leaching.more » Their model for sandstone diagenesis is consistent throughout the basin. Variation in the significance of these diagenetic components is strongly templated by stratigraphically predictable facies variations within the St. Peter Sandstone.« less

Micro- and macro-scale petrophysical characterization of potential reservoir units from the Northern Israel

NASA Astrophysics Data System (ADS)

Haruzi, Peleg; Halisch, Matthias; Katsman, Regina; Waldmann, Nicolas

2016-04-01

Lower Cretaceous sandstone serves as hydrocarbon reservoir in some places over the world, and potentially in Hatira formation in the Golan Heights, northern Israel. The purpose of the current research is to characterize the petrophysical properties of these sandstone units. The study is carried out by two alternative methods: using conventional macroscopic lab measurements, and using CT-scanning, image processing and subsequent fluid mechanics simulations at a microscale, followed by upscaling to the conventional macroscopic rock parameters (porosity and permeability). Comparison between the upscaled and measured in the lab properties will be conducted. The best way to upscale the microscopic rock characteristics will be analyzed based the models suggested in the literature. Proper characterization of the potential reservoir will provide necessary analytical parameters for the future experimenting and modeling of the macroscopic fluid flow behavior in the Lower Cretaceous sandstone.

Is there a basin-centered gas accumulation in Cotton Valley Group Sandstones, Gulf Coast Basin, U.S.A.?

USGS Publications Warehouse

Bartberger, Charles E.; Dyman, Thaddeus S.; Condon, Steven M.

2002-01-01

The U.S. Geological Survey (USGS), in cooperation with the U.S. Department of Energy, is reevaluating the resource potential of selected domestic basin-centered gas accumulations. Basin-centered gas accumulations are characterized by presence of gas in extensive low-permeability (tight) reservoirs in which conventional seals and trapping mechanisms are absent, abnormally high or low reservoir pressures exist, and gas-water contacts are absent. In 1995, the USGS assessed one basin-centered gas play and two conventional plays within the trend of Jurassic and Cretaceous Cotton Valley Group fl uvial-deltaic and barrierisland/ strandplain sandstones across the onshore northern Gulf of Mexico Basin. Detailed evaluation of geologic and production data provides new insights into these Cotton Valley plays. Two Cotton Valley sandstone trends are identifi ed based on reservoir properties and gas-production characteristics. Transgressive blanket sandstones across northern Louisiana have relatively high porosity and permeability and do not require fracture stimulation to produce gas at commercial rates. South of this trend, and extending westward into eastern Texas, massive sandstones of the Cotton Valley trend exhibit low porosity and permeability and require fracture stimulation. The high permeability of Cotton Valley blanket sandstones is not conducive to the presence of basin-centered gas, but lowpermeability massive sandstones provide the type of reservoir in which basin-centered gas accumulations commonly occur. Data on source rocks, including burial and thermal history, are consistent with the interpretation of potential basincentered gas within Cotton Valley sandstones. However, pressure gradients throughout most of the blanket- and massivesandstone trends are normal or nearly normal, which is not characteristic of basin-centered gas accumulations. The presence of gas-water contacts in at least seven fi elds across the blanket-sandstone trend together with relatively high permeabilities and high gas-production rates without fracture stimulation indicate that fi elds in this trend are conventional. Within the tight massive-sandstone trend, permeability is suffi ciently low that gas-water transition zones are vertically extensive and gas-water contacts either have not been encountered or are poorly defi ned. With increasing depth through these transition zones, gas saturation decreases and water saturation increases until eventually gas saturations become suffi ciently low that, in terms of ultimate cumulative production, wells are noncommercial. Such progressive increase in water saturation with depth suggests that poorly defi ned gas-water contacts probably are present below the depth at which wells become noncommercial. The interpreted presence of gas-water contacts within the tight, Cotton Valley massive-sandstone trend suggests that gas accumulations in this trend, too, are conventional, and that a basin-centered gas accumulation does not exist within Cotton Valley sandstones in the northern Gulf Basin.

Deformation of Reservoir Sandstones by Elastic versus Inelastic Deformation Mechanisms

NASA Astrophysics Data System (ADS)

Pijnenburg, R.; Verberne, B. A.; Hangx, S.; Spiers, C. J.

2016-12-01

Hydrocarbon or groundwater production from sandstone reservoirs can result in surface subsidence and induced seismicity. Subsidence results from combined elastic and inelastic compaction of the reservoir due to a change in the effective stress state upon fluid extraction. The magnitude of elastic compaction can be accurately described using poroelasticity theory. However inelastic or time-dependent compaction is poorly constrained. Specifically, the underlying microphysical processes controlling sandstone compaction remain poorly understood. We use sandstones recovered by the field operator (NAM) from the Slochteren gas reservoir (Groningen, NE Netherlands) to study the importance of elastic versus inelastic deformation processes upon simulated pore pressure depletion. We conducted conventional triaxial tests under true in-situ conditions of pressure and temperature. To investigate the effect of applied differential stress (σ1 - σ3 = 0 - 50 MPa) and initial sample porosity (φi = 12 - 24%) on instantaneous and time-dependent inelastic deformation, we imposed multiple stages of axial loading and relaxation. The results show that inelastic strain develops at all stages of loading, and that its magnitude increases with increasing value of differential stress and initial porosity. The stress sensitivity of the axial creep strain rate and microstructural evidence suggest that inelastic compaction is controlled by a combination of intergranular slip and intragranular cracking. Intragranular cracking is shown to be more pervasive with increasing values of initial porosity. The results are consistent with a conceptual microphysical model, involving deformation by poro-elasticity combined with intergranular sliding and grain contact failure. This model aims to predict sandstone deformation behavior for a wide range of stress conditions.

Petrology and reservoir quality of the Gaikema Sandstone: Initial impressions

USGS Publications Warehouse

Helmold, Kenneth P.; Stanley, Richard G.

2015-01-01

The Division of Geological & Geophysical Surveys (DGGS) and Division of Oil & Gas (DOG) are currently conducting a study of the hydrocarbon potential of Cook Inlet basin (LePain and others, 2011). The Tertiary stratigraphic section of the basin includes coal-bearing units that are prolific gas reservoirs, particularly the Neogene sandstones. The Paleogene sandstones are locally prolific oil reservoirs that are sourced largely from the underlying Middle Jurassic Tuxedni Group. Several large structures act as hydrocarbon traps and the possibility exists for stratigraphic traps although this potential has not been fully exploited. As part of this study a significant number of Tertiary sandstones from the basin have been already collected and analyzed (Helmold and others, 2013). Recent field programs have shifted attention to the Mesozoic stratigraphic section to ascertain whether it contains potential hydrocarbon reservoirs. During the 2013 Cook Inlet field season, two days were spent on the Iniskin Peninsula examining outcrops of the Middle Jurassic Gaikema Sandstone along the south shore of Chinitna Bay (fig. 7-1). A stratigraphic section approximately 34 m in thickness was measured and a detailed description was initiated (Stanley and others, 2015), but due to deteriorating weather it was not possible to complete the description. During the 2014 field season two additional days were spent completing work on the Gaikema section. Analyses of thin sections from six of the samples collected in 2013 are available for incorporation in this report (table 7-1). Data from samples collected during the 2014 field season will be included in future reports.

Geology and log responses of the Rose Run sandstone in Randolph Township, Portage County, Ohio

DOE Office of Scientific and Technical Information (OSTI.GOV)

Moyer, C.C.

1996-09-01

Approximately 75 wells have penetrated the Cambrian Rose Run sandstone in Randolph Township, Portage County, Ohio, about half of which should produce well beyond economic payout. Only one deep test (to the Rose Run or deeper) was drilled in this Township prior to 1990. Two separate and distinct Rose Run producing fields exist in the Township; the western field is predominately gas-productive and the east is predominantly oil-productive. Both fields are on the north side of the Akron-Suffield Fault Zone, which is part of a regional cross-strike structural discontinuity extending from the Pittsburgh, Pennsylvania area northwestward to Lake Erie. Thismore » feature exhibits control over Berea, Oriskany, Newburg, Clinton, and Rose Run production.« less

Geology of the Anderson Mesa quadrangle, Colorado

USGS Publications Warehouse

Cater, Fred W.; Withington, C.F.

1953-01-01

The Anderson Mesa quadrangle is one of the eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of the southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteenth quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quarternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by high-angle faults, and northwest-tending folds. Conspicuous among the folds are large anticlines having cores of intrusive slat and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of the Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as the "Uravan Mineral Belt". Individual deposits range in size from irregular masses containing many thousands of tons. The ore consists of largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary structures in sandstones of favorable composition.

Measuring and predicting reservoir heterogeneity in complex deposystems: The fluvial-deltaic Big Injun sandstone in West Virginia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Patchen, D.G.; Hohn, M.E.; Aminian, K.

1993-04-01

The purpose of this research is to develop techniques to measure and predict heterogeneities in oil reservoirs that are the products of complex deposystems. The unit chosen for study is the Lower Mississippian Big Injun sandstone, a prolific oil producer (nearly 60 fields) in West Virginia. This research effort has been designed and is being implemented as an integrated effort involving stratigraphy, structural geology, petrology, seismic study, petroleum engineering, modeling and geostatistics. Sandstone bodies are being mapped within their regional depositional systems, and then sandstone bodies are being classified in a scheme of relative heterogeneity to determine heterogeneity across depositionalmore » systems. Facies changes are being mapped within given reservoirs, and the environments of deposition responsible for each facies are being interpreted to predict the inherent relative heterogeneity of each facies. Structural variations will be correlated both with production, where the availability of production data will permit, and with variations in geologic and engineering parameters that affect production. A reliable seismic model of the Big Injun reservoirs in Granny Creek field is being developed to help interpret physical heterogeneity in that field. Pore types are being described and related to permeability, fluid flow and diagenesis, and petrographic data are being integrated with facies and depositional environments to develop a technique to use diagenesis as a predictive tool in future reservoir development. Another objective in the Big Injun study is to determine the effect of heterogeneity on fluid flow and efficient hydrocarbon recovery in order to improve reservoir management. Graphical methods will be applied to Big Injun production data and new geostatistical methods will be developed to detect regional trends in heterogeneity.« less

Measuring and predicting reservoir heterogeneity in complex deposystems: The fluvial-deltaic Big Injun sandstone in West Virginia. Annual report, September 20, 1991--September 20, 1992

DOE Office of Scientific and Technical Information (OSTI.GOV)

Patchen, D.G.; Hohn, M.E.; Aminian, K.

1993-04-01

The purpose of this research is to develop techniques to measure and predict heterogeneities in oil reservoirs that are the products of complex deposystems. The unit chosen for study is the Lower Mississippian Big Injun sandstone, a prolific oil producer (nearly 60 fields) in West Virginia. This research effort has been designed and is being implemented as an integrated effort involving stratigraphy, structural geology, petrology, seismic study, petroleum engineering, modeling and geostatistics. Sandstone bodies are being mapped within their regional depositional systems, and then sandstone bodies are being classified in a scheme of relative heterogeneity to determine heterogeneity across depositionalmore » systems. Facies changes are being mapped within given reservoirs, and the environments of deposition responsible for each facies are being interpreted to predict the inherent relative heterogeneity of each facies. Structural variations will be correlated both with production, where the availability of production data will permit, and with variations in geologic and engineering parameters that affect production. A reliable seismic model of the Big Injun reservoirs in Granny Creek field is being developed to help interpret physical heterogeneity in that field. Pore types are being described and related to permeability, fluid flow and diagenesis, and petrographic data are being integrated with facies and depositional environments to develop a technique to use diagenesis as a predictive tool in future reservoir development. Another objective in the Big Injun study is to determine the effect of heterogeneity on fluid flow and efficient hydrocarbon recovery in order to improve reservoir management. Graphical methods will be applied to Big Injun production data and new geostatistical methods will be developed to detect regional trends in heterogeneity.« less

Investigation of the relationship between CO2 reservoir rock property change and the surface roughness change originating from the supercritical CO2-sandstone-groundwater geochemical reaction at CO2 sequestration condition

NASA Astrophysics Data System (ADS)

Lee, Minhee; Wang, Sookyun; Kim, Seyoon; Park, Jinyoung

2015-04-01

Lab scale experiments were performed to investigate the property changes of sandstone slabs and cores, resulting from the scCO2-rock-groundwater reaction for 180 days under CO2 sequestration conditions (100 bar and 50 °C). The geochemical reactions, including the surface roughness change of minerals in the slab, resulted from the dissolution and the secondary mineral precipitation for the sandstone reservoir of the Gyeongsang basin, Korea were reproduced in laboratory scale experiments and the relationship between the geochemical reaction and the physical rock property change was derived, for the consideration of successful subsurface CO2 sequestration. The use of the surface roughness value (SRrms) change rate and the physical property change rate to quantify scCO2-rock-groundwater reaction is the novel approach on the study area for CO2 sequestration in the subsurface. From the results of SPM (Scanning Probe Microscope) analyses, the SRrms for each sandstone slab was calculated at different reaction time. The average SRrms increased more than 3.5 times during early 90 days reaction and it continued to be steady after 90 days, suggesting that the surface weathering process of sandstone occurred in the early reaction time after CO2 injection into the subsurface reservoir. The average porosity of sandstone cores increased by 8.8 % and the average density decreased by 0.5 % during 90 days reaction and these values slightly changed after 90 days. The average P and S wave velocities of sandstone cores also decreased by 10 % during 90 days reaction. The trend of physical rock property change during the geochemical reaction showed in a logarithmic manner and it was also correlated to the logarithmic increase in SRrms, suggesting that the physical property change of reservoir rocks originated from scCO2 injection directly comes from the geochemical reaction process. Results suggested that the long-term estimation of the physical property change for reservoir rocks in CO2 injection site could be possible from the extrapolation process of SRrms and rocks property change rates, acquired from laboratory scale experiments. It will be aslo useful to determine the favorite CO2 injection site from the viewpoint of the safety.

Potential for deep basin-centered gas accumulation in Travis Peak (Hosston) Formation, Gulf Coastal Basin

USGS Publications Warehouse

Bartberger, Charles E.; Dyman, Thaddeus S.; Condon, Steven M.

2003-01-01

The potential of Lower Cretaceous sandstones of the Travis Peak Formation in the northern Gulf Coast Basin to harbor a basin-centered gas accumulation was evaluated by examining (1) the depositional and diagenetic history and reservoir properties of Travis Peak sandstones, (2) the presence and quality of source rocks for generating gas, (3) the burial and thermal history of source rocks and time of gas generation and migration relative to tectonic development of Travis Peak traps, (4) gas and water recoveries from drill-stem and formation tests, (5) the distribution of abnormal pressures based on shut-in-pressure data, and (6) the presence or absence of gas-water contacts associated with gas accumulations in Travis Peak sandstones. The Travis Peak Formation (and correlative Hosston Formation) is a basinward-thickening wedge of terrigenous clastic sedimentary rocks that underlies the northern Gulf Coast Basin from eastern Texas across northern Louisiana to southern Mississippi. Clastic infl ux was focused in two main fl uvial-deltaic depocenters?one located in northeastern Texas and the other in southeastern Mississippi and northeastern Louisiana. Across the main hydrocarbon-productive trend in eastern Texas and northern Louisiana, the Travis Peak Formation is about 2,000 ft thick. Most Travis Peak hydrocarbon production in eastern Texas comes from drilling depths between 6,000 and 10,000 ft. Signifi cant decrease in porosity and permeability occurs through that depth interval. Above 8,000-ft drilling depth in eastern Texas, Travis Peak sandstone matrix permeabilities often are signifi cantly higher than the 0.1-millidarcy (mD) cutoff that characterizes tight-gas reservoirs. Below 8,000 ft, matrix permeability of Travis Peak sandstones is low because of pervasive quartz cementation, but abundant natural fractures impart signifi cant fracture permeability. Although pressure data within the middle and lower Travis Peak Formation are limited in eastern Texas, overpressured reservoirs caused by thermal generation of gas, typical of basin-centered gas accumulations, are not common in the Travis Peak Formation. Signifi cant overpressure was found in only one Travis Peak sandstone reservoir in 1 of 24 oil and gas fi elds examined across eastern Texas and northern Louisiana. The presence of gas-water contacts is perhaps the most defi nitive criterion indicating that a gas accumulation is conventional rather than a ?sweet spot? within a basin-centered gas accumulation. Hydrocarbon-water contacts within Travis Peak sandstone reservoirs were documented in 17 fi elds and probably occur in considerably more fi elds across the productive Travis Peak trend in eastern Texas and northern Louisiana. All known hydrocarbon-water contacts in Travis Peak reservoirs in eastern Texas, however, occur within sandstones in the upper 500 ft of the formation. Although no gas-water contacts have been reported within the lower three-fourths of the Travis Peak Formation in northeastern Texas, gas production from that interval is limited. The best available data suggest that most middle and lower Travis Peak sandstones are water bearing in northeastern Texas. Insuffi cient hydrocarbon charge relative to permeability of Travis Peak reservoirs might be responsible for lack of overpressure and basin-centered gas within the Travis Peak Formation. Shales interbedded with Travis Peak sandstones in eastern Texas are primarily oxidized fl ood-plain deposits with insuffi cient organic-carbon content to be signifi cant sources of oil and gas. The most likely source rocks for hydrocarbons in Travis Peak reservoirs are two stratigraphically lower units, the Jurassic-age Bossier Shale of the Cotton Valley Group, and laminated, lime mudstones of the Jurassic Smackover Formation. Hydrocarbon charge, therefore, might be suffi cient for development of conventional gas accumulations, but it is insuffi cient for

Depositional environment of downdip Yegua (Eocene) sandstones, Jackson County, Texas

DOE Office of Scientific and Technical Information (OSTI.GOV)

Whitten, C.J.; Berg, R.R.

Yegua sandstones at a depth of 8300-8580 ft (2530-2615 m) were partly cored in the Arco Jansky 1 dry hole. Total thickness of the sandstone section is approximately 240 ft (73 m). The sandstones are enclosed in thick marine shales and are about 20 mi (32 km) downdip from thicker and more abundant sandstones in the Yegua Formation. The section is similar to reservoirs recently discovered in the area at the Toro Grande (1984), Lost Bridge (1984), and El Torito (1985) fields. The sandstones are fine to very fine grained and occur in thin beds that are 0.5-9 ft (0.15-2.7more » m) thick. Sedimentary structures within the beds range from a lower massive division to a laminated or rippled upper division. Grain size within beds fines upward from 0.18 mm at the base to 0.05 mm at the top. The sandstones are interpreted to be turbidites of the AB type that were deposited within channels. The sandstones contain an average of 50% quartz and are classified as volcanic-arenites to feldspathic litharenites. Carbonate cement ranges from 0 to 27%. Average porosity is 29% and permeabilities are in the range of 60-1600 md in the clean sandstones. Much of the porosity is secondary and is the result of the dissolution of cements, volcanic rock fragments, and feldspar grains. Yegua sandstones produce gas and condensate at nearby Toro Grande field on a gentle, faulted anticline. The local trend of reservoir sandstones may be controlled in part by faulting that was contemporaneous with deposition.« less

Lower paleozoic of Baltic Area

DOE Office of Scientific and Technical Information (OSTI.GOV)

Haselton, T.M.; Surlyk, F.

The Baltic Sea offers a new and exciting petroleum play in northwestern Europe. The Kaliningrad province in the Soviet Union, which borders the Baltic Sea to the east, contains an estimated 3.5 billion bbl of recoverable oil from lower Paleozoic sandstones. To the south, in Poland, oil and gas fields are present along a trend that projects offshore into the Baltic. Two recent Petrobaltic wells in the southern Baltic have tested hydrocarbons from lower Paleozoic sandstone. Minor production comes from Ordovician reefs on the Swedish island of Gotland in the western Baltic. The Baltic synclise, which began subsiding in themore » late Precambrian, is a depression in the East European platform. Strate dip gently to the south where the Baltic Synclise terminates against a structurally complex border zone. Depth to the metamorphosed Precambrian basement is up to 4,000 m. Overlying basement is 200-300 m of upper Precambrian arkosic sandstone. The Lower Cambrian consists of shallow marine quartzites. During Middle and Late Camnbrian, restricted circulation resulted in anoxic conditions and the deposition of Alum shale. The Lower Ordovician consists of quartzites and shale. The Upper Ordovician includes sandstones and algal reefs. The Silurian contains marginal carbonates and shales. For the last 25 years, exploration in northwest Europe has concentrated on well-known Permian sandstone, Jurassic sandstone, and Cretaceous chalk plays. Extrapolation of trends known and exploited in eastern Europe could open an entirely new oil province in the lower Paleozoic in the Baltic.« less

Middle to late Cambrian shallow marine trace fossils from the Imfout Syncline (Western Meseta, Morocco): Palaeoecological and palaeoenvironmental significance in NW-Gondwana

NASA Astrophysics Data System (ADS)

Oukassou, Mostafa; Lagnaoui, Abdelouahed; Raji, Mohammed; Michard, André; Saddiqi, Omar

2017-05-01

The present research provides the first evidence of invertebrate activity assigned to the ichnogenus Selenichnites occurring together with moderately diverse ichnofossils from the middle to late Cambrian of the Moroccan Meseta. The invertebrate traces occur in sandstone strata of the El Hank Formation within the Imfout Syncline, in the northern part of the Rehamna Massif (Coastal Block, western Moroccan Meseta). Bedding surfaces from the top of the El Hank Formation near the Imfout Dam show diverse forms of current ripples and distincts crescentic ichnofossils in concave epirelief scattered on the surface. In this section, the traces provide evidence of the ethology of an organism inhabiting the relatively shallow waters of the area during this time. Selenichnites co-occurs with the ichnogenera Arenicolites, Diplocraterion, Lingulichnus, Monocraterion, Skolithos and unidentified burrows, and the ichnoassemblage is referred to the Skolithos ichnofacies. These traces can be referred to arthropods (e.g. polychaete worms and amphipod crustaceans), lingulid brachiopods, annelids and/or phoronids. The Imfout Selenichnites represents the first occurrence of this ichnogenus from the Cambrian of the Moroccan Meseta, and the second from the Cambrian deposits of Morocco. The potential tracemakers are still questionable, but were most likely xiphosurans, trilobites, euthycarcinoids or crustaceans. If so, the Imfout traces could be among the oldest pieces of evidence for the presence of horseshoe crabs during the Cambrian. The combination of sedimentological and ichnological data indicates that the El Hank Formation was deposited in a sublittoral soft ground environment next to a sandy shore. It was originally part of an early Palaeozoic shallow marine epicontinental platform in west-central Morocco. In addition to the equivalent Cambrian deposits from the Anti-Atlas, the El Hank Formation constituted a part of the northern Gondwana platform domain during the transgression coming from the Rheic Ocean onto the West African Craton margin.

Provenance, diagenesis, tectonic setting and reservoir quality of the sandstones of the Kareem Formation, Gulf of Suez, Egypt

NASA Astrophysics Data System (ADS)

Zaid, Samir M.

2013-09-01

The Middle Miocene Kareem sandstones are important oil reservoirs in the southwestern part of the Gulf of Suez basin, Egypt. However, their diagenesis and provenance and their impact on reservoir quality, are virtually unknown. Samples from the Zeit Bay Oil Field, and the East Zeit Oil Field represent the Lower Kareem (Rahmi Member) and the Upper Kareem (Shagar Member), were studied using a combination of petrographic, mineralogical and geochemical techniques. The Lower Rahmi sandstones have an average framework composition of Q95F3.4R1.6, and 90% of the quartz grains are monocrystalline. By contrast, the Upper Shagar sandstones are only slightly less quartzose with an average framework composition of Q76F21R3 and 82% of the quartz grains are monocrystalline. The Kareem sandstones are mostly quartzarenite with subordinate subarkose and arkose. Petrographical and geochemical data of sandstones indicate that they were derived from granitic and metamorphic terrains as the main source rock with a subordinate quartzose recycled sedimentary rocks and deposited in a passive continental margin of a syn rift basin. The sandstones of the Kareem Formation show upward decrease in maturity. Petrographic study revealed that dolomite is the dominant cement and generally occurs as fine to medium rhombs pore occluding phase and locally as a grain replacive phase. Authigenic quartz occurs as small euhedral crystals, locally as large pyramidal crystals in the primary pores. Authigenic anhydrites typically occur as poikilotopic rhombs or elongate laths infilling pores but also as vein filling cement. The kaolinite is a by-product of feldspar leaching in the presence of acidic fluid produced during the maturation of organic matter in the adjacent Miocene rocks. Diagenetic features include compaction; dolomite, silica and anhydrite cementation with minor iron-oxide, illite, kaolinite and pyrite cements; dissolution of feldspars, rock fragments. Silica dissolution, grain replacement and carbonate dissolution greatly enhance the petrophysical properties of many sandstone samples.

Sedimentological and geophysical studies of clastic reservoir analogs: Methods, applications and developments of ground-penetrating radar for determination of reservoir geometries in near-surface settings. Final report

DOE Office of Scientific and Technical Information (OSTI.GOV)

McMechan, G.A.; Soegaard, K.

1998-05-25

An integrated sedimentologic and GPR investigation has been carried out on a fluvial channel sandstone in the mid-Cretaceous Ferron Sandstone at Coyote Basin along the southwestern flank of the San Rafael Uplift in east-central Utah. This near-surface study, which covers a area of 40 {times} 16.5 meters to a depth of 15 meters, integrates detailed stratigraphic data from outcrop sections and facies maps with multi-frequency 3-D GPR surveys. The objectives of this investigation are two-fold: (1) to develop new ground-penetrating radar (GPR) technology for imaging shallow subsurface sandstone bodies, and (2) to construct an empirical three-dimensional sandstone reservoir model suitablemore » for hydrocarbon flow-simulation by imaging near-surface sandstone reservoir analogs with the use of GPR. The sedimentological data base consists of a geologic map of the survey area and a detailed facies map of the cliff face immediately adjacent to the survey area. Five vertical sections were measured along the cliff face adjacent to the survey area. In addition, four wells were cored within the survey area from which logs were recorded. In the sections and well logs primary sedimentary structures were documented along with textural information and permeability data. Gamma-ray profiles were also obtained for all sections and core logs. The sedimentologic and stratigraphic information serves as the basis from which much of the processing and interpretation of the GPR data was made. Three 3-D GPR data sets were collected over the survey area at frequencies of 50 MHZ, 100 MHZ, and 200 MHZ.« less

DOE Office of Scientific and Technical Information (OSTI.GOV)

Seyler, Beverly; Grube, John; Huff, Bryan

Within the Illinois Basin, most of the oilfields are mature and have been extensively waterflooded with water cuts that range up to 99% in many of the larger fields. In order to maximize production of significant remaining mobile oil from these fields, new recovery techniques need to be researched and applied. The purpose of this project was to conduct reservoir characterization studies supporting Alkaline-Surfactant-Polymer Floods in two distinct sandstone reservoirs in Lawrence Field, Lawrence County, Illinois. A project using alkaline-surfactantpolymer (ASP) has been established in the century old Lawrence Field in southeastern Illinois where original oil in place (OOIP) ismore » estimated at over a billion barrels and 400 million barrels have been recovered leaving more than 600 million barrels as an EOR target. Radial core flood analysis using core from the field demonstrated recoveries greater than 20% of OOIP. While the lab results are likely optimistic to actual field performance, the ASP tests indicate that substantial reserves could be recovered even if the field results are 5 to 10% of OOIP. Reservoir characterization is a key factor in the success of any EOR application. Reservoirs within the Illinois Basin are frequently characterized as being highly compartmentalized resulting in multiple flow unit configurations. The research conducted on Lawrence Field focused on characteristics that define reservoir compartmentalization in order to delineate preferred target areas so that the chemical flood can be designed and implemented for the greatest recovery potential. Along with traditional facies mapping, core analyses and petrographic analyses, conceptual geological models were constructed and used to develop 3D geocellular models, a valuable tool for visualizing reservoir architecture and also a prerequisite for reservoir simulation modeling. Cores were described and potential permeability barriers were correlated using geophysical logs. Petrographic analyses were used to better understand porosity and permeability trends in the region and to characterize barriers and define flow units. Diagenetic alterations that impact porosity and permeability include development of quartz overgrowths, sutured quartz grains, dissolution of feldspar grains, formation of clay mineral coatings on grains, and calcite cementation. Many of these alterations are controlled by facies. Mapping efforts identified distinct flow units in the northern part of the field showing that the Pennsylvanian Bridgeport consists of a series of thick incised channel fill sequences. The sandstones are about 75-150 feet thick and typically consist of medium grained and poorly sorted fluvial to distributary channel fill deposits at the base. The sandstones become indistinctly bedded distributary channel deposits in the main part of the reservoir before fining upwards and becoming more tidally influenced near their top. These channel deposits have core permeabilities ranging from 20 md to well over 1000 md. The tidally influenced deposits are more compartmentalized compared to the thicker and more continuous basal fluvial deposits. Fine grained sandstones that are laterally equivalent to the thicker channel type deposits have permeabilities rarely reaching above 250 md. Most of the unrecovered oil in Lawrence Field is contained in Pennsylvanian Age Bridgeport sandstones and Mississippian Age Cypress sandstones. These reservoirs are highly complex and compartmentalized. Detailed reservoir characterization including the development of 3-D geologic and geocellular models of target areas in the field were completed to identify areas with the best potential to recover remaining reserves including unswept and by-passed oil. This project consisted of tasks designed to compile, interpret, and analyze the data required to conduct reservoir characterization for the Bridgeport and Cypress sandstones in pilot areas in anticipation of expanded implementation of ASP flooding in Lawrence Field. Geologic and geocellular modeling needed for reservoir characterization and reservoir simulation were completed as prerequisites for design of efficient ASP flood patterns. Characterizing the complex reservoir geology that identifies the geologic conditions that will optimize oil recoveries for expansion of the ASP pilots in the Bridgeport and Cypress sandstones to other areas of Lawrence Field is the primary objective of this project. It will permit evaluation of efficiency of oil recovery from Bridgeport and Cypress sandstone reservoirs using ASP technology. Additionally evaluation of similar Pennsylvanian and Chesterian reservoirs shows that it is likely that ASP flood technology can be successfully applied to similar reservoirs in the Illinois Basin as well as to other U.S. reservoirs. Chemical flooding was introduced in stages with the first flood initiated in 2010 and a second offset pilot project initiated during 2011. Rex Energy Corporation is reporting a positive response on its ASP Middagh pilot project in the Pennsylvanian Bridgeport B reservoir, Lawrence Field. Oil response in the 15 acre flood has continued to show an increase in oil cut from 1% to 12%. Total pattern production increased from 16 BOPD and stabilized at a range of 65-75 BOPD in the last three months of 2011. Peak production rose to 100 + BOPD. Oil cut in the pilot increased for 1.0% to ~ 12.0% with an individual well showing oil cuts greater than 20%. A second, 58 acre pilot (Perkins-Smith) adjacent to and likely in communication with the Middagh pilot has been initiated. Preliminary brine injection has been implemented and ASP injection was initiated in mid-2012. Response is expected by mid-2013 with peak recovery expected by late 2013. Rex Energy is projecting full scale expansion with the next step of development being a 351 acre project scheduled to begin in mid-2013. Preliminary development has been initiated in this Delta Unit area located in the south half of section 32, T4N, R12W.« less

A highly redox-heterogeneous ocean in South China during the early Cambrian (˜529-514 Ma): Implications for biota-environment co-evolution

NASA Astrophysics Data System (ADS)

Jin, Chengsheng; Li, Chao; Algeo, Thomas J.; Planavsky, Noah J.; Cui, Hao; Yang, Xinglian; Zhao, Yuanlong; Zhang, Xingliang; Xie, Shucheng

2016-05-01

The ;Cambrian Explosion; is known for rapid increases in the morphological disparity and taxonomic diversity of metazoans. It has been widely proposed that this biological event was a consequence of oxygenation of the global ocean, but this hypothesis is still under debate. Here, we present high-resolution Fe-S-C-Al-trace element geochemical records from the Jinsha (outer shelf) and Weng'an (outer shelf) sections of the early Cambrian Yangtze Platform, integrating these results with previously published data from six correlative sections representing a range of water depths (Xiaotan, Shatan, Dingtai, Yangjiaping, Songtao, and Longbizui). The integrated iron chemistry and redox-sensitive trace element data suggest that euxinic mid-depth waters dynamically coexisted with oxic surface waters and ferruginous deep waters during the earliest Cambrian, but that stepwise expansion of oxic waters commenced during Cambrian Stage 3 (∼ 521- 514 Ma). Combined with data from lower Cambrian sections elsewhere, including Oman, Iran and Canada, we infer that the global ocean exhibited a high degree of redox heterogeneity during the early Cambrian, consistent with low atmospheric oxygen levels (∼ 10- 40% of present atmospheric level, or PAL). A large spatial gradient in pyrite sulfur isotopic compositions (δ34Spy), which vary from a mean of - 12.0 ‰ in nearshore areas to + 22.5 ‰ in distal deepwater sections in lower Cambrian marine units of South China imply low concentrations and spatial heterogeneity of seawater sulfate, which is consistent with a limited oceanic sulfate reservoir globally. By comparing our reconstructed redox chemistry with fossil records from the lower Cambrian of South China, we infer that a stepwise oxygenation of shelf and slope environments occurred concurrently with a gradual increase in ecosystem complexity. However, deep waters remained anoxic and ferruginous even as macrozooplankton and suspension-feeding mesozooplankton appeared during Cambrian Stage 3. These findings suggest that the ;Cambrian Explosion; in South China may have been primarily a consequence of locally improved oxygenation of the ocean-surface layer rather than of the full global ocean. Our observations are inconsistent with predicted changes in ocean chemistry driven by early Cambrian animals, suggesting that the influence of early Cambrian animals on contemporaneous ocean chemistry, as proposed in previous studies, may be overly exaggerated.

Geologic summary of the Appalachian Basin, with reference to the subsurface disposal of radioactive waste solutions

USGS Publications Warehouse

Colton, G.W.

1962-01-01

The Appalachian basin is an elongate depression in the crystalline basement complex< which contains a great volume of predominantly sedimentary stratified rocks. As defined in this paper it extends from the Adirondack Mountains in New York to central Alabama. From east to west it extends from the west flank of the Blue Ridge Mountains to the crest of the Findlay and Cincinnati arches and the Nashville dome. It encompasses an area of about 207,000 square miles, including all of West Virginia and parts of New York, New Jersey, Pennsylvania, Ohio, Maryland, Virginia, Kentucky, Tennessee, North Carolina, Georgia, and Alabama. The stratified rocks that occupy the basin constitute a wedge-shaped mass whose axis of greatest thickness lies close to and parallel to the east edge of the basin. The maximum thickness of stratified rocks preserved in any one part of the basin today is between 35,000 and 40,000 feet. The volume of the sedimentary rocks is approximately 510,000 cubic miles and of volcanic rocks is a few thousand cubic miles. The sedimentary rocks are predominantly Paleozoic in age, whereas the volcanic rocks are predominantly Late Precambrian. On the basis of gross lithology the stratified rocks overlying the crystalline basement complex can be divided into nine vertically sequential units, which are designated 'sequences' in this report. The boundaries between contiguous sequences do not necessarily coincide with the commonly recognized boundaries between systems or series. All sequences are grossly wedge shaped, being thickest along the eastern margin of the basin and thinnest along the western margin. The lowermost unit--the Late Precambrian stratified sequence--is present only along part of the eastern margin of the basin, where it lies unconformably on the basement complex. It consists largely of volcanic tuffs and flows but contains some interbedded sedimentary rocks. The Late Precambrian sequence is overlain by the Early Cambrian clastic sequence. Where the older sequence is absent, the Early Cambrian sequence rests on the basement complex. Interbedded fine- to coarse-grained noncarbonate detrital rocks comprise the bulk of the sequence, but some volcanic and carbonate rocks are included. Next above is the Cambrian-Ordovician carbonate sequence which consists largely of limestone and dolomite. Some quartzose sandstone is present in the lower part in the western half of the basin, and much shale is present in the upper part in the southeast part of the basin. The next higher sequence is the Late Ordovician clastic sequence, which consists largely of shale, siltstone, and sandstone. Coarse-grained light-gray to red rocks are common in the sequence along the eastern side of the basin, whereas fine-grained dark-gray to black calcareous rocks are common along the west side. The Late Ordovician clastic sequence is overlain--unconformably in many places--by the Early Silurian clastic sequence. The latter comprises a relatively thin wedge of coarse-grained clastic rocks. Some of the most prolific oil- and gas-producing sandstones in the Appalachian basin are included. Among these are the 'Clinton' sands of Ohio, the Medina Sandstones of New York and Pennsylvania, and the Keefer or 'Big Six' Sandstone of West Virginia and Kentucky. Conformably overlying the Early Silurian clastic sequence is the Silurian-Devonian carbonate sequence, which consists predominantly of limestone and dolomite. It also contains a salt-bearing unit in the north-central part of the basin and a thick wedge of coarse-grained red beds in the northeastern part. The sequence is absent in much of the southern part of the basin. Large volumes of gas and much oil are obtained from some of its rocks, especially from the Oriskany Sandstone and the Huntersville Chert. The Silurian-Devonian carbonate sequence is abruptly overlain by the Devonian clastic sequence--a thick succession of interbedded shale, mudrock, siltstone, and sandstone. Colors range f

The significance of 24-norcholestanes, triaromatic steroids and dinosteroids in oils and Cambrian-Ordovician source rocks from the cratonic region of the Tarim Basin, NW China

USGS Publications Warehouse

Li, Meijun; Wang, T.-G.; Lillis, Paul G.; Wang, Chunjiang; Shi, Shengbao

2012-01-01

Two oil families in Ordovician reservoirs from the cratonic region of the Tarim Basin are distinguished by the distribution of regular steranes, triaromatic steroids, norcholestanes and dinosteroids. Oils with relatively lower contents of C28 regular steranes, C26 20S, C26 20R + C27 20S and C27 20R regular triaromatic steroids, dinosteranes, 24-norcholestanes and triaromatic dinosteroids originated from Middle–Upper Ordovician source rocks. In contrast, oils with abnormally high abundances of the above compounds are derived from Cambrian and Lower Ordovician source rocks. Only a few oils have previously been reported to be of Cambrian and Lower Ordovician origin, especially in the east region of the Tarim Basin. This study further reports the discovery of oil accumulations of Cambrian and Lower Ordovician origin in the Tabei and Tazhong Uplifts, which indicates a potential for further discoveries involving Cambrian and Lower Ordovician sourced oils in the Tarim Basin. Dinosteroids in petroleum and ancient sediments are generally thought to be biomarkers for dinoflagellates and 24-norcholestanes for dinoflagellates and diatoms. Therefore, the abnormally high abundance of these compounds in extracts from the organic-rich sediments in the Cambrian and Lower Ordovician and related oils in the cratonic region of the Tarim Basin suggests that phytoplankton algae related to dinoflagellates have appeared and might have flourished in the Tarim Basin during the Cambrian Period. Steroids with less common structural configurations are underutilized and can expand understanding of the early development history of organisms, as well as define petroleum systems.

Possible continuous-type (unconventional) gas accumulation in the Lower Silurian "Clinton" sands, Medina Group and Tuscarora Sandstone in the Appalachian Basin; a progress report of the 1995 project activities

USGS Publications Warehouse

Ryder, Robert T.; Aggen, Kerry L.; Hettinger, Robert D.; Law, Ben E.; Miller, John J.; Nuccio, Vito F.; Perry, William J.; Prensky, Stephen E.; Filipo, John J.; Wandrey, Craig J.

1996-01-01

INTRODUCTION: In the U.S. Geological Survey's (USGS) 1995 National Assessment of United States oil and gas resources (Gautier and others, 1995), the Appalachian basin was estimated to have, at a mean value, about 61 trillion cubic feet (TCF) of recoverable gas in sandstone and shale reservoirs of Paleozoic age. Approximately one-half of this gas resource is estimated to reside in a regionally extensive, continuous-type gas accumulation whose reservoirs consist of low-permeability sandstone of the Lower Silurian 'Clinton' sands and Medina Group (Gautier and others, 1995; Ryder, 1995). Recognizing the importance of this large regional gas accumulation for future energy considerations, the USGS initiated in January 1995 a multi-year study to evaluate the nature, distribution, and origin of natural gas in the 'Clinton' sands, Medina Group sandstones, and equivalent Tuscarora Sandstone. The project is part of a larger natural gas project, Continuous Gas Accumulations in Sandstones and Carbonates, coordinated in FY1995 by Ben E. Law and Jennie L. Ridgley, USGS, Denver. Approximately 2.6 man years were devoted to the Clinton/Medina project in FY1995. A continuous-type gas accumulation, referred to in the project, is a new term introduced by Schmoker (1995a) to identify those natural gas accumulations whose reservoirs are charged throughout with gas over a large area and whose entrapment does not involve a downdip gas-water contact. Gas in these accumulations is located downdip of the water column and, thus, is the reverse of conventional-type hydrocarbon accumulations. Commonly used industry terms that are more or less synonymous with continuous-type gas accumulations include basin- centered gas accumulation (Rose and others, 1984; Law and Spencer, 1993), tight (low-permeability) gas reservoir (Spencer, 1989; Law and others, 1989; Perry, 1994), and deep basin gas (Masters, 1979, 1984). The realization that undiscovered gas in Lower Silurian sandstone reservoirs of the Appalachian basin probably occurs in a continuous accumulation rather than in conventionally trapped, discrete accumulations represents a significant departure from the 1989 National Assessment (Mast and others, 1989; deWitt, 1993). In 1989, a direct assessment (field-size distributions required for play analysis were unavailable) of the Lower Silurian sandstone play gave, at a mean value, about 1.7 TCF of gas. The 1995 estimate (~30 TCF of gas) is so much greater than the 1989 estimate (~1.7 TCF of gas) because of the interpreted continuous nature of the accumulation and the assessment methodology applied. The methodology for continuous hydrocarbon accumulations assumes that the reservoirs in the accumulation are gas-saturated and takes into account: 1) estimated ultimate recovery (EUR) per well probability distributions, 2) optimum area that a well can drain (spacing), 3) number of untested drill sites having the appropriate spacing area, 4) success ratio of previously drilled holes, and 5) risk (Schmoker, 1995b). Davis (1984), Zagorski (1988, 1991), and Law and Spencer (1993) were among the first petroleum geologists to suggest that gas in the 'Clinton' sands and Medina Group sandstones was trapped in a basin-centered/deep basin accumulation. They recognized many of the earmarks of a basin-centered/deep basin accumulation such as low-permeability reservoirs, abnormally low formation pressure, coalesced gas fields, gas shows or production in most holes drilled, low water yields, and a general lack of structural control on entrapment. Ryder (1995) adopted this interpretation by defining four continuous-type gas plays (6728-6731) in the 'Clinton' sands-Medina Group interval (fig.1). Play 6728 (Clinton/Medina sandstone gas high potential) covers a 17,000 sq mi region of western New York, northwestern Pennsylvania, eastern Ohio, and a small part of westernmost West Virginia that is very favorable for future gas resources (fig.1). Also, this play includes a l

Diagenesis and porosity evolution of tight sand reservoirs in Carboniferous Benxi Formation, Southeast Ordos Basin

NASA Astrophysics Data System (ADS)

Hu, Peng; Yu, Xinghe; Shan, Xin; Su, Dongxu; Wang, Jiao; Li, Yalong; Shi, Xin; Xu, Liqiang

2016-04-01

The Ordos Basin, situated in west-central China, is one of the oldest and most important fossil-fuel energy base, which contains large reserves of coal, oil and natural gas. The Upper Palaeozoic strata are widely distributed with rich gas-bearing and large natural gas resources, whose potential is tremendous. Recent years have witnessed a great tight gas exploration improvement of the Upper Paleozoic in Southeastern Ordos basin. The Carboniferous Benxi Formation, mainly buried more than 2,500m, is the key target strata for hydrocarbon exploration, which was deposited in a barrier island and tidal flat environment. The sandy bars and flats are the favorable sedimentary microfacies. With an integrated approach of thin-section petrophysics, constant velocity mercury injection test, scanning electron microscopy and X-ray diffractometry, diagenesis and porosity evolution of tight sand reservoirs of Benxi Formation were analyzed in detail. The result shows that the main lithology of sandstone in this area is dominated by moderately to well sorted quartz sandstone. The average porosity and permeability is 4.72% and 1.22mD. The reservoirs of Benxi Formation holds a variety of pore types and the pore throats, with obvious heterogeneity and poor connection. Based on the capillary pressure curve morphological characteristics and parameters, combined with thin section and phycical property data, the reservoir pore structure of Benxi Formation can be divided into 4 types, including mid pore mid throat type(I), mid pore fine throat type(II), small pore fine throat type(III) and micro pro micro throat type(Ⅳ). The reservoirs primarily fall in B-subsate of middle diagenesis and late diagenesis, which mainly undergo compaction, cmentation, dissolution and fracturing process. Employing the empirical formula of different sorting for unconsolideated sandstone porosity, the initial sandstone porosity is 38.32% on average. Quantitative evaluation of the increase and decrease of porosity caused by different diagenesis reveals that mechanical compaction and chemical cementation are the main mechanisms for destroying primary pores, which contribute 19.61% and 8.75% to the loss of primary posoity, respectively. Dissolution of volcanic fragments and feldspar increased reservoir porosity by 4.14%. The pores were occluded by late minerals and carbonate cements, resulting in a reduction of 9.38%. Overall, the dual influence of compaction and cementation is the key of the key, controlling formation of tight gas sandstone reservoirs. Keywords: diagenesis, porosity evolution, tight sandstone, Benxi Formation, Southeast Ordos Basin Acknowledgements: We greatfully acknowledge Yanchang Petroleum for providing the samples and data access and for permission to publish this work. The first author, Peng Hu, would like to thank the support from Prof. Xinghe Yu.

Geology of the Gateway quadrangle, Mesa county Colorado

USGS Publications Warehouse

Cater, Fred W.

1953-01-01

The Gateway quadrangle is one of eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by hih-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as "Uruvan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large, tabular masses containing many thousands of tons. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary structures in sandstones of favorable composition.

Geology of the Egnar quadrangle, Dolores and San Miguel counties, Colorado

USGS Publications Warehouse

Cater, Fred W.; Bush, A.L.; Bell, Henry

1954-01-01

The Egnar quadrangle is one of eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by hih-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as "Uruvan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large, tabular masses containing many thousands of tons. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary structures in sandstones of favorable composition.

Geology of the Hamm Canyon quadrangle, Colorado

USGS Publications Warehouse

Cater, Fred W.

1953-01-01

The Hamm Canyon quadrangle is on eof eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by high-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of the Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as the "Uravan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large, tabular masses containing many thousands of tons. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary structures in sandstones of favorable composition.

Geology of the Davis Mesa quadrangle, Colorado

USGS Publications Warehouse

Cater, Fred W.; Bryner, Leonid

1953-01-01

The Davis Mesa quadrangle is one of eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by hih-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as "Uruvan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large, tabular masses containing many thousands of tons. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary structures in sandstones of favorable composition.

Geology of the Joe Davis Hill quadrangle, Dolores and San Miguel counties, Colorado

USGS Publications Warehouse

Cater, Fred W.; Bell, Henry

1953-01-01

The Joe Davis Hill quadrangle is one of eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by hih-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to Salt Wash sandstone member of the Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as the "Uravan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large, tabular masses containing many thousands of tons. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary structures in sandstones of favorable composition.

Geology of the Gypsum Gap quadrangle, Colorado

USGS Publications Warehouse

Cater, Fred W.

1953-01-01

The Gypsum Gap quadrangle is one eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comparative study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by high-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of the Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through a arcuate zone known as the "Uravan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large, tabular masses containing many thousands of tons. The core consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary structures in sandstones of favorable composition.

Geology of the Pine Mountain quadrangle, Mesa county, Colorado

USGS Publications Warehouse

Cater, Fred W.

1953-01-01

The Pine Mountain quadrangle is one of eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from Paleozoic to Quaternary. Over mush of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by high-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confines to the Salt Wash sandstone member of the Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as the "Uravan Mineral Belt". Individual deposits range in sizer from irregular masses containing only a few ton of ore to large, tabular masses containing many thousands of tons. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary structures in sandstones of favorable composition.

Geology of the Naturita NW quadrangle, Colorado

USGS Publications Warehouse

Cater, Fred W.; Vogel, J.D.

1953-01-01

The Naturita NW quadrangle is one of eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of these quadrangles were mapped by the U.S. Geological Survey on behalf of the U.S. Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by high-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of the Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as the "Uravan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large, tabular masses containing many thousands of tons. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear ro be related to certain sedimentary structures in sandstones of favorable composition.

Geology of the Calamity Mesa quadrangle, Mesa county, Colorado

USGS Publications Warehouse

Cater, Fred W.; Stager, Harold K.

1953-01-01

The Calamity Mesa quadrangle is one of eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks the range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by high-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of the Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as the "Uravan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large tabular masses containing many thousands of tons. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary structures in sandstones of favorable composition.

Geology of the Horse Range Mesa quadrangle, Colorado

USGS Publications Warehouse

Cater, Fred W.; Bush, A.L.; Bell, Henry; Withington, C.F.

1953-01-01

The Horse Range Mesa quadrangle is one of eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of the quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by high-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of the Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as the "Uravan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large, tabular masses containing many thousands of tons. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary strictures in sandstones of favorable composition.

Geology of Bull Canyon quadrangle, Montrose and San Miguel counties, Colorado

USGS Publications Warehouse

Cater, Fred W.

1953-01-01

The Bull Canyon quadrangle is one of eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite depots. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by high-angle faults and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of the Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as the "Uravan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large, tabular masses containing many thousands of tones. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to be related to certain sedimentary structures in sandstones of favorable composition.

Geology of the Uravan quadrangle, Montrose county, Colorado

USGS Publications Warehouse

Cater, Fred W.; Butler, A.P.; McKay, E.J.; Boardman, Robert L.

1954-01-01

The Uravan quadrangle is one of eighteen 7 1/2-minute quadrangles covering the principal carnotite-producing area of the southwestern Colorado. The geology of these quadrangles was mapped by the U.S. Geological Survey for the Atomic Energy Commission as part of a comprehensive study of carnotite deposits. The rocks exposed in the eighteen quadrangles consist of crystalline rocks of pre-Cambrian age and sedimentary rocks that range in age from late Paleozoic to Quaternary. Over much of the area the sedimentary rocks are flat lying, but in places the rocks are disrupted by high-angle faults, and northwest-trending folds. Conspicuous among the folds are large anticlines having cores of intrusive salt and gypsum. Most of the carnotite deposits are confined to the Salt Wash sandstone member of the Jurassic Morrison formation. Within this sandstone, most of the deposits are spottily distributed through an arcuate zone known as the "Uravan Mineral Belt". Individual deposits range in size from irregular masses containing only a few tons of ore to large, tabular masses containing many thousands of tons. The ore consists largely of sandstone selectively impregnated and in part replaced by uranium and vanadium minerals. Most of the deposits appear to the related to certain sedimentary structures in sandstones of favorable composition.

New interpretation of the so-called Nubian strata in northeast Africa

DOE Office of Scientific and Technical Information (OSTI.GOV)

Klitzsch, E.H.; Squyres, C.H.

1988-08-01

Stratigraphical interpretation of the so-called Nubian Sandstone of Egypt and northern Sudan have led to new ideas on the structural and paleogeographical development of northeast Africa. The strata formerly comprised under the term Nubian Sandstone include sediments from Cambrian to Paleocene age. Based on field work and paleontological investigations during the last 10 years, these strata can be subdivided into three major cycles, each characterizing a certain structural situation of northeast Africa. The first or Paleozoic cycle comprises strata of Cambrian to Early Carboniferous age. These strata were deposited during a period of generally northern dip of northeast Africa; continentalmore » sediments transported northward interfinger with marine strata resulting from southward transgressions. Sediments of the second cycle were deposited during and after Gondwana and northern continents collided, which caused updoming of large areas of Egypt and bordering areas to the west and east. As a result, most of Egypt became subject to erosion; transgressions remained near the present northern edge of the continent, and purely continental deposition took place in northern Sudan and bordering areas in Chad and Libya. The resulting strata are similar to the Karroo of East Africa. Strata of the third cycle were deposited after Pangea began to disintegrate. Northeast Africa now had a generally northern dip again, and consequently deposition was controlled - as during the first cycle - by northward drainage and southward transgressions. This last cycle began during Late Jurassic time.« less

Petrographic and reservoir features of Hauterivian (Lower Cretaceous) Shatlyk horizon in the Malay gas field, Amu-Darya basin, east Turkmenia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Naz, H.; Ersan, A.

1996-08-01

Malay gas field in Amu-Darya basin, eastern Turkmenia, is located on the structural high that is on the Malay-Bagadzha arch north of the Repetek-Kelif structure zone. With 500 km{sup 2} areal coverage, 16 producing wells and 200 billion m{sup 3} estimated reserves, the field was discovered in 1978 and production began in 1987 from 2400-m-deep Hauterivian-age (Early Cretaceous) Shatlyk horizon. The Shatlyk elastic sequence shows various thickness up to 100 m in the Malay structural closure and is studied through E-log, core, petrographic data and reservoir characteristics. The Shatlyk consists of poorly indurated, reddish-brown and gray sandstones, and sandy graymore » shales. The overall sand-shale ratio increases up and the shales interleave between the sand packages. The reservoir sandstones are very fine to medium grained, moderately sorted, compositionally immature, subarkosic arenites. The framework grains include quartz, feldspar and volcanic lithic fragments. Quartz grains are monocrystalline in type and most are volcanic in origin. Feldspars consist of K- Feldspar and plagioclase. The orthoclases are affected by preferential alteration. The sandstones show high primary intergranular porosity and variations in permeability. Patch-like evaporate cement and the iron-rich grain coatings are reducing effects in permeability. The coats are pervasive in reddish-brown sandstones but are not observed in the gray sandstones. The evaporate cement is present in all the sandstone samples examined and, in places, follows the oxidation coats. The petrographic evidences and the regional facies studies suggest the deposition in intersection area from continental to marine nearshore deltaic environment.« less

Reservoir characterization of Mesaverde (Campanian) bedload fluvial meanderbelt sandstones, northwestern Colorado

DOE Office of Scientific and Technical Information (OSTI.GOV)

Jones, J.R. Jr.

1984-04-01

Reservoir characterization of Mesaverde meanderbelt sandstones is used to determined directional continuity of permeable zones. A 500-m (1600 ft) wide fluvial meanderbelt in the Mesaverde Group is exposed as laterally continuous 3-10-m (10-33-ft) high sandstone cliffs north of Rangely, Colorado. Forty-eight detailed measured sections through 3 point bar complexes oriented at right angles to the long axis of deposition and 1 complex oriented parallel to deposition were prepared. Sections were tied together by detailed sketches delineating and tracing major bounding surfaces such as scours and clay drapes. These complexes contain 3 to 8 multilateral sandstone packages separated by 5-20 cmmore » (2-8 in.) interbedded siltstone and shale beds. Component facies are point bars, crevasse splays, chute bars, and floodplain/overbank deposits. Two types of lateral accretion surfaces are recognized in the point bar facies. Gently dipping lateral accretions containing fining-upward sandstone packages. Large scale trough cross-bedding at the base grades upward into ripples and plane beds. Steeply dipping lateral accretion surfaces enclose beds characterized by climbing ripple cross laminations. Bounding surfaces draped by shale lags can seal vertically stacked point bars from reservoir communication. Scoured boundaries allow communication in some stacked point bars. Crevasse splays showing climbing ripples form tongues of very fine-grained sandstone which flank point bars. Chute channels commonly cut upper point bar surfaces at their downstream end. Chute facies are upward-fining with small scale troughs and common dewatering structures. Siltstones and shales underlie the point bar complexes and completely encase the meanderbelt system. Bounding surfaces at the base of the complexes are erosional and contain large shale rip-up clasts.« less

Geologic framework for the national assessment of carbon dioxide storage resources: Powder River Basin, Wyoming, Montana, South Dakota, and Nebraska: Chapter B in Geologic framework for the national assessment of carbon dioxide storage resources

USGS Publications Warehouse

Craddock, William H.; Drake II, Ronald M.; Mars, John L.; Merrill, Matthew D.; Warwick, Peter D.; Blondes, Madalyn S.; Gosai, Mayur A.; Freeman, P.A.; Cahan, Steven A.; DeVera, Christina A.; Lohr, Celeste D.; Warwick, Peter D.; Corum, Margo D.

2012-01-01

This report presents ten storage assessment units (SAUs) within the Powder River Basin of Wyoming, Montana, South Dakota, and Nebraska. The Powder River Basin contains a thick succession of sedimentary rocks that accumulated steadily throughout much of the Phanerozoic, and at least three stratigraphic packages contain strata that are suitable for CO2 storage. Pennsylvanian through Triassic siliciclastic strata contain two potential storage units: the Pennsylvanian and Permian Tensleep Sandstone and Minnelusa Formation, and the Triassic Crow Mountain Sandstone. Jurassic siliciclastic strata contain one potential storage unit: the lower part of the Sundance Formation. Cretaceous siliciclastic strata contain seven potential storage units: (1) the Fall River and Lakota Formations, (2) the Muddy Sandstone, (3) the Frontier Sandstone and Turner Sandy Member of the Carlile Shale, (4) the Sussex and Shannon Sandstone Members of Cody Shale, and (5) the Parkman, (6) Teapot, and (7) Teckla Sandstone Members of the Mesaverde Formation. For each SAU, we discuss the areal distribution of suitable CO2 reservoir rock. We also characterize the overlying sealing unit and describe the geologic characteristics that influence the potential CO2 storage volume and reservoir performance. These characteristics include reservoir depth, gross thickness, net thickness, porosity, permeability, and groundwater salinity. Case-by-case strategies for estimating the pore volume existing within structurally and (or) stratigraphically closed traps are presented. Although assessment results are not contained in this report, the geologic information included herein will be employed to calculate the potential storage space in the various SAUs.

Incorporating reservoir heterogeneity with geostatistics to investigate waterflood recoveries

DOE Office of Scientific and Technical Information (OSTI.GOV)

Wolcott, D.S.; Chopra, A.K.

1993-03-01

This paper presents an investigation of infill drilling performance and reservoir continuity with geostatistics and a reservoir simulator. The geostatistical technique provides many possible realizations and realistic descriptions of reservoir heterogeneity. Correlation between recovery efficiency and thickness of individual sand subunits is shown. Additional recovery from infill drilling results from thin, discontinuous subunits. The technique may be applied to variations in continuity for other sandstone reservoirs.

Detrital zircon age distribution from Devonian and Carboniferous sandstone in the Southern Variscan Fold-and-Thrust belt (Montagne Noire, French Massif Central), and their bearings on the Variscan belt evolution

NASA Astrophysics Data System (ADS)

Lin, Wei; Faure, Michel; Li, Xian-hua; Chu, Yang; Ji, Wenbin; Xue, Zhenhua

2016-05-01

In the Southern French Massif Central, the Late Paleozoic sedimentary sequences of the Montagne Noire area provide clues to decipher the successive tectonic events that occurred during the evolution of the Variscan belt. Previous sedimentological studies already demonstrated that the siliciclastic deposits were supplied from the northern part of the Massif Central. In this study, detrital zircon provenance analysis has been investigated in Early Devonian (Lochkovian) conglomerate and sandstone, and in Carboniferous (Visean to Early Serpukhovian) sandstone from the recumbent folds and the foreland basin of the Variscan Southern Massif Central in Montagne Noire. The zircon grains from all of the samples yielded U-Pb age spectra ranging from Neoarchean to Late Paleozoic with several age population peaks at 2700 Ma, 2000 Ma, 980 Ma, 750 Ma, 620 Ma, 590 Ma, 560 Ma, 480 Ma, 450 Ma, and 350 Ma. The dominant age populations concentrate on the Neoproterozoic and Paleozoic. The dominant concordant detrital zircon age populations in the Lochkovian samples, the 480-445 Ma with a statistical peak around 450 Ma, are interpreted as reflecting the rifting event that separated several continental stripes, such as Armorica, Mid-German Crystalline Rise, and Avalonia from the northern part of Gondwana. However, Ediacaran and Cambrian secondary peaks are also observed. The detrital zircons with ages at 352 - 340 Ma, with a statistical peak around 350 Ma, came from the Early Carboniferous volcanic and plutonic rocks similar to those exposed in the NE part of the French Massif Central. Moreover, some Precambrian grains recorded a more complex itinerary and may have experienced a multi-recycling history: the Archean and Proterozoic grains have been firstly deposited in Cambrian or Ordovician terrigenous rocks, and secondly re-sedimented in Devonian and/or Carboniferous formations. Another possibility is that ancient grains would be inherited grains, scavenged from an underlying but not exposed Precambrian basement.

Fractures and stresses in Bone Spring sandstones

DOE Office of Scientific and Technical Information (OSTI.GOV)

Warpinski, N.R.; Sattler, A.R.; Lorenz, J.C.

This project was a collaboration between Sandia National Laboratories and the Harvey E. Yates Company (Heyco), Roswell, NM, conducted under the auspices of Department of Energy's Oil Recovery Technology Partnership. The project applied Sandia perspectives on the effects of natural fractures, stress, and sedimentology for the stimulation and production of low permeability gas reservoirs to low permeability oil reservoirs, such as those typified by the Bone Spring sandstones of the Delaware Basin, southeast New Mexico. This report details the results and analyses obtained in 1990 from core, logs, stress, and other data taken from three additional development wells. An overallmore » summary gives results from all five wells studied in this project in 1989--1990. Most of the results presented are believed to be new information for the Bone Spring sandstones.« less

Radon-222 content of natural gas samples from Upper and Middle Devonian sandstone and shale reservoirs in Pennsylvania—preliminary data

USGS Publications Warehouse

Rowan, E.L.; Kraemer, T.F.

2012-01-01

Samples of natural gas were collected as part of a study of formation water chemistry in oil and gas reservoirs in the Appalachian Basin. Nineteen samples (plus two duplicates) were collected from 11 wells producing gas from Upper Devonian sandstones and the Middle Devonian Marcellus Shale in Pennsylvania. The samples were collected from valves located between the wellhead and the gas-water separator. Analyses of the radon content of the gas indicated 222Rn (radon-222) activities ranging from 1 to 79 picocuries per liter (pCi/L) with an overall median of 37 pCi/L. The radon activities of the Upper Devonian sandstone samples overlap to a large degree with the activities of the Marcellus Shale samples.

The oceanic carbon cycle implicated in the d13Ccarb and the d13Corg variations from the terminal Ediacaran to the Early Cambrian

NASA Astrophysics Data System (ADS)

Ishikawa, T.; Ueno, Y.; Komiya, T.; Shu, D.; Li, Y.; Yoshida, N.; Maruyama, S.

2009-04-01

The terminal Neoproterozoic and its transition into the Cambrian witnessed major evolutionary and geochemical changes (e.g. Knoll, 1994). Evolutionary features include extinction and subsequent radiation events (e.g. Brasier, 1994; Knoll, 1994; Knoll and Carroll, 1999; Shu 2008). Geochemical changes comprise secular variations of the global carbon cycle expressed as variations of the d13C isotope records. A representative d13C curve for inorganic carbon (d13Ccarb) across the Precambrian/Cambrian boundary (Pc/C boundary) shows the existence of large fluctuations (e.g. Kirschvink et al., 1991; Narbonne et al., 1994; Kaufman et al., 1995; Amthor et al., 2003; Maloof et al., 2005, Ishikawa et al., 2008). This indicates a significant change of the oceanic carbon cycle at that time. On the other hand, the d13C values for total organic carbon (d13Corg) have rarely been reported together with the d13Ccarb across the boundary. Therefore, the precise relation between the d13Ccarb and the d13Corg and the global carbon cycle at the Pc/C boundary are still ambiguous. This work presents a first high-resolution d13Corg chemostratigraphy of drill core samples across the Pc/C boundary in the Three Gorges area, South China. Based on the results, this work additionally proposes variations of the sizes of the oceanic carbon reservoirs by a calculation of the carbon cycle model at the Pc/C boundary. The Three Gorges section extends from the uppermost Ediacaran dolostone (Dengying Formation), through the lowermost Early Cambrian muddy limestone (Yanjiahe Formation) to the middle Early Cambrian calcareous black shale (Shuijingtuo Formation). The ^13Corg values exhibit relatively invariant values averaging at -31 permil. By comparison between the d13Ccarb and d13Corg, we recognize two different terms in this period. The first term from the Pc/C boundary to the early Nemakit-Daldynian (ND) is characterized by the decoupling of d13Corg and d13Ccarb, stable d13Corg and the significant negative excursion of d13Ccarb, which could be explained by the carbon cycle with two reactive pools of inorganic and organic carbon, distinguished in the Neoproterozoic (Rothman et al., 2003; Fike et al., 2006; McFadden et al., 2008). The second term from the middle ND to Atdabanian is distinctive in parallel variation between the d13Ccarb and d13Corg, consistent with the conventional, steady-state models of the carbon cycle. We consider that the d13Corg of the carbon in an unusually large oceanic reservoir of organic carbon would not be driven by the variation of input and output fluxes because the residence time of such a large DOC reservoir could be longer than that of the inorganic carbon reservoir. We calculated masses of two reactive carbon reservoirs in the ocean, when the d13Ccarb varies from the terminal Neoproterozoic to the early Cambrian. According to the calculation, we suggest the significant negative d13Ccarb anomaly across the Pc/C boundary results from the increased remineralization of a large reservoir of organic carbon. Also we propose the two step increase of d13Ccarb in the early ND is derived from the two step increase in the sinking rate of organic particles. We interpret the large reservoir of organic carbon had dramatically declined in the late period of ND. In addition, we have estimated the fraction of buried organic carbon in the middle ND to Atdabanian, and found that the organic carbon burial was enhanced in the late ND, and then it increased from Tommotian to Atdabanian after a temporal reduction in basal-Tommotian. Hence, it implies the lowering of pCO2 and the subsequent global cooling in the late ND. This possibly caused the global-scale regression in the basal-Tommotian (Ripperdan, 1994), and led to the low organic carbon burial in the early Tommotian.

Numerical simulation of groundwater movement and managed aquifer recharge from Sand Hollow Reservoir, Hurricane Bench area, Washington County, Utah

USGS Publications Warehouse

Marston, Thomas M.; Heilweil, Victor M.

2012-01-01

The Hurricane Bench area of Washington County, Utah, is a 70 square-mile area extending south from the Virgin River and encompassing Sand Hollow basin. Sand Hollow Reservoir, located on Hurricane Bench, was completed in March 2002 and is operated primarily as a managed aquifer recharge project by the Washington County Water Conservancy District. The reservoir is situated on a thick sequence of the Navajo Sandstone and Kayenta Formation. Total recharge to the underlying Navajo aquifer from the reservoir was about 86,000 acre-feet from 2002 to 2009. Natural recharge as infiltration of precipitation was approximately 2,100 acre-feet per year for the same period. Discharge occurs as seepage to the Virgin River, municipal and irrigation well withdrawals, and seepage to drains at the base of reservoir dams. Within the Hurricane Bench area, unconfined groundwater-flow conditions generally exist throughout the Navajo Sandstone. Navajo Sandstone hydraulic-conductivity values from regional aquifer testing range from 0.8 to 32 feet per day. The large variability in hydraulic conductivity is attributed to bedrock fractures that trend north-northeast across the study area.A numerical groundwater-flow model was developed to simulate groundwater movement in the Hurricane Bench area and to simulate the movement of managed aquifer recharge from Sand Hollow Reservoir through the groundwater system. The model was calibrated to combined steady- and transient-state conditions. The steady-state portion of the simulation was developed and calibrated by using hydrologic data that represented average conditions for 1975. The transient-state portion of the simulation was developed and calibrated by using hydrologic data collected from 1976 to 2009. Areally, the model grid was 98 rows by 76 columns with a variable cell size ranging from about 1.5 to 25 acres. Smaller cells were used to represent the reservoir to accurately simulate the reservoir bathymetry and nearby monitoring wells; larger cells were used in the northern and southern portions of the model where water-level data were limited. Vertically, the aquifer system was divided into 10 layers, which incorporated the Navajo Sandstone and Kayenta Formation. The model simulated recharge to the groundwater system as natural infiltration of precipitation and as infiltration of managed aquifer recharge from Sand Hollow Reservoir. Groundwater discharge was simulated as well withdrawals, shallow drains at the base of reservoir dams, and seepage to the Virgin River. During calibration, variables were adjusted within probable ranges to minimize differences among model-simulated and observed water levels, groundwater travel times, drain discharges, and monthly estimated reservoir recharge.

Are seismic velocity time-lapse changes due to fluid substitution or matrix dissolution? A CO2 sequestration study at Pohokura Field, New Zealand

NASA Astrophysics Data System (ADS)

Adam, L.; Sim, C. Y.; Macfarlane, J.; van Wijk, K.; Shragge, J. C.; Higgs, K.

2015-12-01

Time-lapse seismic signatures can be used to quantify fluid saturation and pressure changes in a reservoir undergoing CO2 sequestration. However, the injection of CO2 acidifies the water, which may dissolve and/or precipitate minerals. Understanding the impact on the rock frame from field seismic time-lapse changes remains an outstanding challenge. Here, we study the effects of carbonate-CO2-water reactions on the physical and elastic properties of rock samples with variable volumes of carbonate cementation. The effects of fluid substitution alone (brine to CO2) and those due to the combination of fluid substitution and mineral dissolution on time-lapse seismic signatures are studied by combining laboratory data, geophysical well-log data and 1-D seismic modeling. Nine rocks from Pohokura Field (New Zealand) are reacted with carbonic acid. The elastic properties are measured using a high-density laser-ultrasonic setup. We observe that P-wave velocity changes up to -19% and correlate with sandstone grain size. Coarse-grained sandstones show greater changes in elastic wave velocities due to dissolution than fine-grained sandstones. To put this in perspective, this velocity change is comparable to the effect of fluid substitution from brine to CO2. This can potentially create an ambiguity in the interpretation of the physical processes responsible for time-lapse signatures in a CO2injection scenario. The laboratory information is applied onto well-log data to model changes in elastic properties of sandstones at the well-log scale. Well-logs and core petrographic analyses are used to find an elastic model that best describes the observed elastic waves velocities in the cemented reservoir sandstones. The Constant-cement rock physics model is found to predict the elastic behaviour of the cemented sandstones. A possible late-time sequestration scenario is that both mineral dissolution and fluid substitution occur in the reservoir. 1-D synthetic seismograms show that seismic amplitudes can change up to 126% in such a scenario. Our work shows that it is important to consider that time-lapse seismic signatures in carbonate-cemented reservoirs can result not only from fluid and pressure changes but also potentially from chemical reaction between CO2-water mixtures and carbonate cemented sandstones.

Cambrian rivers and floodplains: the significance of microbial cementation, groundwater and aeolian sediment transport

NASA Astrophysics Data System (ADS)

Reesink, A. J. H.; Best, J.; Freiburg, J. T.; Nathan, W.

2016-12-01

Rivers that existed before land plants colonized the Earth are commonly considered to be unaffected by microbial activity on their floodplains, because the limited cementation produced by microbial activity is insufficient to stabilize the river banks. Although this assumption is likely correct, such emphasis on channel dynamics ignores the potential role of floodplain dynamics as an integral component of the river system. Detailed analysis of cores from the Cambrian Mount Simon Sandstone, Illinois, suggests that a significant proportion of the terrestrial sequence is composed of flat-bedded `crinkly' structures that provide evidence of cementation by soil crusts and microbial biofilms, and that promoted the adhesion of sediment to sticky surfaces. Wind ripples and local desert pavements were abundant. These findings highlight that sediment deposition on Cambrian floodplains was often dominated by wind in locations where the ground water table reached the surface, and was thus likely independent of sediment transport within the river channel. Erosion by wind would thus have been hindered by surface cementation and the formation of desert pavements. Such ground water control on deposition, and resistance to erosion by floodplain surface hardening, appear to have been the primary controls on Cambrian floodplain topography. Because floodplain topography poses a key control on channel and floodplain flow, these processes may have affected patterns of erosion and deposition, as well as reach-scale dynamics such as channel avulsions. The autonomous operation of wind-and-groundwater controlled floodplains makes pre-vegetated river systems more sensitive to climatic conditions such as precipitation and evaporation, and strikingly different from those that occurred after the development of land plants.

Geology and oil and gas assessment of the Todilto Total Petroleum System, San Juan Basin Province, New Mexico and Colorado: Chapter 3 in Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

USGS Publications Warehouse

Ridgley, J.L.; Hatch, J.R.

2013-01-01

Organic-rich, shaly limestone beds, which contain hydrocarbon source beds in the lower part of the Jurassic Todilto Limestone Member of the Wanakah Formation, and sandstone reservoirs in the overlying Jurassic Entrada Sandstone, compose the Todilto Total Petroleum System (TPS). Source rock facies of the Todilto Limestone were deposited in a combined marine-lacustrine depositional setting. Sandstone reservoirs in the Entrada Sandstone were deposited in eolian depositional environments. Oil in Todilto source beds was generated beginning in the middle Paleocene, about 63 million years ago, and maximum generation of oil occurred in the middle Eocene. In the northern part of the San Juan Basin, possible gas and condensate were generated in Todilto Limestone Member source beds until the middle Miocene. The migration distance of oil from the Todilto source beds into the underlying Entrada Sandstone reservoirs was short, probably within the dimensions of a single dune crest. Traps in the Entrada are mainly stratigraphic and diagenetic. Regional tilt of the strata to the northeast has influenced structural trapping of oil, but also allowed for later introduction of water. Subsequent hydrodynamic forces have influenced the repositioning of the oil in some reservoirs and flushing in others. Seals are mostly the anhydrite and limestone facies of the Todilto, which thin to as little as 10 ft over the crests of the dunes. The TPS contains only one assessment unit, the Entrada Sandstone Conventional Oil Assessment Unit (AU) (50220401). Only four of the eight oil fields producing from the Entrada met the 0.5 million barrels of oil minimum size used for this assessment. The AU was estimated at the mean to have potential additions to reserves of 2.32 million barrels of oil (MMBO), 5.56 billion cubic feet of natural gas (BCFG), and 0.22 million barrels of natural gas liquids (MMBNGL).

STRUCTURAL HETEROGENEITIES AND PALEO FLUID FLOW IN AN ANALOG SANDSTONE RESERVOIR 2001-2004

DOE Office of Scientific and Technical Information (OSTI.GOV)

Pollard, David; Aydin, Atilla

2005-02-22

Fractures and faults are brittle structural heterogeneities that can act both as conduits and barriers with respect to fluid flow in rock. This range in the hydraulic effects of fractures and faults greatly complicates the challenges faced by geoscientists working on important problems: from groundwater aquifer and hydrocarbon reservoir management, to subsurface contaminant fate and transport, to underground nuclear waste isolation, to the subsurface sequestration of CO2 produced during fossil-fuel combustion. The research performed under DOE grant DE-FG03-94ER14462 aimed to address these challenges by laying a solid foundation, based on detailed geological mapping, laboratory experiments, and physical process modeling, onmore » which to build our interpretive and predictive capabilities regarding the structure, patterns, and fluid flow properties of fractures and faults in sandstone reservoirs. The material in this final technical report focuses on the period of the investigation from July 1, 2001 to October 31, 2004. The Aztec Sandstone at the Valley of Fire, Nevada, provides an unusually rich natural laboratory in which exposures of joints, shear deformation bands, compaction bands and faults at scales ranging from centimeters to kilometers can be studied in an analog for sandstone aquifers and reservoirs. The suite of structures there has been documented and studied in detail using a combination of low-altitude aerial photography, outcrop-scale mapping and advanced computational analysis. In addition, chemical alteration patterns indicative of multiple paleo fluid flow events have been mapped at outcrop, local and regional scales. The Valley of Fire region has experienced multiple episodes of fluid flow and this is readily evident in the vibrant patterns of chemical alteration from which the Valley of Fire derives its name. We have successfully integrated detailed field and petrographic observation and analysis, process-based mechanical modeling, and numerical simulation of fluid flow to study a typical sandstone aquifer/reservoir at a variety of scales. We have produced many tools and insights which can be applied to active subsurface flow systems and practical problems of pressing global importance.« less

Regional fluid migration in the Illinois basin: evidence from in situ oxygen isotope analysis of authigenic K-feldspar and quartz from the Mount Simon Sandstone

USGS Publications Warehouse

Chen, Zhensheng; Riciputi, Lee R.; Mora, Claudia I.; Fishman, Neil S.

2001-01-01

Oxygen isotope compositions of widespread, authigenic K-feldspar and quartz overgrowths and cements in the Upper Cambrian Mount Simon Sandstone were measured by ion microprobe in 11 samples distributed across the Illinois basin and its periphery. Average K-feldspar δ18O values increase systematically from +14‰ ± 1‰ in the southernmost and deepest samples in Illinois to +24‰ ± 2‰ in the northernmost outcrop sample in Wisconsin. A similar trend was observed for quartz overgrowths (22‰ ± 2‰ to 28‰ ± 2‰). Constant homogenization temperatures (100–130 °C) of fluid inclusions associated with quartz overgrowths throughout the basin suggest that the geographic trend in oxygen isotope compositions is a result of diagenetic modification of a south to north migrating basinal fluid.

Transport of Organic Contaminants Mobilized from Coal through Sandstone Overlying a Geological Carbon Sequestration Reservoir

DOE Office of Scientific and Technical Information (OSTI.GOV)

Zhong, Lirong; Cantrell, Kirk J.; Bacon, Diana H.

2014-02-01

Column experiments were conducted using a wetted sandstone rock installed in a tri-axial core holder to study the flow and transport of organic compounds mobilized by scCO2 under simulated geologic carbon storage (GCS) conditions. The sandstone rock was collected from a formation overlying a deep saline reservoir at a GCS demonstration site. Rock core effluent pressures were set at 0, 500, or 1000 psig and the core temperature was set at 20 or 50°C to simulate the transport to different subsurface depths. The concentrations of the organic compounds in the column effluent and their distribution within the sandstone core weremore » monitored. Results indicate that the mobility though the core sample was much higher for BTEX compounds than for naphthalene. Retention of organic compounds from the vapor phase to the core appeared to be primarily controlled by partitioning from the vapor phase to the aqueous phase. Adsorption to the surfaces of the wetted sandstone was also significant for naphthalene. Reduced temperature and elevated pressure resulted in greater partitioning of the mobilized organic contaminants into the water phase.« less

Composition of natural gas and crude oil produced from 10 wells in the Lower Silurian "Clinton" Sandstone, Trumbull County, Ohio: Chapter G.7 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Burruss, Robert A.; Ryder, Robert T.; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

Natural gases and associated crude oils in the “Clinton” sandstone, Medina Group sandstones, and equivalent Tuscarora Sandstone in the northern Appalachian basin are part of a regional, continuous-type or basin-centered accumulation. The origin of the hydrocarbon charge to regional continuoustype accumulations is poorly understood. We have analyzed the molecular and stable isotopic composition of gases and oils produced from 10 wells in the “Clinton” sandstone in Trumbull County, Ohio, in an initial attempt to identify the characteristics of the accumulated fluids. The analyses show that the fluids have remarkably uniform compositions that are similar to previously published analyses of oils (Cole and others, 1987) and gases (Laughrey and Baldasarre, 1998) in Early Silurian reservoirs elsewhere in Ohio; however, geochemical parameters in the oils and gases suggest that the fluids have experienced higher levels of thermal stress than the present-day burial conditions of the reservoir rocks. The crude oils have an unusual geochemical characteristic: they do not contain detectable levels of sterane and triterpane biomarkers. The origin of these absences is unknown.

Geologic map of the Nelson quadrangle, Lewis and Clark County, Montana

USGS Publications Warehouse

Reynolds, Mitchell W.; Hays, William H.

2003-01-01

The geologic map of the Nelson quadrangle, scale 1:24,000, was prepared as part of the Montana Investigations Project to provide new information on the stratigraphy, structure, and geologic history of an area in the geologically complex southern part of the Montana disturbed belt. In the Nelson area, rocks ranging in age from Middle Proterozoic through Cretaceous are exposed on three major thrust plates in which rocks have been telescoped eastward. Rocks within the thrust plates are folded and broken by thrust faults of smaller displacement than the major bounding thrust faults. Middle and Late Tertiary sedimentary and volcaniclastic rocks unconformably overlie the pre-Tertiary rocks. A major normal fault displaces rocks of the western half of the quadrangle down on the west with respect to strata of the eastern part. Alluvial and terrace gravels and local landslide deposits are present in valley bottoms and on canyon walls in the deeply dissected terrain. Different stratigraphic successions are exposed at different structural levels across the quadrangle. In the northeastern part, strata of the Middle Cambrian Flathead Sandstone, Wolsey Shale, and Meagher Limestone, the Middle and Upper Cambrian Pilgrim Formation and Park Shale undivided, the Devonian Maywood, Jefferson, and lower part of the Three Forks Formation, and Lower and Upper Mississippian rocks assigned to the upper part of the Three Forks Formation and the overlying Lodgepole and Mission Canyon Limestones are complexly folded and faulted. These deformed strata are overlain structurally in the east-central part of the quadrangle by a succession of strata including the Middle Proterozoic Greyson Formation and the Paleozoic succession from the Flathead Sandstone upward through the Lodgepole Limestone. In the east-central area, the Flathead Sandstone rests unconformably on the middle part of the Greyson Formation. The north edge, northwest quarter, and south half of the quadrangle are underlain by a succession of rocks that includes not only strata equivalent to those of the remainder of the quadrangle, but also the Middle Proterozoic Newland, Greyson, and Spokane Formations, Pennsylvanian and Upper Mississippian Amsden Formation and Big Snowy Group undivided, the Permian and Pennsylvanian Phosphoria and Quadrant Formations undivided, the Jurassic Ellis Group and Lower Cretaceous Kootenai Formation. Hornblende diorite sills and irregular bodies of probable Late Cretaceous age intrude Middle Proterozoic, Cambrian and Devonian strata. No equivalent intrusive rocks are present in structurally underlying successions of strata. In this main part of the quadrangle, the Flathead Sandstone cuts unconformably downward from south to north across the Spokane Formation into the upper middle part of the Greyson Formation. Tertiary (Miocene?) strata including sandstone, pebble and cobble conglomerate, and vitric crystal tuff underlie, but are poorly exposed, in the southeastern part of the quadrangle where they are overlain by late Tertiary and Quaternary gravel. The structural complexity of the quadrangle decreases from northeast to southwest across the quadrangle. At the lowest structural level (Avalanche Butte thrust plate) exposed in the canyon of Beaver Creek, lower and middle Paleozoic rocks are folded in northwest-trending east-inclined disharmonic anticlines and synclines that are overlain by recumbently folded and thrust faulted Devonian and Mississippian rocks. The Mississippian strata are imbricated adjacent to the recumbent folds. In the east-central part of the quadrangle, a structurally overlying thrust plate, likely equivalent to the Hogback Mountain thrust plate of the Hogback Mountain quadrangle adjacent to the east (Reynolds, 20xx), juxtaposes recumbently folded Middle Proterozoic and unconformably overlying lower Paleozoic rocks on the complexly folded and faulted rocks of the Avalanche Butte thrust plate. The highest structural plate, bounded below

DOE Office of Scientific and Technical Information (OSTI.GOV)

Oldham, D.W.

Commercial quantities of gas have been produced from shallow sandstone reservoirs of the Tongue River Member of the Fort Union Formation (Paleocene) in the Wyoming portion of the Powder River Basin. The two largest accumulations discovered to date, Oedekoven and Chan pools, were drilled on prospects which invoked differential compaction as a mechanism for gas entrapment and prospect delineation. Coal-sourced bacterial gas may have accumulated in localized structural highs early in the burial history of lenticular sand bodies and associated sediments. Structural relief is due to the compaction contrast between sand and stratigraphically equivalent fine-grained sediments. A shallow gas playmore » targeting sandstones as potential reservoirs was initiated in the Recluse area in response as sources for bacterial gas, and the presence of lenticular sandstones that may have promoted the development of compaction structures early in the burial process, to which early-formed bacterial gas migrated. Prospects were ranked based on a number of geologic elements related to compaction-induced trap development. Drilling of the Oedekoven prospect, which possessed all prospect elements, led to the discovery and development of the Oedekoven Fort Union gas pool, which has produced nearly 2 BCF of gas from a depth of 340 ft. Production figures from the Oedekoven and Chan pools demonstrate the commercial gas potential of Fort Union sandstone reservoirs in the Powder River Basin. The shallow depths of the reservoirs, coupled with low drilling and completion costs, an abundance of subsurface control with which to delineate prospects, and an existing network of gas-gathering systems, make them attractive primary targets in shallow exploration efforts as well as secondary objectives in deeper drilling programs.« less

Seismic data interpretation for hydrocarbon potential, for Safwa/Sabbar field, East Ghazalat onshore area, Abu Gharadig basin, Western Desert, Egypt

NASA Astrophysics Data System (ADS)

Hameed El Redini, Naser A.; Ali Bakr, Ali M.; Dahroug, Said M.

2017-12-01

Safwa/Sabbar oil field located in the East Ghazalat Concession in the proven and prolific Abu Gharadig basin, Western Desert, Egypt, and about 250 km to the southwest of Cairo, it's located in the vicinity of several producing oil fields ranging from small to large size hydrocarbon accumulation, adjacent to the NW-SE trending major Abu Gharadig fault which is throwing to the Southwest. All the geological, "structure and stratigraphic" elements, have been identified after interpreting the recent high quality 3D seismic survey for prospect generation, evaluation and their relation to the hydrocarbon exploration. Synthetic seismograms have been carried out for all available wells to tie horizons to seismic data and to define the lateral variation characters of the beds. The analysis has been done using the suitable seismic attributes to understand the characteristics of different types of the reservoir formations, type of trap system, identify channels and faults, and delineating the stratigraphic plays of good reservoirs such as Eocene Apollonia Limestone, AR "F", AR "G" members, Upper Bahariya, Jurassic Khatatba Sandstone, upper Safa and Lower Safa Sandstone. The top Cenomanian Bahariya level is the main oil reservoir in the Study area, which consist of Sandstone, Siltstone and Shale, the thickness is varying from 1 to 50 ft along the study area. In addition to Upper-Bahariya there are a good accessibility of hydrocarbon potential within the Jurassic Khatatba Sandstone and the Eocene Apollonia Limestone. More exploring of these reservoirs are important to increase productivity of Oil and/or Gas in the study area.

Depositional systems and diagenesis of Travis Peak tight gas sandstone reservoirs, Sabine Uplift Area, Texas

DOE Office of Scientific and Technical Information (OSTI.GOV)

Fracasso, M.A.; Dutton, S.P.; Finley, R.J.

The Travis Peak formation (lower Cretaceous) in the eastern East Texas basin is a fluvio-deltaic depositional system divided into large-scale facies packages: a middle sandstone-rich fluvial and delta-plain sequence that is gradationally overlain and underlain by a marine-influenced delta-fringe zone with a higher mudstone content. Domes and structural terraces on the west flank of the Sabine Uplift influenced deposition of Travis Peak sediments, and most Travis Peak gas production in this area is from thin sandstones (<25 ft(<7.6 m) thick) in the upper delta-fringe facies. The trapping mechanism is stratigraphic pinch-out of sandstones or porosity zones within sandstone, or both,more » on the flanks of structures. Detailed mapping of producing sandstone sequences in the uppermost upper delta-fringe on the western flank of the Bethany structure has delineated fluvial channelways, distributary or tidal channels, and barrier of distributary-mouth bars. Most Travis Peak gas production in the Bethany West area is from the bases of channel sandstones in a marine-influenced facies belt. Travis Peak sandstones in the eastern East Texas basin have undergone a complex series of diagenetic modifications. Precipitation of authigenic quartz, ankerite, dolomite, illite, and chlorite and the introduction of reservoir bitumen were the most important causes of occlusion of primary porosity and reduction of permeability. Permeability decreases with depth in the Travis Peak, which suggests that the diagenetic processes that caused extensive cementation and resultant low permeability throughout most of the formation operated less completely on sediments deposited near the top of the succession.« less

Advanced Reservoir Characterization and Development through High-Resolution 3C3D Seismic and Horizontal Drilling: Eva South Marrow Sand Unit, Texas County, Oklahoma

DOE Office of Scientific and Technical Information (OSTI.GOV)

Wheeler,David M.; Miller, William A.; Wilson, Travis C.

2002-03-11

The Eva South Morrow Sand Unit is located in western Texas County, Oklahoma. The field produces from an upper Morrow sandstone, termed the Eva sandstone, deposited in a transgressive valley-fill sequence. The field is defined as a combination structural stratigraphic trap; the reservoir lies in a convex up -dip bend in the valley and is truncated on the west side by the Teepee Creek fault. Although the field has been a successful waterflood since 1993, reservoir heterogeneity and compartmentalization has impeded overall sweep efficiency. A 4.25 square mile high-resolution, three component three-dimensional (3C3D) seismic survey was acquired in order tomore » improve reservoir characterization and pinpoint the optimal location of a new horizontal producing well, the ESU 13-H.« less

Consolidation of geologic studies of geopressured-geothermal resources in Texas: Barrier-bar tidal-channel reservoir facies architecture, Jackson Group, Prado Field, South Texas

DOE Office of Scientific and Technical Information (OSTI.GOV)

Seni, S.J.; Choh, S.J.

1993-09-01

Sandstone reservoirs in the Jackson barrier/strandplain play are characterized by low recovery efficiencies and thus contain a large hydrocarbon resource target potentially amenable to advanced recovery techniques. Prado field, Jim Hogg County, South Texas, has produced over 23 million bbl of oil and over 32 million mcf gas from combination structural-stratigraphic traps in the Eocene lower Jackson Group. Hydrocarbon entrapment at Prado field is a result of anticlinal nosing by differential compaction and updip pinch-out of barrier bar sandstone. Relative base-level lowering resulted in forced regression that established lower Jackson shoreline sandstones in a relatively distal location in central Jimmore » Hogg County. Reservoir sand bodies at Prado field comprise complex assemblages of barrier-bar, tidal-inlet fill, back-barrier bar, and shoreface environments. Subsequent progradation built the barrier-bar system seaward 1 to 2 mi. With the barrier-bar system, favorable targets for hydrocarbon reexploration are concentrated in tidal-inlet facies because they possess the greatest degree of depositional heterogeneity.« less

Description and correlation of reservoir heterogenity within the Big Injun sandstone, Granny Creek field, West Virginia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Vargo, A.; McDowell, R.; Matchen, D.

1992-01-01

The Granny Creek field (approximately 6 sq. miles in area), located in Clay and Roane counties, West Virginia, produces oil from the Big Injun sandstone (Lower Mississippian). Analysis of 15 cores, 22 core analyses, and approximately 400 wireline logs (gamma ray and bulk density) show that the Big Injun (approximately 12 to 55 feet thick) can be separated into an upper, coarse-grained sandstone and a lower, fine-grained sandstone. The Big Injun is truncated by an erosional unconformity of Early to Middle Mississippian age which removes the coarse-grain upper unit in the northwest portion of the field. The cores show nodulesmore » and zones (1 inch to 6 feet thick) of calcite and siderite cement. Where the cements occur as zones, porosity and permeability are reduced. Thin shales (1 inch to 1 foot thick) are found in the coarse-grained member of the Big Injun, whereas the bottom of the fine-grained, lower member contains intertongues of dark shale which cause pinchouts in porosity at the bottom of the reservoir. Calcite and siderite cement are recognized on wireline logs as high bulk density zones that form horizontal, inclined, and irregular pods of impermeable sandstone. At a 400 foot well spacing, pods may be confined to a single well or encompass as many as 30 wells creating linear and irregular barriers to flow. These pods increase the length of the fluid flow path and may divide the reservoir into discrete compartments. The combination of sedimentologic and diagenetic features contribute to the heterogeneity observed in the field.« less

Geophysical Characterization for Potential Carbon Dioxide Sequestration in the Black Warrior Basin of Alabama

NASA Astrophysics Data System (ADS)

Goodliffe, A. M.; Harris, W.; Rutter, R. S.; Clark, P.; Pashin, J. C.; Esposito, R. A.

2011-12-01

The southeastern US is a leading producer of carbon dioxide emissions in large part due to the high number of coal-fired power plants in the region. As part of a Department of Energy (DOE) National Energy Technology Laboratory (NETL) funded geological characterization project we have collected a number of geophysical data sets that characterize the Black Warrior Basin in the vicinity of the Alabama Power Gorgas Steam Plant in Walker County, Alabama. These geophysical data sets are important for extending the results from our 8000-foot characterization hole throughout the basin. Two 5-mile seismic reflection profiles processed through pre-stack time migration image the Cambrian through Pennsylvanian stratigraphy in the basin. The major injection targets in the saline reservoirs of the Hartselle Sandstone, Tuscumbia Limestone, Stones River Group and Knox Group. Initial examination of the data show that it is well suited for techniques such as Amplitude Versus Offset (AVO) analysis and inversion with the downhole data. Multiple offset vertical seismic profiles (VSP) image the formations close to and at multiple azimuths away from the drill hole. These VSPs also provide an important link to the seismic reflection profiles, which pass a little less than a mile to the north of the drill hole. Three shallow microseismic wells in the vicinity of the main drill hole have 3-component geophones cemented at depths of 50, 150, and 250 foot. These wells, designed to record small magnitude seismic events resulting from low-volume water injection, are important for characterizing the local fracture pathways and stress fields. Downhole gravity data complements the usual suite of downhole tools by imaging density variations deeper into the formations and ensuring that the identified saline reservoirs are not locally discontinuous.

Fractures and stresses in Bone Spring sandstones. Final report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Warpinski, N.R.; Sattler, A.R.; Lorenz, J.C.

This project was a collaboration between Sandia National Laboratories and the Harvey E. Yates Company (Heyco), Roswell, NM, conducted under the auspices of Department of Energy`s Oil Recovery Technology Partnership. The project applied Sandia perspectives on the effects of natural fractures, stress, and sedimentology for the stimulation and production of low permeability gas reservoirs to low permeability oil reservoirs, such as those typified by the Bone Spring sandstones of the Delaware Basin, southeast New Mexico. This report details the results and analyses obtained in 1990 from core, logs, stress, and other data taken from three additional development wells. An overallmore » summary gives results from all five wells studied in this project in 1989--1990. Most of the results presented are believed to be new information for the Bone Spring sandstones.« less

Assessment of undiscovered oil and gas resources in sandstone reservoirs of the Cotton Valley Group, U.S. Gulf Coast, 2015

USGS Publications Warehouse

Eoff, Jennifer D.; Biewick, Laura R.H.; Brownfield, Michael E.; Burke, Lauri; Charpentier, Ronald R.; Dubiel, Russell F.; Gaswirth, Stephanie B.; Gianoutsos, Nicholas J.; Kinney, Scott A.; Klett, Timothy R.; Leathers, Heidi M.; Mercier, Tracey J.; Paxton, Stanley T.; Pearson, Ofori N.; Pitman, Janet K.; Schenk, Christopher J.; Tennyson, Marilyn E.; Whidden, Katherine J.

2015-08-11

Using a geology-based assessment methodology, the U.S. Geological Survey estimated undiscovered mean volumes of 14 million barrels of conventional oil, 430 billion cubic feet of conventional gas, 34,028 billion cubic feet of continuous gas, and a mean total of 391 million barrels of natural gas liquids in sandstone reservoirs of the Upper Jurassic–Lower Cretaceous Cotton Valley Group in onshore lands and State waters of the U.S. Gulf Coast region.

Regional Big Injun (Price/Pocono) subsurface stratigraphy of West Virginia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Donaldson, A.C.; Zou, Xiangdong

1992-01-01

The lower Big Injun (Lower Mississippian) is the oil reservoir of the Granny Creek and Rock Creek fields and consists of multiple sandstones that were deposited in different fluvial-deltaic depositional environments. These multiple sandstones became amalgamated and now appear as a widespread blanket sandstone as a result of ancient cut and fill processes associated with river-channel sedimentation. The regional study of this Price Formation subsurface equivalent considers the continuity and thickness variations of the composite sandstones of the Big Injun mainly within western West Virginia. The major fluvial drainage system apparently flowed southward through Ohio (much of it later erodedmore » by the pre-Pottsville unconformity) during Big Injun time (and earlier) and part of the system was diverted into southwestern West Virginia as vertically stacked channel and river-mouth bar deposits (Rock Creek field). This ancient Ontario River system apparently drained a huge area including the northern craton as well as the orogenic belt. The emerging West Virginia Dome probably sourced the sediment transported by small rivers developing southwestward prograding deltas across Clay County (Granny Creek field). Sedimentation was affected by differential subsidence in the basin. Paleovalley fill was considered for areas with vertically stacked sandstones, but evidence for their origin is not convincing. Oil-reservoir sandstones are classified as dip-trending river channel (D1) and deltaic shoreline (D2) deposits.« less

Deep-water facies and petrography of the Galoc clastic unit, offshore Palawan, Philippines (south China Sea)

DOE Office of Scientific and Technical Information (OSTI.GOV)

Link, M.H.; Helmold, K.P.

1988-02-01

The lower Miocene Galoc clastic unit, offshore Palawan, Philippines, is about 500-600 ft thick. The unit overlies the Galoc Limestone and is overlain by the Pelitic Pagasa Formation. The Galoc clastic unit consists of alternating quartzose sandstone, mudstone, and resedimented carbonate deposited at bathyal depths, mainly as turbidites. The deep-water deposits are confined to the axis of a northeast-trending trough in which slope, submarine channel, interchannel, depositional lobe, slump, and basinal facies are recognized. Eroded shallow-marine carbonate lithoclasts are commonly incorporated within the siliciclastic turbidites. The main reservoir sandstones occur in submarine channels and depositional lobes. The sandstones are texturallymore » submature, very fine to medium-grained feldspathic litharenites and subarkoses. The sandstones have detrital modes of Q78:F11:L11 and Qm51:F11:Lt38, with partial modes of the monocrystalline components of Qm82:P13:K5. Lithic fragments include chert, shale, schist, volcanic rock fragments, and minor plutonic rock fragments. Porosity in the better reservoir sandstones ranges from 11 to 25%, and calcite is the dominant cement. Dissolution textures and inhomogeneity of calcite distribution suggest that at least half of the porosity in the sandstones has formed through the leaching of calcite cement and labile framework grains. A source terrain of quartzo-feldspathic sediments and metasediments, chert, volcanics, and acid-intermediate plutonic rocks is visualized.« less

Experimental Study of Cement - Sandstone/Shale - Brine - CO2 Interactions

PubMed Central

2011-01-01

Background Reactive-transport simulation is a tool that is being used to estimate long-term trapping of CO2, and wellbore and cap rock integrity for geologic CO2 storage. We reacted end member components of a heterolithic sandstone and shale unit that forms the upper section of the In Salah Gas Project carbon storage reservoir in Krechba, Algeria with supercritical CO2, brine, and with/without cement at reservoir conditions to develop experimentally constrained geochemical models for use in reactive transport simulations. Results We observe marked changes in solution composition when CO2 reacted with cement, sandstone, and shale components at reservoir conditions. The geochemical model for the reaction of sandstone and shale with CO2 and brine is a simple one in which albite, chlorite, illite and carbonate minerals partially dissolve and boehmite, smectite, and amorphous silica precipitate. The geochemical model for the wellbore environment is also fairly simple, in which alkaline cements and rock react with CO2-rich brines to form an Fe containing calcite, amorphous silica, smectite and boehmite or amorphous Al(OH)3. Conclusions Our research shows that relatively simple geochemical models can describe the dominant reactions that are likely to occur when CO2 is stored in deep saline aquifers sealed with overlying shale cap rocks, as well as the dominant reactions for cement carbonation at the wellbore interface. PMID:22078161

Types of stratigraphic traps in Lower Cretaceous Muddy Formation, northern Powder River Basin, Wyoming

DOE Office of Scientific and Technical Information (OSTI.GOV)

Lovekin, J.R.; Odland, S.K.; Quartarone, T.S. Gardner, M.H.

1986-08-01

Stratigraphic traps account for most of the oil produced from the Muddy Sandstone in the northern Powder River basin. Two categories of traps exist. The first trap type is the result of lateral and vertical facies changes. Reservoir facies include tidal channels, point bars, bayhead deltas, barrier islands, and strand-plain sandstones; trapping facies include bay-fill and estuarine sediments, mud-filled tidal channels, and flood-plain deposits. The second of the two categories of traps results from an unconformity that juxtaposes permeable and impermeable sediments of quite different ages. Structural and diagenetic factors often modify and locally enhance reservoir quality within both categoriesmore » of stratigraphic traps. The various types of traps are demonstrated by studies of six field areas: (1) barrier-island sandstones, sealed updip by back-barrier shales, produce at Ute and Kitty fields; (2) tidal channels produce at Collums and Kitty fields; (3) bayhead deltas, encased in estuarine sediments, form traps at Oedekoven and Kitty fields; (4) fluvial point-bar sandstones form traps at Oedekoven, Store, and Kitty fields; (5) unconformity-related traps exist where Muddy fluvial valley-fill sediments lap out against impermeable valley walls of Skull Creek Shale on the updip side at Store, Oedekoven, and Kitty fields; and (6) the clay-rich weathered zone, directly beneath an intraformational unconformity, forms the seal to the reservoirs at Amos Draw field.« less

Sequence stratigraphy of the Aux Vases Sandstone: A major oil producer in the Illinois basin

USGS Publications Warehouse

Leetaru, H.E.

2000-01-01

The Aux Vases Sandstone (Mississippian) has contributed between 10 and 25% of all the oil produced in Illinois. The Aux Vases is not only an important oil reservoir but is also an important source of groundwater, quarrying stone, and fluorspar. Using sequence stratigraphy, a more accurate stratigraphic interpretation of this economically important formation can be discerned and thereby enable more effective exploration for the resources contained therein. Previous studies have assumed that the underlying Spar Mountain, Karnak, and Joppa formations interfingered with the Aux Vases, as did the overlying Renault Limestone. This study demonstrates that these formations instead are separated by sequence boundaries; therefore, they are not genetically related to each other. A result of this sequence stratigraphic approach is the identification of incised valleys, paleotopography, and potential new hydrocarbon reservoirs in the Spar Mountain and Aux Vases. In eastern Illinois, the Aux Vases is bounded by sequence boundaries with 20 ft (6 m) of relief. The Aux Vases oil reservoir facies was deposited as a tidally influenced siliciclastic wedge that prograded over underlying carbonate-rich sediments. The Aux Vases sedimentary succession consists of offshore sediment overlain by intertidal and supratidal sediments. Low-permeability shales and carbonates typically surround the Aux Vases reservoir sandstone and thereby form numerous bypassed compartments from which additional oil can be recovered. The potential for new significant oil fields within the Aux Vases is great, as is the potential for undrained reservoir compartments within existing Aux Vases fields.

Paleozoic fluid history of the Michigan Basin: Evidence from dolomite geochemistry in the Middle Ordovician St. Peter Sandstone

DOE Office of Scientific and Technical Information (OSTI.GOV)

Winter, B.L.; Johnson, C.M.; Simo, J.A.

1995-04-03

The isotope (Sr and O) and elemental (Mg, Ca, Mn, Fe, and Sr) compositions of the various dolomites in the Middle Ordovician St. Peter Sandstone in the Michigan Basin are determined and the variations are modeled in terms of fluid-rock interaction or as mixing relations. These geochemical models, combined with the paragenetic sequence of the dolomites and late anhydrite cement, suggest the existence of at least four distinct diagenetic fluids in the St. Peter Sandstone during the paleozoic. Fluid 1 has a composition consistent with a modified older (pre-Middle Ordovician) seawater origin, which indicates that the flow path for thismore » fluid had a major upward component. This fluid resulted in the first and volumetrically most important burial dolomitization event, producing dolomite in both carbonate and quartz sandstone lithofacies in the St. Peter Sandstone. Fluid 2 has a composition consistent with a modified Middle to early Late Ordovician seawater origin, suggesting a major downward component for fluid flow. Fluid 2 produced dolomite cement in the carbonate lithofacies that postdates Fluid 1 dolomite. The composition of Fluid 3 is best interpreted to reflect a heated, deep basinal brine that had previously interacted with the K-feldspar-rich rocks near the Cambrian-Precambrian unconformity in the Michigan Basin, indicating a major upward component for fluid flow. Fluid 3 produced dolomite cement in quartz sandstone lithofacies that postdates Fluid 1 dolomite. Fluid 4 resulted in precipitation of late anhydrite in fractures. The {sup 87}Sr/{sup 86}Sr ratio of the anhydrite is consistent with Fluid 4 originating as a dilute fluid that interacted extensively with Silurian gypsum in the Michigan Basin; this indicates that the flow path of Fluid 4 had a major downward component.« less

Earliest Phanerozoic or latest Proterozoic fossils from the Arabian Shield

USGS Publications Warehouse

Cloud, P.; Awramik, S.M.; Morrison, K.; Hadley, D.G.

1979-01-01

We report here the first biologically definable fossils from pre-Saq (pre-Middle Cambrian) rocks of the Arabian Shield. They include the distinctive helically coiled tubular filaments of the oscillatorialean blue-green alga Obruchevella parva as well as two size classes of spheroidal unicells of uncertain affinity. Also present is the conical stromatolite Conophyton and unidentified stromatolites. All occur in cherty limestones of the Jubaylah Group, northern Saudi Arabia, a nonmarine to locally marine taphrogeosynclinal sequence that fills depressions along the northwest-trending Najd faults. Conophyton has heretofore been found only in strata older than about 680 Ma (except for puzzling records in modern hot springs) while Obruchevella is so far known only from rocks between about 680 and 470 Ma old. Thus it appears that the Jubaylah Group is close to the Proterozoic-Phanerozoic transition. The simple spheroidal nanno-fossils are not diagnostic as to age. Their relationships within what appears to be early diagenetic chert suggest a classical algal-mat association. The brecciated and microchanneled appearance of much of the fossiliferous rock, its locally dolomitic nature, and the prevalence of cryptalgalaminate favors a very shallow, locally turbulent, and perhaps episodically exposed marine or marginal marine setting. The Jubaylah Group lies unconformably beneath the Siq Sandstone (basal member of the Saq Sandstone) of medial Cambrian age, rests nonconformably on crystalline basement, and has yielded a K-Ar whole-rock age (on andesitic basalt) of ???540 Ma. To judge from the fossils, however, that age may be as much as 100 Ma or more too young. ?? 1979.

Effects of CO 2 on mechanical variability and constitutive behavior of the Lower Tuscaloosa formation, Cranfield Injection Site, USA

DOE PAGES

Rinehart, Alex J.; Dewers, Thomas A.; Broome, Scott T.; ...

2016-08-25

We characterize geomechanical constitutive behavior of reservoir sandstones at conditions simulating the “Cranfield” Southeast Regional Carbon Sequestration Partnership injection program. From two cores of Lower Tuscaloosa Formation, three sandstone lithofacies were identified for mechanical testing based on permeability and lithology. These include: chlorite-cemented conglomeratic sandstone (Facies A); quartz-cemented fine sandstone (Facies B); and quartz- and calcite-cemented very fine sandstone (Facies C). We performed a suite of compression tests for each lithofacies at 100 °C and pore pressure of 30 MPa, including hydrostatic compression and triaxial tests at several confining pressures. Plugs were saturated with supercritical CO 2-saturated brine. Chemical environmentmore » affected the mechanical response of all three lithofacies, which experience initial plastic yielding at stresses far below estimated in situ stress. Measured elastic moduli degradation defines a secondary yield surface coinciding with in situ stress for Facies B and C. Facies A shows measurable volumetric creep strain and a failure envelope below estimates of in situ stress, linked to damage of chlorite cements by acidic pore solutions. Furthermore, the substantial weakening of a particular lithofacies by CO 2 demonstrates a possible chemical-mechanical coupling during injection at Cranfield with implications for CO 2 injection, reservoir permeability stimulation, and enhanced oil recovery.« less

Geologic model of a small, intraslope basin: Garden Banks 72 field, offshore Louisiana

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kolb, R.A.; Tuller, J.N.; Link, M.H.

1989-03-01

Garden Banks 72 field is 115 mi off the Louisiana coast and lies near the shelf-slope break in water depths ranging from 450 to 800 ft. During the middle Pleistocene, the area was the site of a small, restricted basin on the upper slope, into which turbidite sandstones were deposited. These sandstones have been slumped, uplifted, and faulted, forming oil and gas traps in the field. Mobil and partners AGIP and Kerr-McGee leased block 72 in 1984. Three wells and two sidetracks have been drilled, discovering oil and gas in middle Pleistocene sandstones. A total of 650 ft of coremore » was cut in two wells. Geologic data in the block have been supplemented by 2-D and 3-D seismic surveys. Trapping mechanisms in the field are both structural and stratigraphic. The structural high is on the southwest flank of a northwest-southeast-trending shale/salt ridge. The middle Pleistocene reservoir sandstones trend northeast, and their seismic signature consists of discontinuous, hummocky reflections; the presence of hydrocarbons in these sandstones causes anomalous seismic responses. Amplitude terminations often cross structural contours, implying stratigraphic pinch-outs. Data from electric logs, seismic, and cores demonstrate that the middle Pleistocene reservoir sandstones are the result of deposition by turbidites into a small, restricted basin. Associated facies identified include channels, levees, and possible sheet (lobe) sandstones. Postdepositional activity has included slumping and reworking by bottom currents (contour currents ). The resulting depositional model for this field can be applied to many of the recent discoveries in the Flexure trend.« less

Preliminary seismic characterization of parts of the island of Gotland in preparation for a potential CO2 storage test site

NASA Astrophysics Data System (ADS)

Lydersen, Ida; Sopher, Daniel; Juhlin, Christopher

2015-04-01

Geological storage of CO2 is one of the available options to reduce CO2-emissions from large point sources. Previous work in the Baltic Sea Basin has inferred a large storage potential in several stratigraphic units. The most promising of these is the Faludden sandstone, exhibiting favorable reservoir properties and forming a regional stratigraphic trap. A potential location for a pilot CO2 injection site, to explore the suitability of the Faludden reservoir is onshore Gotland, Sweden. In this study onshore and offshore data have been digitized and interpreted, along with well data, to provide a detailed characterization of the Faludden reservoir below parts of Gotland. Maps and regional seismic profiles describing the extent and top structure of the Faludden sandstone are presented. The study area covers large parts of the island of Gotland, and extends about 50-70km offshore. The seismic data presented is part of a larger dataset acquired by Oljeprospektering AB (OPAB) between 1970 and 1990. The dataset is to this date largely unpublished, therefore re-processing and interpretation of these data provide improved insight into the subsurface of the study area. Two longer seismic profiles crossing Gotland ENE-WSW have been interpreted to give a large scale, regional control of the Faludden sandstone. A relatively tight grid of land seismic following the extent of the Faludden sandstone along the eastern coast to the southernmost point has been interpreted to better understand the actual distribution and geometry of the Faludden sandstone beneath Gotland. The maps from this study help to identify the most suitable area for a potential test injection site for CO2-storage, and to further the geological understanding of the area in general.

Diagenesis and reservoir quality of Bhuban sandstones (Neogene), Titas Gas Field, Bengal Basin, Bangladesh

NASA Astrophysics Data System (ADS)

Aminul Islam, M.

2009-06-01

This study deals with the diagenesis and reservoir quality of sandstones of the Bhuban Formation located at the Titas Gas Field of Bengal Basin. Petrographic study including XRD, CL, SEM and BSE image analysis and quantitative determination of reservoir properties were carried out for this study. The sandstones are fine to medium-grained, moderately well to well sorted subfeldspathic arenites with subordinate feldspathic and lithic arenites. The diagenetic processes include clay infiltration, compaction and cementation (quartz overgrowth, chlorite, kaolinite, calcite and minor amount of pyrite, dolomite and K-feldspar overgrowth). Quartz is the dominant pore occluding cement and generally occurred as small euhedral crystals, locally as large pyramidal crystals in the primary pores. Pressure solution derived from grain contact is the main contributor of quartz overgrowths. Chlorite occurs as pore-lining and pore filling cement. In some cases, chlorite helps to retain porosity by preventing quartz overgrowth. In some restricted depth interval, pore-occlusion by calcite cement is very much intense. Kaolinite locally developed as vermiform and accelerated the minor porosity loss due to pore-occlusion. Kaolinite/chlorite enhances ineffective microporosity. Kaolinite is a by-product of feldspar leaching in the presence of acidic fluid produced during the maturation of organic matter in the adjacent Miocene or deeper Oligocene source rocks. The relation between diagenesis and reservoir quality is as follows: the initial porosity was decreased by compaction and cementation and then increased by leaching of the metastable grains and dissolution of cement. Good quality reservoir rocks were deposited in fluvial environment and hence quality of reservoir rocks is also environment selective. Porosity and permeability data exhibit good inverse correlation with cement. However, some data points indicate multiple controls on permeability. Reservoir quality is thus controlled by pore occluding cement, textural parameters (grain size, pore size and sorting) and depositional environment. The reservoir finally resumed partly its pre-cementation quality after development of secondary porosity.

Triassic arc-derived detritus in the Triassic Karakaya accretionary complex was not derived from either the S Eurasian margin (Istanbul terrane) or the N Gondwana margin (Taurides)

NASA Astrophysics Data System (ADS)

Ustaömer, Timur; Ayda Ustaömer, Petek; Robertson, Alastair H. F.; Gerdes, Axel; Zulauf, Gernold

2014-05-01

We present new U-Pb zircon source age data for Upper Triassic sandstones of the Istanbul Terrane (S Eurasian margin) and also for Triassic sandstones of the Taurides (N Gondwana margin). The main aim is to detect and quantify the contribution of Triassic magmatism as detritus to either of these crustal blocks. This follows the recent discovery of a Triassic magmatic arc source for the Triassic sandstones of the Palaeotethyan Karakaya subduction-accretion complex (Ustaömer et al. 2013; this meeting). Carboniferous (Variscan) zircon grains also form a significant detrital population, plus several more minor populations. Six sandstone samples were studied, two from the İstanbul Terrane (Bakırlıkıran Formation of the Kocaeli Triassic Basin) and four from the Tauride Autochthon (latest Triassic Üzümdere Formation and Mid-Triassic Kasımlar Formations; Beyşehir region). Detrital zircon grains were dated by the laser ablation-inductively coupled plasma-mass spectrometer (LA-ICP-MS) U-Pb method at Goethe University, Frankfurt. Our results do not reveal Triassic detritus in the Üzümdere Formation. The U-Pb age of the analysed zircon grains ranges from 267 Ma to 3.2 Ga. A small fraction of Palaeozoic zircons are Permian (267 to 296 Ma), whereas the remainder are Early Palaeozoic. Ordovician grains (4%) form two age clusters, one at ca. 450 Ma and the other at ca. 474 Ma. Cambrian-aged grains dominate the zircon population, while the second largest population is Ediacaran (576 to 642 Ma). Smaller populations occur at 909-997 Ma, 827-839 Ma, 1.8-2.0 Ga and 2.4-2.6 Ga. The sandstones of the Kasımlar Formation have similar zircon age cluster to those of the somewhat younger Üzümdere Formation, ranging from 239 Ma to 2.9 Ga. A few grains gave Anisian ages. Cambrian zircon grains are less pronounced than in the Kasımlar Formation compared to the Üzümdere Formation. The detrital zircon record of Tauride sandstones, therefore, not indicates significant contribution of Triassic or Carboniferous (Variscan) arc sources, in marked contrast to those of the Triassic Karakaya subduction complex. In comparison, the ages of the analysed zircons in the Upper Triassic sandstones of the Istanbul Terrane range from 294 Ma to 3.1 Ga. Triassic zircons are again absent, while Variscan-aged zircons (294 to 339 Ma) dominate the zircon population. Additional zircon populations are dated at 554 to 655 Ma, 0.9 to 1.2 Ga, 1.5 Ga, 1.65 Ga, 2.0 to 2.15 and 2.5 to 2.8 Ga. The Precambrian zircon age spectra are compatible with derivation from an Avalonian/Amazonian/Baltic crustal provenance. In summary, there is no evidence in either the Triassic sandstones of the İstanbul Terrane or of the Taurides of the Triassic magmatic arc source that dominates the Triassic Karakaya subduction-accretion complex. Where then was the source of the Karakaya arc detritus? A likely option is that the Karakaya subduction-accretion complex is an exotic terrane that was detached from a source magmatic arc and displaced to its present location, probably prior the initial deposition of the Early Jurassic cover sediments. This study was supported by TUBITAK, Project No: 111R015

Resonant Ultrasound Spectroscopy studies of Berea sandstone at high temperature

DOE PAGES

Davis, Eric S.; Sturtevant, Blake T.; Sinha, Dipen N.; ...

2016-09-04

Resonant Ultrasound Spectroscopy was used in this paper to determine the elastic moduli of Berea sandstone from room temperature to 478 K. Sandstone is a common component of oil reservoirs, and the temperature range was chosen to be representative of typical downhole conditions, down to about 8 km. In agreement with previous works, Berea sandstone was found to be relatively soft with a bulk modulus of approximately 6 GPa as compared to 37.5 GPa for α-quartz at room temperature and pressure. Finally, it was found that Berea sandstone undergoes a ~17% softening in bulk modulus between room temperature and 385more » K, followed by an abnormal behavior of similar stiffening between 385 K and 478 K.« less

Resonant Ultrasound Spectroscopy studies of Berea sandstone at high temperature

DOE Office of Scientific and Technical Information (OSTI.GOV)

Davis, Eric S.; Sturtevant, Blake T.; Sinha, Dipen N.

Resonant Ultrasound Spectroscopy was used in this paper to determine the elastic moduli of Berea sandstone from room temperature to 478 K. Sandstone is a common component of oil reservoirs, and the temperature range was chosen to be representative of typical downhole conditions, down to about 8 km. In agreement with previous works, Berea sandstone was found to be relatively soft with a bulk modulus of approximately 6 GPa as compared to 37.5 GPa for α-quartz at room temperature and pressure. Finally, it was found that Berea sandstone undergoes a ~17% softening in bulk modulus between room temperature and 385more » K, followed by an abnormal behavior of similar stiffening between 385 K and 478 K.« less

Geologic map of the Rifle Falls quadrangle, Garfield County, Colorado

USGS Publications Warehouse

Scott, Robert B.; Shroba, Ralph R.; Egger, Anne

2001-01-01

New 1:24,000-scale geologic map of the Rifle Falls 7.5' quadrangle, in support of the USGS Western Colorado I-70 Corridor Cooperative Geologic Mapping Project, provides new interpretations of the stratigraphy, structure, and geologic hazards in the area of the southwest flank of the White River uplift. Bedrock strata include the Upper Cretaceous Iles Formation through Ordovician and Cambrian units. The Iles Formation includes the Cozzette Sandstone and Corcoran Sandstone Members, which are undivided. The Mancos Shale is divided into three members, an upper member, the Niobrara Member, and a lower member. The Lower Cretaceous Dakota Sandstone, the Upper Jurassic Morrison Formation, and the Entrada Sandstone are present. Below the Upper Jurassic Entrada Sandstone, the easternmost limit of the Lower Jurassic and Upper Triassic Glen Canyon Sandstone is recognized. Both the Upper Triassic Chinle Formation and the Lower Triassic(?) and Permian State Bridge Formation are present. The Pennsylvanian and Permian Maroon Formation is divided into two members, the Schoolhouse Member and a lower member. All the exposures of the Middle Pennsylvanian Eagle Evaporite intruded into the Middle Pennsylvanian Eagle Valley Formation, which includes locally mappable limestone beds. The Middle and Lower Pennsylvanian Belden Formation and the Lower Mississippian Leadville Limestone are present. The Upper Devonian Chaffee Group is divided into the Dyer Dolomite, which is broken into the Coffee Pot Member and the Broken Rib Member, and the Parting Formation. Ordovician through Cambrian units are undivided. The southwest flank of the White River uplift is a late Laramide structure that is represented by the steeply southwest-dipping Grand Hogback, which is only present in the southwestern corner of the map area, and less steeply southwest-dipping older strata that flatten to nearly horizontal attitudes in the northern part of the map area. Between these two is a large-offset, mid-Tertiary(?) Rifle Falls normal fault, that dips southward placing Leadville Limestone adjacent to Eagle Valley and Maroon Formations. Diapiric Eagle Valley Evaporite intruded close to the fault on the down-thrown side and presumably was injected into older strata on the upthrown block creating a blister-like, steeply north-dipping sequence of Mississippian and older strata. Also, removal of evaporite by either flow or dissolution from under younger parts of the strata create structural benches, folds, and sink holes on either side of the normal fault. A prominent dipslope of the Morrison-Dakota-Mancos part of the section forms large slide blocks that form distinctly different styles of compressive deformation called the Elk Park fold and fault complex at different parts of the toe of the slide. The major geologic hazard in the area consist of large landslides both associated with dip-slope slide blocks and the steep slopes of the Eagle Valley Formation and Belden Formation in the northern part of the map. Significant uranium and vanadium deposits were mined prior to 1980.

Influence of Capillary Force and Buoyancy on CO2 Migration During CO2 Injection in a Sandstone Reservoir

NASA Astrophysics Data System (ADS)

Wu, H.; Pollyea, R.

2017-12-01

Carbon capture and sequestration (CCS) is one component of a broad carbon management portfolio designed to mitigate adverse effects of anthropogenic CO2 emissions. During CCS, capillary trapping is an important mechanism for CO2 isolation in the disposal reservoir, and, as a result, the distribution of capillary force is an important factor affecting CO2 migration. Moreover, the movement of CO2 being injected to the reservoir is also affected by buoyancy, which results from the density difference between CO2 and brine. In order to understand interactions between capillary force and buoyancy, we implement a parametric modeling experiment of CO2 injections in a sandstone reservoir for combinations of the van Genuchten capillary pressure model that bound the range of capillary pressure-saturation curves measured in laboratory experiments. We simulate ten years supercritical CO2 (scCO2) injections within a 2-D radially symmetric sandstone reservoir for five combinations of the van Genuchten model parameters λ and entry pressure (P0). Results are analyzed on the basis of a modified dimensionless ratio, ω, which is similar to the Bond number and defines the relationship between buoyancy pressure and capillary pressure. We show how parametric variability affects the relationship between buoyancy and capillary force, and thus controls CO2 plume geometry. These results indicate that when ω >1, then buoyancy governs the system and CO2 plume geometry is governed by upward flow. In contrast, when ω <1, then buoyancy is smaller than capillary force and lateral flow governs CO2 plume geometry. As a result, we show that the ω ratio is an easily implemented screening tool for qualitative assessment of reservoir performance.

Potential seal bypass and caprock storage produced by deformation-band-to-opening-mode-fracture transition at the reservoir/caprock interface

DOE PAGES

Raduha, S.; Butler, D.; Mozley, P. S.; ...

2016-06-18

Here, we examined the potential impact on CO 2 transport of zones of deformation bands in reservoir rock that transition to opening-mode fractures within overlying caprock. Sedimentological and petrophysical measurements were collected along an approximately 5 m × 5 m outcrop of the Slick Rock and Earthy Members of the Entrada Sandstone on the eastern flank of the San Rafael Swell, Utah, USA. Measured deformation band permeability (2 mD) within the reservoir facies is about three orders of magnitude lower than the host sandstone. Average permeability of the caprock facies (0.0005 mD) is about seven orders of magnitude lower thanmore » the host sandstone. Aperture-based permeability estimates of the opening-mode caprock fractures are high (3.3 × 10 7 mD). High-resolution CO 2–H 2O transport models incorporate these permeability data at the millimeter scale. We then varied fault properties at the reservoir/caprock interface between open fractures and deformation bands as part of a sensitivity study. Numerical modeling results suggest that zones of deformation bands within the reservoir strongly compartmentalize reservoir pressures largely blocking lateral, cross-fault flow of supercritical CO 2. Significant vertical CO 2 transport into the caprock occurred in some scenarios along opening-mode fractures. The magnitude of this vertical CO 2 transport depends on the small-scale geometry of the contact between the opening-mode fracture and the zone of deformation bands, as well as the degree to which fractures penetrate caprock. Finally, the presence of relatively permeable units within the caprock allows storage of significant volumes of CO 2, particularly when the fracture network does not extend all the way through the caprock.« less

Rock specific hydraulic fracturing and matrix acidizing to enhance a geothermal system — Concepts and field results

NASA Astrophysics Data System (ADS)

Zimmermann, Günter; Blöcher, Guido; Reinicke, Andreas; Brandt, Wulf

2011-04-01

Enhanced geothermal systems (EGS) are engineered reservoirs developed to extract economic amounts of heat from low permeability and/or porosity geothermal resources. To enhance the productivity of reservoirs, a site specific concept is necessary to actively make reservoir conditions profitable using specially adjusted stimulation treatments, such as multi fracture concepts and site specific well path design. The results of previously performed stimulation treatments in the geothermal research well GtGrSk4/05 at Groß Schönebeck, Germany are presented. The reservoir is located at a 4100-4300 m depth within the Lower Permian of the NE German Basin with a bottom-hole temperature of 150 °C. The reservoir rock is classified by two lithological units from bottom to top: volcanic rocks (andesitic rocks) and siliciclastics ranging from conglomerates to fine-grained sandstones (fluvial sediments). The stimulation treatments included multiple hydraulic stimulations and an acid treatment. In order to initiate a cross-flow from the sandstone layer, the hydraulic stimulations were performed in different depth sections (two in the sandstone section and one in the underlying volcanic section). In low permeability volcanic rocks, a cyclic hydraulic fracturing treatment was performed over 6 days in conjunction with adding quartz in low concentrations to maintain a sustainable fracture performance. Flow rates of up to 150 l/s were realized, and a total of 13,170 m 3 of water was injected. A hydraulic connection to the sandstone layer was successfully achieved in this way. However, monitoring of the water level in the offsetting well EGrSk3/90, which is 475 m apart at the final depth, showed a very rapid water level increase due to the stimulation treatment. This can be explained by a connected fault zone within the volcanic rocks. Two gel-proppant treatments were performed in the slightly higher permeability sandstones to obtain long-term access to the reservoir rocks. During each treatment, a total of 100 ton of high strength proppants was injected with 500 m 3 of cross-linked gel. The subsequent production test in conjunction with flowmeter logging showed an improvement of productivity by a factor of more than 4. Due to assumed residual drilling mud (constituents: calcite, dolomite, and aragonite) in the near-wellbore vicinity, an acid matrix stimulation was performed thereafter using a coil tubing unit. The following nitrogen lift test demonstrated another increase of productivity by 30-50% to an overall increase by a factor of 5.5-6.2.

Adverse effects of mineral-alkali reactions in alkaline flooding: Final report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Thornton, S.D.

1988-01-01

Two slim-tube experiments and supporting bottle tests were performed for a study of sandstone-alkali reactions. The two samples of reservoir sandstone used are from oilfields in the People's Republic of China. The first sandstone contains 16 percent clay and is from the Gu-Dao oilfield. The second sandstone contains 12 percent clay and is from the Liao-He oilfield. These two sandstones were allowed to react with alkaline solutions in 6-month bottle tests. Each sandstone consumed the most alkali from 0.5 N NaOH solution, an intermediate amount of alkali from 0.5 N Na/sub 2/SiO/sub 3/ solution, and the least amount of alkalimore » from 0.5 N Na/sub 2/CO/sub 3/ solution. 59 refs., 14 figs., 20 tabs.« less

Seismic spectral decomposition and analysis based on Wigner-Ville distribution for sandstone reservoir characterization in West Sichuan depression

NASA Astrophysics Data System (ADS)

Wu, Xiaoyang; Liu, Tianyou

2010-06-01

Reflections from a hydrocarbon-saturated zone are generally expected to have a tendency to be low frequency. Previous work has shown the application of seismic spectral decomposition for low-frequency shadow detection. In this paper, we further analyse the characteristics of spectral amplitude in fractured sandstone reservoirs with different fluid saturations using the Wigner-Ville distribution (WVD)-based method. We give a description of the geometric structure of cross-terms due to the bilinear nature of WVD and eliminate cross-terms using smoothed pseudo-WVD (SPWVD) with time- and frequency-independent Gaussian kernels as smoothing windows. SPWVD is finally applied to seismic data from West Sichuan depression. We focus our study on the comparison of SPWVD spectral amplitudes resulting from different fluid contents. It shows that prolific gas reservoirs feature higher peak spectral amplitude at higher peak frequency, which attenuate faster than low-quality gas reservoirs and dry or wet reservoirs. This can be regarded as a spectral attenuation signature for future exploration in the study area.

The low salinity effect at high temperatures

DOE PAGES

Xie, Quan; Brady, Patrick V.; Pooryousefy, Ehsan; ...

2017-04-05

The mechanism(s) of low salinity water flooding (LSWF) must be better understood at high temperatures and pressures if the method is to be applied in high T/P kaolinite-bearing sandstone reservoirs. We measured contact angles between a sandstone and an oil (acid number, AN = 3.98 mg KOH/g, base number, BN = 1.3 mg KOH/g) from a reservoir in the Tarim Field in western China in the presence of various water chemistries. We examined the effect of aqueous ionic solutions (formation brine, 100X diluted formation brine, and softened water), temperature (60, 100 and 140 °C) and pressure (20, 30, 40, andmore » 50 MPa) on the contact angle. We also measured the zeta potential of the oil/water and water/rock interfaces to calculate oil/brine/rock disjoining pressures. A surface complexation model was developed to interpret contact angle measurements and compared with DLVO theory predictions. Contact angles were greatest in formation water, followed by the softened water, and low salinity water at the same pressure and temperature. Contact angles increased slightly with temperature, whereas pressure had little effect. DLVO and surface complexation modelling predicted similar wettability trends and allow reasonably accurate interpretation of core-flood results. Water chemistry has a much larger impact on LSWF than reservoir temperature and pressure. As a result, low salinity water flooding should work in high temperature and high pressure kaolinite-bearing sandstone reservoirs.« less

The low salinity effect at high temperatures

DOE Office of Scientific and Technical Information (OSTI.GOV)

Xie, Quan; Brady, Patrick V.; Pooryousefy, Ehsan

The mechanism(s) of low salinity water flooding (LSWF) must be better understood at high temperatures and pressures if the method is to be applied in high T/P kaolinite-bearing sandstone reservoirs. We measured contact angles between a sandstone and an oil (acid number, AN = 3.98 mg KOH/g, base number, BN = 1.3 mg KOH/g) from a reservoir in the Tarim Field in western China in the presence of various water chemistries. We examined the effect of aqueous ionic solutions (formation brine, 100X diluted formation brine, and softened water), temperature (60, 100 and 140 °C) and pressure (20, 30, 40, andmore » 50 MPa) on the contact angle. We also measured the zeta potential of the oil/water and water/rock interfaces to calculate oil/brine/rock disjoining pressures. A surface complexation model was developed to interpret contact angle measurements and compared with DLVO theory predictions. Contact angles were greatest in formation water, followed by the softened water, and low salinity water at the same pressure and temperature. Contact angles increased slightly with temperature, whereas pressure had little effect. DLVO and surface complexation modelling predicted similar wettability trends and allow reasonably accurate interpretation of core-flood results. Water chemistry has a much larger impact on LSWF than reservoir temperature and pressure. As a result, low salinity water flooding should work in high temperature and high pressure kaolinite-bearing sandstone reservoirs.« less

The role of mineral heterogeneity on the hydrogeochemical response of two fractured reservoir rocks in contact with dissolved CO2

NASA Astrophysics Data System (ADS)

Garcia Rios, Maria; Luquot, Linda; Soler, Josep M.; Cama, Jordi

2017-04-01

In this study we compare the hydrogeochemical response of two fractured reservoir rocks (limestone composed of 100 wt.% calcite and sandstone composed of 66 wt.% calcite, 28 wt.% quartz and 6 wt.% microcline) in contact with CO2-rich sulfate solutions. Flow-through percolation experiments were performed using artificially fractured limestone and sandstone cores and injecting a CO2-rich sulfate solution under a constant volumetric flow rate (from 0.2 to 60 mL/h) at P = 150 bar and T = 60 °C. Measurements of the pressure difference between the inlet and the outlet of the samples and of the aqueous chemistry enabled the determination of fracture permeability changes and net reaction rates. Additionally, X-ray computed microtomography (XCMT) was used to characterize and localized changes in fracture volume induced by dissolution and precipitation reactions. In all reacted cores an increase in fracture permeability and in fracture volume was always produced even when gypsum precipitation happened. The presence of inert silicate grains in sandstone samples favored the occurrence of largely distributed dissolution structures in contrast to localized dissolution in limestone samples. This phenomenon promoted greater dissolution and smaller precipitation in sandstone than in limestone experiments. As a result, in sandstone reservoirs, the larger increase in fracture volume as well as the more extended distribution of the created volume would favor the CO2 storage capacity. The different distribution of created volume between limestone and sandstone experiments led to a different variation in fracture permeability. The progressive stepped permeability increase for sandstone would be preferred to the sharp permeability increase for limestone to minimize risks related to CO2 injection, favor capillary trapping and reduce energetic storage costs. 2D reactive transport simulations that reproduce the variation in aqueous chemistry and the fracture geometry (dissolution pattern) were performed using CrunchFlow. The calcite reactive surface area had to be diminished with respect to the geometric surface area in order to account for the transport control of the calcite dissolution reaction at pH < 5. The fitted reactive surface area was higher under faster flow conditions, reflecting a decrease in transport control and a more distributed reaction in sandstone compared to limestone.

GEOCHEMICAL INVESTIGATIONS OF CO₂-BRINE-ROCK INTERACTIONS OF THE KNOX GROUP IN THE ILLINOIS BASIN

DOE Office of Scientific and Technical Information (OSTI.GOV)

Yoksoulian, Lois; Berger, Peter; Freiburg, Jared

Increased output of greenhouse gases, particularly carbon dioxide (CO₂), into the atmosphere from anthropogenic sources is of great concern. A potential technology to reduce CO₂ emissions is geologic carbon sequestration. This technology is currently being evaluated in the United States and throughout the world. The geology of the Illinois Basin exhibits outstanding potential as a carbon sequestration target, as demonstrated by the ongoing Illinois Basin – Decatur Project that is using the Mt. Simon Sandstone reservoir and Eau Claire Shale seal system to store and contain 1 million tonnes of CO₂. The Knox Group-Maquoketa Shale reservoir and seal system, locatedmore » stratigraphically above the Mt. Simon Sandstone-Eau Claire Shale reservoir and seal system, has little economic value as a resource for fossil fuels or as a potable water source, making it ideal as a potential carbon sequestration target. In order for a reservoir-seal system to be effective, it must be able to contain the injected CO₂ without the potential for the release of harmful contaminants liberated by the reaction between CO₂-formation fluids and reservoir and seal rocks. This study examines portions of the Knox Group (Potosi Dolomite, Gunter Sandstone, New Richmond Sandstone) and St. Peter Sandstone, and Maquoketa Shale from various locations around the Illinois Basin. A total of 14 rock and fluid samples were exposed to simulated sequestration conditions (9101–9860 kPa [1320–1430 psi] and 32°–42°C [90°– 108°F]) for varying amounts of time (6 hours to 4 months). Knox Group reservoir rocks exhibited dissolution of dolomite in the presence of CO₂ as indicated by petrographic examination, X-ray diffraction analysis, and fluid chemistry analysis. These reactions equilibrated rapidly, and geochemical modeling confirmed that these reactions reached equilibrium within the time frames of the experiments. Pre-reaction sample mineralogy and postreaction fluid geochemistry from this study suggests only limited potential for the release of United States Environmental Protection Agency regulated inorganic contaminants into potable water sources. Short-term core flood experiments further verify that the carbonate reactions occurring in Knox Group reservoir samples reach equilibrium rapidly. The core flood experiments also lend insight to pressure changes that may occur during CO₂ injection. The Maquoketa Shale experiments reveal that this rock is initially chemically reactive when in contact with CO₂ and brine. However, due to the conservative nature of silicate and clay reaction kinetics and the rapid equilibration of carbonate reactions that occur in the shale, these reactions would not present a significant risk to the competency of the shale as an effective seal rock.« less

Novel Geothermal Development of Deep Sedimentary Systems in the United States

DOE Office of Scientific and Technical Information (OSTI.GOV)

Moore, Joseph; Allis, Rick

Economic and reservoir engineering models show that stratigraphic reservoirs have the potential to contribute significant geothermal power in the U.S. If the reservoir temperature exceeds about 150 – 200 °C at 2 – 4 km depth, respectively, and there is good permeability, then these resources can generate power with a levelized cost of electricity (LCOE) of close to 10 ¢/kWh (without subsidies) on a 100 MW power plant scale. There is considerable evidence from both groundwater geology and petroleum reservoir geology that relatively clean carbonates and sandstones have, and can sustain, the required high permeability to depths of at leastmore » 5 km. This paper identifies four attractive stratigraphic reservoir prospects which are all located in the eastern Great Basin, and have temperatures of 160 – 230 °C at 3 – 3.5 km depth. They are the Elko basins (Nevada), North Steptoe Valley (Nevada), Pavant Butte (Utah), and the Idaho Thrust Belt. The reservoir lithologies are Paleozoic carbonates in the first three, and Jurassic sandstone and carbonate in the Idaho Thrust Belt. All reservoir lithologies are known to have high permeability characteristics. At North Steptoe Valley and Pavant Butte, nearby transmission line options allow interconnection to the California power market. Modern techniques for drilling and developing tight oil and gas reservoirs are expected to have application to geothermal development of these reservoirs.« less

Sequence Stratigraphy of the Dakota Sandstone, Eastern San Juan Basin, New Mexico, and its Relationship to Reservoir Compartmentalization

DOE Office of Scientific and Technical Information (OSTI.GOV)

Varney, Peter J.

2002-04-23

This research established the Dakota-outcrop sequence stratigraphy in part of the eastern San Juan Basin, New Mexico, and relates reservoir quality lithologies in depositional sequences to structure and reservoir compartmentalization in the South Lindrith Field area. The result was a predictive tool that will help guide further exploration and development.

Basin Analysis and Petroleum System Characterization and Modeling, Interior Salt Basins, Central and Eastern Gulf of Mexico

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ernest A. Mancini; Paul Aharon; Donald A. Goddard

2006-05-26

The principal research effort for Phase 1 (Concept Development) of the project has been data compilation; determination of the tectonic, depositional, burial, and thermal maturation histories of the North Louisiana Salt Basin; basin modeling (geohistory, thermal maturation, hydrocarbon expulsion); petroleum system identification; comparative basin evaluation; and resource assessment. Existing information on the North Louisiana Salt Basin has been evaluated, an electronic database has been developed, and regional cross sections have been prepared. Structure, isopach and formation lithology maps have been constructed, and burial history, thermal maturation history, and hydrocarbon expulsion profiles have been prepared. Seismic data, cross sections, subsurface mapsmore » and burial history, thermal maturation history, and hydrocarbon expulsion profiles have been used in evaluating the tectonic, depositional, burial and thermal maturation histories of the basin. Oil and gas reservoirs have been found to be associated with salt-supported anticlinal and domal features (salt pillows, turtle structures and piercement domes); with normal faulting associated with the northern basin margin and listric down-to-the-basin faults (state-line fault complex) and faulted salt features; and with combination structural and stratigraphic features (Sabine and Monroe Uplifts) and monoclinal features with lithologic variations. Petroleum reservoirs include Upper Jurassic and Cretaceous fluvial-deltaic sandstone facies; shoreline, marine bar and shallow shelf sandstone facies; and carbonate shoal, shelf and reef facies. Cretaceous unconformities significantly contribute to the hydrocarbon trapping mechanism capacity in the North Louisiana Salt Basin. The chief petroleum source rock in this basin is Upper Jurassic Smackover lime mudstone beds. The generation of hydrocarbons from Smackover lime mudstone was initiated during the Early Cretaceous and continued into the Tertiary. Hydrocarbon expulsion commenced during the Early Cretaceous and continued into the Tertiary with peak expulsion occurring during the Early to Late Cretaceous. The geohistory of the North Louisiana Salt Basin is comparable to the Mississippi Interior Salt Basin with the major difference being the elevated heat flow the strata in the North Louisiana Salt Basin experienced in the Cretaceous due primarily to reactivation of upward movement, igneous activity, and erosion associated with the Monroe and Sabine Uplifts. Potential undiscovered reservoirs in the North Louisiana Salt Basin are Triassic Eagle Mills sandstone and deeply buried Upper Jurassic sandstone and limestone. Potential underdeveloped reservoirs include Lower Cretaceous sandstone and limestone and Upper Cretaceous sandstone.« less

Geoscience technology application to optimize field development, Seligi Field, Malay Basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ahmed, M.S.; Wiggins, B.D.

1994-07-01

Integration of well log, core, 3-D seismic, and engineering data within a sequence stratigraphic framework, has enabled prediction of reservoir distribution and optimum development of Seligi field. Seligi is the largest field in the Malay Basin, with half of the reserves within lower Miocene Group J reservoirs. These reservoirs consist of shallow marine sandstones and estuarine sandstones predominantly within an incised valley. Variation in reservoir quality has been a major challenge in developing Seligi. Recognizing and mapping four sequences within the Group J incised valley fill has resulted in a geologic model for predicting the distribution of good quality estuarinemore » reservoir units and intercalated low-permeability sand/shale units deposited during marine transgressions. These low-permeability units segregate the reservoir fluids, causing differential contact movement in response to production thus impacting completion strategy and well placement. Seismic calibration shows that a large impedance contrast exists between the low-permeability rock and adjacent good quality oil sand. Application of sequence stratigraphic/facies analysis coupled with the ability to identify the low-permeability units seismically is enabling optimum development of each of the four sequences at Seligi.« less

Sulfur and Carbon Isotope Systematics in Middle-Upper Cambrian Port au Port Group From Western Newfoundland, Canada: Implications for Seawater Sulfate Concentrations

NASA Astrophysics Data System (ADS)

Hurtgen, M. T.; Pruss, S.; Knoll, A. H.

2006-12-01

The biogeochemical cycles of carbon and sulfur are intimately linked through a variety of feedbacks that operate on timescales of days to millions of years. For example, under anaerobic conditions, some bacteria respire organic matter by sulfate reduction, reducing sulfate to sulfide, which then reacts with iron to form iron sulfide (preserved as pyrite). On much longer timescales, increases in the fraction of total carbon buried as organic carbon can drive increases in atmospheric oxygen concentrations which then facilitate an increase in the extent to which sulfides on land are oxidatively weathered and ultimately delivered to the oceans as sulfate via rivers. Interestingly, these two processes impose very different isotope relationships between the C isotope composition of marine dissolved inorganic carbon (DIC) and the S isotope composition of seawater sulfate. The former leads to a positive correlation between δ13Ccarbonate and δ34Ssulfate whereas the latter prescribes a long-term negative correlation. Of course, the recognition of either a positive or negative correlation between δ13Ccarbonate and δ34Ssulfate depends strongly on the relative sizes of the DIC and seawater sulfate reservoirs-- neither of which is well constrained for the Cambrian Period. Here, we present a high-resolution δ34S (sulfate and pyrite) and δ13Ccarbonate record from the mixed carbonate-siliciclastic Middle-Upper Cambrian Port au Port Group in western Newfoundland, Canada. The δ34Ssulfate profile displays systematic shifts of >15‰ over relatively short stratigraphic distances (10 m, likely to represent < 1 Myr). C isotope values shift sympathetically throughout much of the composite section; however, important deviations from this relationship exist. First, in the Middle Cambrian March Point Formation, a 15‰- δ34Ssulfate decrease precedes a 3‰-δ13Ccarbonate fall suggesting that the sulfur cycle recorded the perturbation to the system before the carbon cycle did. Secondly, further up in the section, the Upper Cambrian Man O' War Member exhibits a ~6‰ positive C isotope excursion (SPICE Event) with almost no change in S isotope values. In combination, these data suggest that seawater sulfate concentrations were much lower than modern values, at least in this basin, resulting in a sulfate reservoir that was more susceptible to isotopic variation. Moreover, differences in the relationship between C and S isotopes indicate that the relative sizes of the marine DIC and sulfate reservoir changed through this interval and/or that the various perturbations recorded in the lower and upper parts of this succession affected the carbon and sulfur cycles in different ways.

Reservoir characterization and preliminary modeling of deltaic facies, lower Wilcox, Concordia Parish, Louisiana

DOE Office of Scientific and Technical Information (OSTI.GOV)

Schenewerk, P.; Goddard, D.; Echols, J.

The decline in production in several fields in Concordia Parish, Louisiana, has created interest in the economic feasibility of producing the remaining bypassed oil in the lower Wilcox Group. One of these fields, Bee Brake, has been one of the more prolific oil-producing fields in east-central Louisiana. The producing interval, the Minter sandstones, at a depth of about 6,775 ft typically consists of an upper Bee Brake sandstone and a lower Angelina sandstone. A detailed study of a conventional core in the center of the field reveals a 15-ft-thick Minter interval bounded above and below by sealing shales and lignitesmore » of lower delta plain marsh facies. The upper 4-ft-thick Bee Brake is a very fine silty sandstone with characteristics of a small overbank or crevasse splay deposit. The lower 3-ft-thick oil-producing Angelina sandstone consists of very fine and fine sandstone of probable overbank or crevasse facies. Cumulative production from the Angelina is about 1.8 million stock-tank barrels of oil. Special core analysis data (capillary pressure, relative permeability, and waterflood recovery) have been used to develop a simulation model of the two reservoirs in the Minter. This model incorporates the geologic and engineering complexities noted during evaluation of the field area. Operators can use the model results in this field to design an optimal development plan for enhanced recovery.« less

Discriminant function analysis as tool for subsurface geologist

DOE Office of Scientific and Technical Information (OSTI.GOV)

Chesser, K.

1987-05-01

Sedimentary structures such as cross-bedding control porosity, permeability, and other petrophysical properties in sandstone reservoirs. Understanding the distribution of such structures in the subsurface not only aids in the prediction of reservoir properties but also provides information about depositional environments. Discriminant function analysis (DFA) is a simple yet powerful method incorporating petrophysical data from wireline logs, core analyses, or other sources into groups that have been previously defined through direct observation of sedimentary structures in cores. Once data have been classified into meaningful groups, the geologist can predict the distribution of specific sedimentary structures or important reservoir properties in areasmore » where cores are unavailable. DFA is efficient. Given several variables, DFA will choose the best combination to discriminate among groups. The initial classification function can be computed from relatively few observations, and additional data may be included as necessary. Furthermore, DFA provides quantitative goodness-of-fit estimates for each observation. Such estimates can be used as mapping parameters or to assess risk in petroleum ventures. Petrophysical data from the Skinner sandstone of Strauss field in southeastern Kansas tested the ability of DFA to discriminate between cross-bedded and ripple-bedded sandstones. Petroleum production in Strauss field is largely restricted to the more permeable cross-bedded sandstones. DFA based on permeability correctly placed 80% of samples into cross-bedded or ripple-bedded groups. Addition of formation factor to the discriminant function increased correct classifications to 83% - a small but statistically significant gain.« less

Geologic framework for the assessment of undiscovered oil and gas resources in sandstone reservoirs of the Upper Jurassic-Lower Cretaceous Cotton Valley Group, U.S. Gulf of Mexico region

USGS Publications Warehouse

Eoff, Jennifer D.; Dubiel, Russell F.; Pearson, Ofori N.; Whidden, Katherine J.

2015-01-01

The Cotton Valley Group extends in the subsurface from southern Texas to the Florida Panhandle in an arcuate belt that crosses northern Louisiana, the southern part of Arkansas, and southern Mississippi and Alabama. Three of the AUs are quantitatively assessed for undiscovered volumes of hydrocarbons in conventional accumulations. The Cotton Valley Updip Oil AU includes areas between the maximum updip limit of the Cotton Valley Group and a curved belt of regional faults (included in the Peripheral Fault System AU). Hydrocarbon charge to this AU remains uncertain. The Peripheral Fault System Oil and Gas AU includes the Mexia, Talco, State Line, South Arkansas, Pickens, Gilbertown, and other fault segments, which trapped early oil that migrated from source rocks within the Smackover Formation. Hydrocarbons in the Downdip Oil and Gas AU are primarily associated with low-amplitude salt-related features in the East Texas, North Louisiana, and Mississippi salt basins. The Tight Sandstone Gas AU contains gas-charged sandstones previously referred to collectively as “massive.” Their reservoir properties are consistent with the USGS’s definition of continuous reservoirs, and their resources, therefore, are assessed using a separate methodology. Optimal coincidence of low-permeability sandstone, gas-mature source rocks, and complex structures of the regional Sabine feature encouraged development of a general “sweet spot” area in eastern Texas.

Anomalies of natural gas compositions and carbon isotope ratios caused by gas diffusion - A case from the Donghe Sandstone reservoir in the Hadexun Oilfield, Tarim Basin, northwest China

NASA Astrophysics Data System (ADS)

Wang, Yangyang; Chen, Jianfa; Pang, Xiongqi; Zhang, Baoshou; Wang, Yifan; He, Liwen; Chen, Zeya; Zhang, Guoqiang

2018-05-01

Natural gases in the Carboniferous Donghe Sandstone reservoir within the Block HD4 of the Hadexun Oilfield, Tarim Basin are characterized by abnormally low total hydrocarbon gas contents (<65%), low methane contents (<10%) and low dryness coefficients (<0.5), and a reversal of the normal trend of carbon isotope ratios, showing δ13C methane (C1) > δ13C ethane (C2) < δ13C propane (C3) < δ13C butane (C4). Specifically, methane is enriched in 13C with the variations in δ13C1 values between gases from Block HD4 and gases from its neighboring blocks reaching 10‰. This type of abnormal gas has never been reported previously in the Tarim Basin and such large variations in δ13C have rarely been observed in other basins globally. Based on a comprehensive analysis of gas geochemical data and the geological setting of the Carboniferous reservoirs in the Hadexun Oilfield, we reveal that the anomalies of the gas compositions and carbon isotope ratios in the Donghe Sandstone reservoir are caused by gas diffusion through the poorly-sealed caprock rather than by pathways such as gas mixing, microorganism degradation, different kerogen types or thermal maturity degrees of source rocks. The documentation of an in-reservoir gas diffusion during the post entrapment process as a major cause for gas geochemical anomalies may offer important insight into exploring natural gas resources in deeply buried sedimentary basins.

Petroleum geology of the Cusiana Field, Llanos Basin Foothills, Colombia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cazier, E.C.; Hayward, A.B.; Espinosa, G.

1995-10-01

Cusiana field is located in the Llanos Foothills, 150 mi (240km) northeast of Bogota, Colombia. Light oil, gas, and condensate in Cusiana occur at drilling depths that average 15,000 ft (4575 m) in an asymmetric, hanging-wall anticlinal trap 15 mi (25 km) long and 3-4 mi (5-6 km) across, formed during the Miocene-Holocene deformation of the Eastern Cordillera. Top and lateral seals are provided by marine mudstones of the Oligocene Carbonera Group, and support a hydrocarbon column of over 1500 ft (460 m). Biomarker data from the hydrocarbons indicate a marine mudstone source interpreted to be the Turonian-Coniacian Gacheta Formation.more » Over 50% of the reserves occur in upper Eocene Mirador Formation sandstones, which were deposited predominantly in estuarine environments. Additional, deeper reservoirs include estuarine sandstones of the Paleocene Barco Formation and the shallow-marine Santonian-Campanian Upper Guadalupe Sandstone. Porosity in Cusiana is relatively low. Good permeability is retained, however, because the reservoirs are pure quartz-cemented quartzarenites that lack permeability-reducing authigenic clays and carbonate cements. Core and well test analyses indicate matrix permeability, not fracture permeability, provides the high deliverability of Cusiana wells. Cusiana hydrocarbon phases exist in a near-miscible, critical-point state. Reservoir simulation indicates very high liquid hydrocarbon recoveries should be possible from all reservoirs by using the reinjection of produced gas to maintain reservoir pressure and to vaporize residual liquids. The field contains up to 1.5 MSTB of hydrocarbon liquid reserves and 3.4 Tcf of gas.« less

Reservoir performance of Late Eocene incised valley fills, Cusiana Field, Llanos Foothills, Eastern Colombia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Pulham, A.; Edward, W.; App, J.

1996-12-31

The Cusiana Field is located in the Llanos Foothills of Eastern Colombia. The principal reservoir is the late Eocene Mirador Formation which comprises >50% of reserves. Currently the Mirador reservoir is providing nearly all of the 150,00bopd of production from the Cusiana Field. The Mirador reservoir comprises a stack of incised valley deposits. The fills of the valleys are dominated by quartz arenite sandstones. The average porosity of the valley sandstones is 8% which reflects abundant quartz cement ({approximately}14%) and significant compaction during deep burial ({approximately}20,000feet). Single valleys are up to 70 feet thick and exhibit a distinctive bipartite fillmore » that reflects changing energy conditions during filling. Bases of valleys have the coarsest grain size and have sedimentological and trace fossil evidence for deposition in highly stressed, brackish water environments. The upper parts of the valleys are typically finer grained and were deposited in more saline settings. Despite the low porosity of the Mirador valleys, drill stem tests and production log data show that they have phenomenal performance characteristics. Rates of {ge}10,000bopd are achieved from single valleys. Bases of the valley fills are the key contributors to flow. Integration of detailed core and pore system analysis with the reservoir performance data shows that the permeability fabric of the Mirador can be explained by original depositional architecture and simple loss of primary porosity. Comparison of Cusiana with other quartz-rich sandstones from around the world suggests that it`s low porosity/high performance is predictable.« less

Area of Interest 1, CO 2 at the Interface. Nature and Dynamics of the Reservoir/Caprock Contact and Implications for Carbon Storage Performance

DOE Office of Scientific and Technical Information (OSTI.GOV)

Mozley, Peter; Evans, James; Dewers, Thomas

2014-10-31

We examined the influence of geologic features present at the reservoir/caprock interface on the transmission of supercritical CO 2 into and through caprock. We focused on the case of deformation-band faults in reservoir lithologies that intersect the interface and transition to opening-mode fractures in caprock lithologies. Deformation-band faults are exceeding common in potential CO 2 injection units and our fieldwork in Utah indicates that this sort of transition is common. To quantify the impact of these interface features on flow and transport we first described the sedimentology and permeability characteristics of selected sites along the Navajo Sandstone (reservoir lithology) andmore » Carmel Formation (caprock lithology) interface, and along the Slickrock Member (reservoir lithology) and Earthy Member (caprock lithology) of the Entrada Sandstone interface, and used this information to construct conceptual permeability models for numerical analysis. We then examined the impact of these structures on flow using single-phase and multiphase numerical flow models for these study sites. Key findings include: (1) Deformation-band faults strongly compartmentalize the reservoir and largely block cross-fault flow of supercritical CO 2. (2) Significant flow of CO 2 through the fractures is possible, however, the magnitude is dependent on the small-scale geometry of the contact between the opening-mode fracture and the deformation band fault. (3) Due to the presence of permeable units in the caprock, caprock units are capable of storing significant volumes of CO 2, particularly when the fracture network does not extend all the way through the caprock. The large-scale distribution of these deformation-bandfault-to-opening-mode-fractures is related to the curvature of the beds, with greater densities of fractures in high curvature regions. We also examined core and outcrops from the Mount Simon Sandstone and Eau Claire Formation reservoir/caprock interface in order to extend our work to a reservoir/caprock pair this is currently being assessed for long-term carbon storage. These analyses indicate that interface features similar to those observed at the Utah sites 3 were not observed. Although not directly related to our main study topic, one byproduct of our investigation is documentation of exceptionally high degrees of heterogeneity in the pore-size distribution of the Mount Simon Sandstone. This suggests that the unit has a greater-than-normal potential for residual trapping of supercritical CO 2.« less

Soft-sediment deformation structures in Cambrian Series 2 tidal deposits (NW Estonia): implications for identifying endogenic triggering mechanisms in ancient sedimentary record

NASA Astrophysics Data System (ADS)

Põldsaar, Kairi

2015-04-01

Soft-sediment deformation structures (SSDS) are documented in several horizons within silt- and sandstones of the Cambrian Series 2 (Dominopolian Stage) Tiskre Formation, and some in the below-deposited argillaceous deposits of the Lükati Formation (northern part of the Baltoscandian Palaeobasin, NW Estonia). The aim of this study was to map, describe, and analyze these deformation features, discuss their deformation mechanism and possible triggers. Load structures (simple load casts, pillows, flame structures, convoluted lamination) with varying shapes and sizes occur in the Tiskre Fm in sedimentary interfaces within medium-bedded peritidal rhythmites (siltstone-argillaceous material) as well as within up to 3 m thick slightly seaward inclined stacked sandstone sequences. Homogenized beds, dish-and-pillar structures, and severely deformed bedding are also found within these stacked units and within a large tidal runoff channel infill. Autoclastic breccias and water-escape channels are rare and occur only in small-scale -- always related to thin, horizontal tidal laminae. Profound sedimentary dykes, sand volcanoes, and thrust faults, which are often related to earthquake triggered soft sediment deformation, were not observed within the studied intervals. Deformation horizon or horizons with large flat-topped pillows often with elongated morphologies occur at or near the boundary between the Tiskre and Lükati formations. Deformation mechanisms identified in this study for the various deformation types are gravitationally unstable reversed density gradient (especially in case of load features that are related to profound sedimentary interfaces) and lateral shear stress due to sediment current drag (in case of deformation structures that not related to loading at any apparent sedimentary interface). Synsedimentary liquefaction was identified as the primary driving force in most of the observed deformation horizons. Clay thixotropy may have contributed in the formation of large sandstone pillows within the Tiskre-Lükati boundary interval at some localities. It is discussed here that the formation of the observed SSDS is genetically related to the restless dynamics of the storm-influenced open marine tidal depositional environment. The most obvious causes of deformation were rapid-deposition, shear and slumping caused by tidal surges, and storm-wave loading.

Red Fork and lower Skinner sandstones in northwest Tecumseh field, Pottawatomie County, Oklahoma

DOE Office of Scientific and Technical Information (OSTI.GOV)

Dale, T.B.

1987-08-01

The Northwest Tecumseh field, discovered in 1978, produces from the Pennsylvanian Skinner and Red Fork sandstones at 4800 ft. The 50 wells had produced 6.4 million bbl of oil and 20.8 bcf of gas through 1986. The field is 4.5 mi long, 3/4 mi wide, and the vertical section contains up to 132 ft of sandstone with greater than 10% porosity. These stacked, interconnected north-northeast-trending, channel-fill sandstones are part of a much larger fluvial/distributary system. These channels flowed to the north and cut down into underlying, fossiliferous, carbonate-bearing marine shale. A pre-Pennsylvanian structural low, trending north-northeast, existed in the southernmore » half of the field and created a predisposition for the channel trend which continued through Red Fork and Skinner deposition. The north-northeast-trending sandstone complex, parallel with present-day regional structural strike, provides the excellent configuration for this efficient stratigraphic trap. The northern end of the field is marked by bifurcation of the channel complex and by the crosscutting of a younger clay-filled channel. Despite the lenticularity of the sandstone sequence, there appears to be a uniform gas-oil contact and minor southwestward tilt of the oil-water contact in the south part of the pool. The primary reservoir energy is provided by a dissolved gas drive, with some assistance from the 60-ft gas cap. The vertical oil column is 80 ft. These reservoir sandstones are fine-grained quartzarenites, and the dissolution of ferrodolomite has increased porosities up to 21%. Kaolinite is the predominant clay mineral and has a tendency to migrate and reduce permeability during production.« less

Suspected microbial-induced sedimentary structures (MISS) in Furongian (Upper Cambrian; Jiangshanian, Sunwaptan) strata of the Upper Mississippi Valley

USGS Publications Warehouse

Eoff, Jennifer D.

2014-01-01

The Furongian (Upper Cambrian; Jiangshanian and Sunwaptan) Tunnel City Group (Lone Rock Formation and Mazomanie Formation), exposed in Wisconsin and Minnesota, represents a shallow-marine clastic environment during a time of exceptionally high sea level. Lithofacies from shoreface to transitional-offshore settings document deposition in a wave- and storm-dominated sea. Flooding of the cratonic interior was associated with formation of a condensed section and the extensive development of microbial mats. Biolamination, mat fragments, wrinkle structures, and syneresis cracks are preserved in various sandstone facies of the Lone Rock Formation, as is evidence for the cohesive behavior of sand. These microbial-induced sedimentary structures (MISS) provide unique signals of biological–physical processes that physical structures alone cannot mimic. The MISS are associated with a trilobite extinction event in the Steptoean–Sunwaptan boundary interval. This may support recent claims that Phanerozoic microbial mats were opportunistic disaster forms that flourished during periods of faunal turnover. Further investigation of stratigraphic, taphonomic, and other potential biases, however, is needed to fully test this hypothesis.

New Zircon U-Pb Age Constrain of the Origin of Devil's River Uplift (SW Texas) and Insights into the Late Proterozoic and Paleozoic Evolution of the Southern Margin of Laurentia

NASA Astrophysics Data System (ADS)

Rodriguez, E.; Dickerson, P. W.; Stockli, D. F.

2017-12-01

The Devils River Uplift (DRU) in SW Texas records the evolution of the southern Laurentian margin from Grenvillian orogenesis and assembly of Rodinia, to its fragmentation by rifting, and to the amalgamation of Pangaea. It was cored by a well (Shell No. 1 Stewart), penetrating Precambrian gneisses and Cambrian metasediments and sandstones. New zircon LA-ICP-MS data from a total of 10 samples elucidate the crystallization and depositional ages, as well as the detrital provenance, of Precambrian and Cambrian rocks from the DRU. Zircons from five Precambrian crystalline basement samples (6000-9693') yield uniform U-Pb crystallization ages of 1230 Ma that are similar to ages for young gneisses of the Valley Spring Domain (Llano uplift) in central Texas, where they mark the cessation of arc magmatism within the Grenville orogenic belt. The 1230 Ma igneous basement is overlain by L.-M. Cambrian metasedimentary rocks ( 4000-6000') with maximum depositional ages of 533-545 Ma. Detrital zircons from Cambrian strata are dominated by a 1070-1080 Ma population, likely derived from basement units exposed in Texas (Llano uplift, Franklin Mts.), with minor contributions from local 1230 Ma Precambrian basement and the 1380-1500 Ma Granite Rhyolite Province. The L.-M. Cambrian interval is dominated (>80%) by Neoproterozoic detrital magmatic zircons with two major distinct age clusters at 570-700 Ma and 780-820 Ma, supporting a two-stage Rodinia rift model and providing strong evidence for major Cryogenian-Eocambrian intraplate magmatism along the southern margin of Rodinia. Moreover, detrital zircon signatures for L.-M. and U. Cambrian strata strongly correlate with those from the Cuyania terrane of W. Argentina - notably the W. Sierras Pampeanas (Sa. Pie de Palo, Sa. de Maz): 1230 Ma from metasandstones (PdP); 1081-1038 Ma from metasiliciclastics (PdP, SdM); Cryogenian-Eocambrian [774 & 570 Ma] plutons (SdM, PdP). In summary, these new zircon U-Pb data from DRU in SW Texas show that it is part of the Grenville orogenic belt, characterized by 1230 Ma magmatism, and that it experienced Cryogenian-Eocambrian intraplate magmatism as well. Significant correlations between DRU and the Cuyania terrane imply that both participated in Rodinia rifting and creation of the southern Laurentian margin.

Correlative multiple porosimetries for reservoir sandstones with adoption of a new reference-sample-guided computed-tomographic method.

PubMed

Jin, Jae Hwa; Kim, Junho; Lee, Jeong-Yil; Oh, Young Min

2016-07-22

One of the main interests in petroleum geology and reservoir engineering is to quantify the porosity of reservoir beds as accurately as possible. A variety of direct measurements, including methods of mercury intrusion, helium injection and petrographic image analysis, have been developed; however, their application frequently yields equivocal results because these methods are different in theoretical bases, means of measurement, and causes of measurement errors. Here, we present a set of porosities measured in Berea Sandstone samples by the multiple methods, in particular with adoption of a new method using computed tomography and reference samples. The multiple porosimetric data show a marked correlativeness among different methods, suggesting that these methods are compatible with each other. The new method of reference-sample-guided computed tomography is more effective than the previous methods when the accompanied merits such as experimental conveniences are taken into account.

Correlative multiple porosimetries for reservoir sandstones with adoption of a new reference-sample-guided computed-tomographic method

PubMed Central

Jin, Jae Hwa; Kim, Junho; Lee, Jeong-Yil; Oh, Young Min

2016-01-01

One of the main interests in petroleum geology and reservoir engineering is to quantify the porosity of reservoir beds as accurately as possible. A variety of direct measurements, including methods of mercury intrusion, helium injection and petrographic image analysis, have been developed; however, their application frequently yields equivocal results because these methods are different in theoretical bases, means of measurement, and causes of measurement errors. Here, we present a set of porosities measured in Berea Sandstone samples by the multiple methods, in particular with adoption of a new method using computed tomography and reference samples. The multiple porosimetric data show a marked correlativeness among different methods, suggesting that these methods are compatible with each other. The new method of reference-sample-guided computed tomography is more effective than the previous methods when the accompanied merits such as experimental conveniences are taken into account. PMID:27445105

CO2 Storage Potential of the Eocene Tay Sandstone, Central North Sea, UK

NASA Astrophysics Data System (ADS)

Gent, Christopher; Williams, John

2017-04-01

Carbon Capture and Storage (CCS) is crucial for low-carbon industry, climate mitigation and a sustainable energy future. The offshore capacity of the UK is substantial and has been estimated at 78 Gt of CO2 in saline aquifers and hydrocarbon fields. The early-mid Eocene Tay Sandstone Member of the Central North Sea (CNS) is a submarine-fan system and potential storage reservoir with a theoretical capacity of 123 Mt of CO2. The Tay Sandstone comprises of 4 sequences, amalgamating into a fan complex 125km long and 40 km at a minimum of 1500 m depth striking NW-SE, hosting several hydrocarbon fields including Gannett A, B, D and Pict. In order to better understand the storage potential and characteristics, the Tay Sandstone over Quadrant 21 has been interpreted using log correlation and 3D seismic. Understanding the internal and external geometry of the sandstone as well as the lateral extent of the unit is essential when considering CO2 vertical and horizontal fluid flow pathways and storage security. 3D seismic mapping of a clear mounded feature has revealed the youngest sequence of the Tay complex; a homogenous sand-rich channel 12 km long, 1.5 km wide and on average 100 m thick. The sandstone has porosity >35%, permeability >5 D and a net to gross of 0.8, giving a total pore volume of 927x106 m3. The remaining three sequences are a series of stacked channels and interbedded mudstones which are more quiescent on the seismic, however, well logs indicate each subsequent sequence reduce in net to gross with age as mud has a greater influence in the early fan system. Nevertheless, the sandstone properties remain relatively consistent and are far more laterally extensive than the youngest sequence. The Tay Sandstone spatially overlaps several other potential storage sites including the older Tertiary sandstones of the Cromarty, Forties and Mey Members and deeper Jurassic reservoirs. This favours the Tay Sandstone to be considered in a secondary or multiple stacked storage scenario. Principal risks include injection-induced pressure-increase limiting injectivity, caused by limited connectivity between sand-rich sequences, up-dip migration to sandstone shelf-facies of the overlying Mousa Formation, or to hydraulically-connected underlying Tertiary sandstones such as the Forties Member which may in places be in hydraulic communication.

Depositional setting and diagenetic evolution of some Tertiary unconventional reservoir rocks, Uinta Basin, Utah.

USGS Publications Warehouse

Pitman, Janet K.; Fouch, T.D.; Goldhaber, M.B.

1982-01-01

The Douglas Creek Member of the Tertiary Green River Formation underlies much of the Uinta basin, Utah, and contains large volumes of oil and gas trapped in a complex of fractured low-permeability sandstone reservoirs. In the SE part of the basin at Pariette Bench, the Eocene Douglas Creek Member is a thick sequence of fine- grained alluvial sandstone complexly intercalated with lacustrine claystone and carbonate rock. Sediments were deposited in a subsiding intermontane basin along the shallow fluctuating margin of ancient Lake Uinta. Although the Uinta basin has undergone postdepositional uplift and erosion, the deepest cored rocks at Pariette Bench have never been buried more than 3000m.-from Authors

Origin and diagenesis of clay minerals in relation to sandstone paragenesis: An example in eolian dune reservoirs and associated rocks, Permian upper part of the Minnelusa Formation, Powder River basin, Wyoming

DOE Office of Scientific and Technical Information (OSTI.GOV)

Pollastro, R.M.; Schenk, C.J.

Eolian dune sandstones are the principal reservoir rocks in the Permian upper part of the Minnelusa Formation, Powder River basin, Wyoming. These sandstones formed as shorelines retreated and dunes migrated across siliciclastic sabkhas. Sandstones are mainly quartzarenites; on average, clay minerals constitute about 5 wt.% the whole rock. Although present in minor amounts, clay minerals play an important role in the diagenetic evolution of these sandstones. Allogenic clay minerals are present in shaly rock fragments and laminae. Early infiltration of clays into porous sabkha sands commonly form characteristic menisei or bridges between framework grains or, when more extensive, form coatingsmore » or rims on grain surfaces. Authigenic clays include nearly pure smectite, mixed-layer illite/smectite (I/S), and late diagenetic illite and corrensite; these clay minerals are present as pore-lining cements. In addition to the deposition and neoformation of clay minerals throughout sandstone paragenesis, the conversion of smectite to illite occurred as temperatures increased with progressive burial. A temperature of 103C is calculated at a present depth of 3,200 m using a geothermal gradient of 30C/km and a mean annual surface temperature of 7C. After correction for uplift and erosion (250 m), the maximum calculated temperature for the conversion of all random I/S to ordered I/S is 100C. This calculated temperature is in excellent agreement with temperatures of 100-110C implied from I/S geothermometry.« less

Digital Rock Physics Aplications: Visualisation Complex Pore and Porosity-Permeability Estimations of the Porous Sandstone Reservoir

NASA Astrophysics Data System (ADS)

Handoyo; Fatkhan; Del, Fourier

2018-03-01

Reservoir rock containing oil and gas generally has high porosity and permeability. High porosity is expected to accommodate hydrocarbon fluid in large quantities and high permeability is associated with the rock’s ability to let hydrocarbon fluid flow optimally. Porosity and permeability measurement of a rock sample is usually performed in the laboratory. We estimate the porosity and permeability of sandstones digitally by using digital images from μCT-Scan. Advantages of the method are non-destructive and can be applied for small rock pieces also easily to construct the model. The porosity values are calculated by comparing the digital image of the pore volume to the total volume of the sandstones; while the permeability values are calculated using the Lattice Boltzmann calculations utilizing the nature of the law of conservation of mass and conservation of momentum of a particle. To determine variations of the porosity and permeability, the main sandstone samples with a dimension of 300 × 300 × 300 pixels are made into eight sub-cubes with a size of 150 × 150 × 150 pixels. Results of digital image modeling fluid flow velocity are visualized as normal velocity (streamline). Variations in value sandstone porosity vary between 0.30 to 0.38 and permeability variations in the range of 4000 mD to 6200 mD. The results of calculations show that the sandstone sample in this research is highly porous and permeable. The method combined with rock physics can be powerful tools for determining rock properties from small rock fragments.

Lower Cretaceous Avile Sandstone, Neuquen basin, Argentina - Exploration model for a lowstand clastic wedge in a back-arc basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ryer, T.A.

1991-03-01

The Neuquen basin of western Argentina is a back-arc basin that was occupied by epeiric seas during much of Jurassic and Cretaceous time. The Avile Sandstone Member of the Agrio Formation records a pronounced but short-lived regression of the Agrio sea during middle Hauterivian (Early Cretaceous) time. Abrupt lowering of relative sea level resulted in emergence and erosion of the Agrio sea floor; shoreline and fluvial facies characteristic of the Centenario Formation shifted basinward. The Avile rests erosionally upon lower Agrio shale over a large area; well-sorted, porous sandstones within the member pinch out laterally against the base-Avile erosional surface.more » Avile deposition closed with an abrupt transgression of the shoreline to the approximate position it had occupied prior to the Avile regression. The transgressive deposits are carbonate rich, reflecting starvation of the basin as a consequence of sea-level rise. The Avile lowstand clastic wedge consists predominantly of sandstones deposited in fluvial to shallow-marine paleoenvironments; eolian sandstones probably constitute an important component in the eastern part of the area. The sandstones locally have excellent reservoir characteristics; they constitute the reservoirs in the Puesto Hernandez, Chihuido de la Sierra Negra, and Filo Morado fields. The pinch-out of the Avile lowstand clastic wedge has the potential to form stratigraphic traps in favorable structural positions. The depositional model indicates that there may be a viable stratigraphic play to be made along the Avile pinch-out in the deep, relatively undrilled, northwestern part of the Neuquen basin.« less

Changes in the composition and properties of Ashalchinskoye bitumen-saturated sandstones when exposed to water vapor

NASA Astrophysics Data System (ADS)

Korolev, E.; Eskin, A.; Kolchugin, A.; Morozov, V.; Khramchenkov, M.; Gabdelvalieva, R.

2018-05-01

Ashalchinskoye bitumen deposit is an experimental platform for testing technology of high-viscosity oil extraction from reservoir rocks. Last time for enhanced of oil recovery in reservoir used pressurization a water vapor with a temperature of ∼ 180 ° C (SAGD technology). However, what happens in sandstone reservoir is little known. We did a study of the effects of water vapor on the structural components of bitumen saturated sandstone. In paper were studied the rock samples at base condition and after one week exposure by water vapour. The thermal analysis showed that steaming helps to removes light and middle oil fractions with a boiling point up to 360 ° C from oil saturated sandstones. Content of heavy oil fractions virtually unchanged. Studying the composition of water extractions of samples showed that the process of aquathermolysis of oil is accompanied by a lowering of the pH of the pore solution from 7.4 to 6.5 and rise content in several times of mobile cations Ca2+, Mg2+ and HCO3 -, SO4 2- anions. Follows from this that the thermal steam effect by bitumen saturated sandstones leads to partial oxidation of hydrocarbons with to form a carbon dioxide. The source of sulfate ions were oxidized pyrite aggregates. Due to the increasing acidity of condensed water, which fills the pore space of samples, pore fluid becomes aggressive to calcite and dolomite cement of bitumen saturated sandstones. As a result of the dissolution of carbonate cement the pore fluid enriched by calcium and magnesium cations. Clearly, that the process is accompanied by reduction of contact strength between fragments of minerals and rocks. Resulting part of compounds is separated from the outer side of samples and falls to bottom of water vapor container. Decreasing the amount of calcite and dolomite anions in samples in a steam-treated influence is confirmed by X-Ray analysis. X-Ray analysis data of study adscititious component of rocks showed that when influenced of water vapor to bitumen saturated sandstones there are the processes of transformation of clay minerals. Mixed-illite-montmorillonite phase is primarily exposed to changes. In this case we fix initial stage of the destruction of polycrystalline particles mixed-mineral. Reducing the size of clay minerals particles along the normal to the layers (L001) is the result from lower energy costs of delamination and disintegration the crystallites along this direction, in comparison with others. Thus, using of SAGD technology at exploitation of Ashalchinskoye bitumen saturated reservoir will be followed by acidification of the pore fluid, activation processes of dissolution calcite cement and transformation of mixed-layers clays minerals.

Chapter 2. Assessment of undiscovered conventional oil and gas resources--Upper Jurassic-Lower Cretaceous Cotton Valley group, Jurassic Smackover interior salt basins total petroleum system, in the East Texas basin and Louisiana-Mississippi salt basins provinces.

USGS Publications Warehouse

Dyman, T.S.; Condon, S.M.

2006-01-01

The Jurassic Smackover Interior Salt Basins Total Petroleum System is defined for this assessment to include (1) Upper Jurassic Smackover Formation carbonates and calcareous shales and (2) Upper Jurassic and Lower Cretaceous Cotton Valley Group organic-rich shales. The Jurassic Smackover Interior Salt Basins Total Petroleum System includes four conventional Cotton Valley assessment units: Cotton Valley Blanket Sandstone Gas (AU 50490201), Cotton Valley Massive Sandstone Gas (AU 50490202), Cotton Valley Updip Oil and Gas (AU 50490203), and Cotton Valley Hypothetical Updip Oil (AU 50490204). Together, these four assessment units are estimated to contain a mean undiscovered conventional resource of 29.81 million barrels of oil, 605.03 billion cubic feet of gas, and 19.00 million barrels of natural gas liquids. The Cotton Valley Group represents the first major influx of clastic sediment into the ancestral Gulf of Mexico. Major depocenters were located in south-central Mississippi, along the Louisiana-Mississippi border, and in northeast Texas. Reservoir properties and production characteristics were used to identify two Cotton Valley Group sandstone trends across northern Louisiana and east Texas: a high-permeability blanket-sandstone trend and a downdip, low-permeability massive-sandstone trend. Pressure gradients throughout most of both trends are normal, which is characteristic of conventional rather than continuous basin-center gas accumulations. Indications that accumulations in this trend are conventional rather than continuous include (1) gas-water contacts in at least seven fields across the blanket-sandstone trend, (2) relatively high reservoir permeabilities, and (3) high gas-production rates without fracture stimulation. Permeability is sufficiently low in the massive-sandstone trend that gas-water transition zones are vertically extensive and gas-water contacts are poorly defined. The interpreted presence of gas-water contacts within the Cotton Valley massive-sandstone trend, however, suggests that accumulations in this trend are also conventional.

Late Cambrian - Early Ordovician turbidites of Gorny Altai (Russia): Compositions, sources, deposition settings, and tectonic implications

NASA Astrophysics Data System (ADS)

Kruk, Nikolai N.; Kuibida, Yana V.; Shokalsky, Sergey P.; Kiselev, Vladimir I.; Gusev, Nikolay I.

2018-06-01

The Cambrian-Ordovician transition was the time of several key events in the history of Central Asia. They were the accretion of Mariana-type island arc systems to the Siberian continent, the related large-scale orogeny and intrusions of basaltic and granitic magma and the formation of a huge turbidite basin commensurate with the Bengal Gulf basin in the western part of the Central Asian orogenic belt (CAOB). The structure of the basin, as well as the sources and environments of deposition remain open to discussion. This paper presents new major- and trace-element data on Late-Cambrian-Early Ordovician turbidites from different parts of the Russian Altai and a synthesis of Nd isotope composition and ages of detrital zircons. The turbidites share chemical similarity with material shed from weathered continental arcs. Broad variations of CIA (39-73) and ICV (0.63-1.66) signatures in sandstones suggest origin from diverse sources and absence of significant sorting. Trace elements vary considerably and have generally similar patterns in rocks from different terranes. On the other hand, there are at least two provinces according to Nd isotope composition and age of detrital zircons. Samples from eastern Russian Altai contain only Phanerozoic zircons and have Nd isotope ratios similar to those in Early Cambrian island arcs (εNdt + 4.4… + 5.4; TNd(DM)-2-st = 0.8-0.9 Ga). Samples from central, western, and southern parts of Russian Altai contain Precambrian zircons (some as old as Late Archean) and have a less radiogenic Nd composition (εNdt up to -3.6; TNd(DM)-2-st up to 1.5 Ga). The chemical signatures of Late Cambrian to Early Ordovician turbidites indicate a provenance chemically more mature than the island arc rocks, and the presence of zircons with 510-490 Ma ages disproves their genetic relation with island arcs. The turbidite basin formed simultaneously with peaks of granitic and alkali-basaltic magmatism in the western Central Asian orogen and resulted from interplay of plate tectonic and plume tectonic processes.

Performance of Surfactant Methyl Ester Sulphonate solution for Oil Well Stimulation in reservoir sandstone TJ Field

NASA Astrophysics Data System (ADS)

Eris, F. R.; Hambali, E.; Suryani, A.; Permadi, P.

2017-05-01

Asphaltene, paraffin, wax and sludge deposition, emulsion and water blocking are kinds ofprocess that results in a reduction of the fluid flow from the reservoir into formation which causes a decrease of oil wells productivity. Oil well Stimulation can be used as an alternative to solve oil well problems. Oil well stimulation technique requires applying of surfactant. Sodium Methyl Ester Sulphonate (SMES) of palm oil is an anionic surfactant derived from renewable natural resource that environmental friendly is one of potential surfactant types that can be used in oil well stimulation. This study was aimed at formulation SMES as well stimulation agent that can identify phase transitions to phase behavior in a brine-surfactant-oil system and altered the wettability of rock sandstone and limestone. Performance of SMES solution tested by thermal stability test, phase behavioral examination and rocks wettability test. The results showed that SMES solution (SMES 5% + xylene 5% in the diesel with addition of 1% NaCl at TJformation water and SMES 5% + xylene 5% in methyl ester with the addition of NaCl 1% in the TJ formation water) are surfactant that can maintain thermal stability, can mostly altered the wettability toward water-wet in sandstone reservoir, TJ Field.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Raduha, S.; Butler, D.; Mozley, P. S.

Here, we examined the potential impact on CO 2 transport of zones of deformation bands in reservoir rock that transition to opening-mode fractures within overlying caprock. Sedimentological and petrophysical measurements were collected along an approximately 5 m × 5 m outcrop of the Slick Rock and Earthy Members of the Entrada Sandstone on the eastern flank of the San Rafael Swell, Utah, USA. Measured deformation band permeability (2 mD) within the reservoir facies is about three orders of magnitude lower than the host sandstone. Average permeability of the caprock facies (0.0005 mD) is about seven orders of magnitude lower thanmore » the host sandstone. Aperture-based permeability estimates of the opening-mode caprock fractures are high (3.3 × 10 7 mD). High-resolution CO 2–H 2O transport models incorporate these permeability data at the millimeter scale. We then varied fault properties at the reservoir/caprock interface between open fractures and deformation bands as part of a sensitivity study. Numerical modeling results suggest that zones of deformation bands within the reservoir strongly compartmentalize reservoir pressures largely blocking lateral, cross-fault flow of supercritical CO 2. Significant vertical CO 2 transport into the caprock occurred in some scenarios along opening-mode fractures. The magnitude of this vertical CO 2 transport depends on the small-scale geometry of the contact between the opening-mode fracture and the zone of deformation bands, as well as the degree to which fractures penetrate caprock. Finally, the presence of relatively permeable units within the caprock allows storage of significant volumes of CO 2, particularly when the fracture network does not extend all the way through the caprock.« less

Rock Physics and Petrographic Parameters Relationship Within Siliciclastic Rocks: Quartz Sandstone Outcrop Study Case

NASA Astrophysics Data System (ADS)

Syafriyono, S.; Caesario, D.; Swastika, A.; Adlan, Q.; Syafri, I.; Abdurrokhim, A.; Mardiana, U.; Mohamad, F.; Alfadli, M. K.; Sari, V. M.

2018-03-01

Rock physical parameters value (Vp and Vs) is one of fundamental aspects in reservoir characterization as a tool to detect rock heterogenity. Its response is depend on several reservoir conditions such as lithology, pressure and reservoir fluids. The value of Vp and Vs is controlled by grain contact and contact stiffness, a function of clay mineral content and porosity also affected by mineral composition. The study about Vp and Vs response within sandstone and its relationship with petrographic parameters has become important to define anisotrophy of reservoir characteristics distribution and could give a better understanding about local diagenesis that influence clastic reservoir properties. Petrographic analysis and Vp-Vs calculation was carried out to 12 core sample which is obtained by hand-drilling of the outcrop in Sukabumi area, West Java as a part of Bayah Formation. Data processing and interpretation of sedimentary vertical succession showing that this outcrop comprises of 3 major sandstone layers indicating fluvial depositional environment. As stated before, there are 4 petrographic parameters (sorting, roundness, clay mineral content, and grain contact) which are responsible to the differences of shear wave and compressional wave value in this outcrop. Lithology with poor-sorted and well- roundness has Vp value lower than well-sorted and poor-roundness (sub-angular) grain. For the sample with high clay content, Vp value is ranging from 1681 to 2000 m/s and could be getting high until 2190 to 2714 m/s in low clay content sample even though the presence of clay minerals cannot be defined neither as matrix nor cement. The whole sample have suture grain contact indicating telogenesis regime whereas facies has no relationship with Vp and Vs value because of the different type of facies show similar petrographic parameters after diagenesis.

Reconstruction of a digital core containing clay minerals based on a clustering algorithm.

PubMed

He, Yanlong; Pu, Chunsheng; Jing, Cheng; Gu, Xiaoyu; Chen, Qingdong; Liu, Hongzhi; Khan, Nasir; Dong, Qiaoling

2017-10-01

It is difficult to obtain a core sample and information for digital core reconstruction of mature sandstone reservoirs around the world, especially for an unconsolidated sandstone reservoir. Meanwhile, reconstruction and division of clay minerals play a vital role in the reconstruction of the digital cores, although the two-dimensional data-based reconstruction methods are specifically applicable as the microstructure reservoir simulation methods for the sandstone reservoir. However, reconstruction of clay minerals is still challenging from a research viewpoint for the better reconstruction of various clay minerals in the digital cores. In the present work, the content of clay minerals was considered on the basis of two-dimensional information about the reservoir. After application of the hybrid method, and compared with the model reconstructed by the process-based method, the digital core containing clay clusters without the labels of the clusters' number, size, and texture were the output. The statistics and geometry of the reconstruction model were similar to the reference model. In addition, the Hoshen-Kopelman algorithm was used to label various connected unclassified clay clusters in the initial model and then the number and size of clay clusters were recorded. At the same time, the K-means clustering algorithm was applied to divide the labeled, large connecting clusters into smaller clusters on the basis of difference in the clusters' characteristics. According to the clay minerals' characteristics, such as types, textures, and distributions, the digital core containing clay minerals was reconstructed by means of the clustering algorithm and the clay clusters' structure judgment. The distributions and textures of the clay minerals of the digital core were reasonable. The clustering algorithm improved the digital core reconstruction and provided an alternative method for the simulation of different clay minerals in the digital cores.

Integrated reservoir characterization and flow simulation for well targeting and reservoir management, Iagifu-Hedinia field, Southern Highlands Province, Papua New Guinea

DOE Office of Scientific and Technical Information (OSTI.GOV)

Franklin, S.P.; Livingston, J.E.; Fitzmorris, R.E.

Infill drilling based on integrated reservoir characterization and flow simulation is increasing recoverable reserves by 20 MMBO, in lagifu-Hedinia Field (IHF). Stratigraphically-zoned models are input to window and full-field flow simulations, and results of the flow simulations target deviated and horizontal wells. Logging and pressure surveys facilitate detailed reservoir management. Flooding surfaces are the dominant control on differential depletion within and between reservoirs. The primary reservoir is the basal Cretaceous Toro Sandstone. Within the IHF, Toro is a 100 m quartz sandstone composed of stacked, coarsening-upward parasequences within a wave-dominated deltaic complex. Flooding surfaces are used to form a hydraulicmore » zonation. The zonation is refined using discontinuities in RIFT pressure gradients and logs from development wells. For flow simulation, models use 3D geostatistical techniques. First, variograms defining spatial correlation are developed. The variograms are used to construct 3D porosity and permeability models which reflect the stratigraphic facies models. Structure models are built using dipmeter, biostratigraphic, and surface data. Deviated wells often cross axial surfaces and geometry is predicted from dip domain and SCAT. Faults are identified using pressure transient data and dipmeter. The Toro reservoir is subnormally pressured and fluid contacts are hydrodynamically tilted. The hydrodynamic flow and tilted contacts are modeled by flow simulation and constrained by maps of the potentiometric surface.« less

Characteristics and origin of the relatively high-quality tight reservoir in the Silurian Xiaoheba Formation in the southeastern Sichuan Basin

PubMed Central

Gong, Xiaoxing; Shi, Zejin; Wang, Yong; Tian, Yaming; Li, Wenjie; Liu, Lei

2017-01-01

A mature understanding of the sandstone gas reservoir in the Xiaoheba Formation in the southeastern Sichuan Basin remains lacking. To assess the reservoir characteristics and the origin of the high-quality reservoir in the Xiaoheba Formation, this paper uses systematic field investigations, physical property analysis, thin section identification, scanning electron microscopy and electron microprobe methods. The results indicate that the Xiaoheba sandstone is an ultra-tight and ultra-low permeability reservoir, with an average porosity of 2.97% and an average permeability of 0.56×10−3 μm2. This promising reservoir is mainly distributed in the Lengshuixi and Shuangliuba regions and the latter has a relatively high-quality reservoir with an average porosity of 5.28% and average permeability of 0.53×10−3 μm2. The reservoir space comprises secondary intergranular dissolved pores, moldic pores and fractures. Microfacies, feldspar dissolution and fracture connectivity control the quality of this reservoir. The relatively weak compaction and cementation in the interbedded delta front distal bar and interdistributary bay microfacies indirectly protected the primary intergranular pores and enhanced late-stage dissolution. Late-stage potassium feldspar dissolution was controlled by the early-stage organic acid dissolution intensity and the distance from the hydrocarbon generation center. Early-stage fractures acted as pathways for organic acid migration and were therefore important factors in the formation of the reservoir. Based on these observations, the area to the west of the Shuangliuba and Lengshuixi regions has potential for gas exploration. PMID:28686735

Revitalizing a mature oil play: Strategies for finding and producing oil in Frio Fluvial-Deltaic Sandstone reservoirs of South Texas

DOE Office of Scientific and Technical Information (OSTI.GOV)

Knox, P.R.; Holtz, M.H.; McRae, L.E.

Domestic fluvial-dominated deltaic (FDD) reservoirs contain more than 30 Billion barrels (Bbbl) of remaining oil, more than any other type of reservoir, approximately one-third of which is in danger of permanent loss through premature field abandonments. The U.S. Department of Energy has placed its highest priority on increasing near-term recovery from FDD reservoirs in order to prevent abandonment of this important strategic resource. To aid in this effort, the Bureau of Economic Geology, The University of Texas at Austin, began a 46-month project in October, 1992, to develop and demonstrate advanced methods of reservoir characterization that would more accurately locatemore » remaining volumes of mobile oil that could then be recovered by recompleting existing wells or drilling geologically targeted infill. wells. Reservoirs in two fields within the Frio Fluvial-Deltaic Sandstone (Vicksburg Fault Zone) oil play of South Texas, a mature play which still contains 1.6 Bbbl of mobile oil after producing 1 Bbbl over four decades, were selected as laboratories for developing and testing reservoir characterization techniques. Advanced methods in geology, geophysics, petrophysics, and engineering were integrated to (1) identify probable reservoir architecture and heterogeneity, (2) determine past fluid-flow history, (3) integrate fluid-flow history with reservoir architecture to identify untapped, incompletely drained, and new pool compartments, and (4) identify specific opportunities for near-term reserve growth. To facilitate the success of operators in applying these methods in the Frio play, geologic and reservoir engineering characteristics of all major reservoirs in the play were documented and statistically analyzed. A quantitative quick-look methodology was developed to prioritize reservoirs in terms of reserve-growth potential.« less

Practical characterization of eolian reservoirs for development: Nugget Sandstone, Utah—Wyoming thrust belt

NASA Astrophysics Data System (ADS)

Lindquist, Sandra J.

1988-04-01

The Jurassic eolian Nugget Sandstone of the Utah-Wyoming thrust belt is a texturally heterogeneous formation with anisotropic reservoir inherited primarily from the depositional environment. Original reservoir quality has been reduced somewhat by cementation and slightly enhanced by dissolution. Low-permeability, gouge-filled micro-faults compartmentalize the formation, whereas intermittently open fractures provide effective permeability paths locally. Where productive, the Nugget Sandstone ranges from approximately 800 to 1050 ft (244-320 m) thick at subsurface depths of 7500 to 15,000 ft (2286-4572 m). Porosity ranges from several percent to 25%, and permeability covers five orders of magnitude from hundredths of milliDarcies to Darcies. Some Nugget reservoirs are fully charged with hydrocarbons. Different stratification types have unique depositional textures, primary and diagenetic mineralogies, and deformational fabrics resulting in characteristic porosity, permeability, permeability directionality, and pore geometry attributes. Such characteristics can be determined from core analysis, mercury injection, nuclear magnetic resonance, conventional log, dipmeter and production data. Nugget dune deposits (good reservoir facies) primarily consist of grainflow and wind-ripple cross-strata, the former of which have the better reservoir quality and the lesser heterogeneity in bedding texture. High-permeability facies are commonly affected by local quartz and nodular carbonate cementation, chlorite (and lesser illite) precipitation, and minor framework and cement dissolution. Gouge-filled micro-faults are the predominant deformational overprint. Interdune, sand-sheet, and other water-associated deposits (poor reservoir facies) are characterized by low-angle wind-ripple laminae and more irregular bedding, some of which is associated with damp or wet conditions. Water-associated Nugget stratification generally contains the finest grained depositional textures and has the poorest reservoir properties. These non-dune facies contain intergranular micritic carbonate and illite precipitates and are most affected by compaction and pressure solution phenomena. Open types of fractures are somewhat more likely in this lower permeability rock. Depositional models incorporating dune morphologies, facies distribution, permeability directionality, and theoretical concepts regarding dune migration through time are useful in delineating correlative intervals most likely to have continuity and potential communication of reservoir properties. Stratigraphic models can be adapted for reservoir simulation studies and also can be utilized in solving structural resolution problems if correlatable vertical sequences and relatively consistent cross-strata orientations exist.

Fluvial-deltaic sedimentation and stratigraphy of the ferron sandstone

USGS Publications Warehouse

Anderson, P.B.; Chidsey, T.C.; Ryer, T.A.

1997-01-01

East-central Utah has world-class outcrops of dominantly fluvial-deltaic Turonian to Coniacian aged strata deposited in the Cretaceous foreland basin. The Ferron Sandstone Member of the Mancos Shale records the influences of both tidal and wave energy on fluvial-dominated deltas on the western margin of the Cretaceous western interior seaway. Revisions of the stratigraphy are proposed for the Ferron Sandstone. Facies representing a variety of environments of deposition are well exposed, including delta-front, strandline, marginal marine, and coastal-plain. Some of these facies are described in detail for use in petroleum reservoir characterization and include permeability structure.

Geology of the Powder River Basin, Wyoming and Montana, with reference to subsurface disposal of radioactive wastes

USGS Publications Warehouse

Beikman, Helen M.

1962-01-01

The Powder River Basin is a structural and topographic basin occupying an area of about 20,000 square miles in northeastern Wyoming arid southeastern Montana. The Basin is about 230 miles long in a northwest-southeast direction and is about 100 miles wide. It is bounded on three sides by mountains in which rocks of Precambrian age are exposed. The Basin is asymmetrical with a steep west limb adjacent to the Bighorn Mountains and a gentle east limb adjacent to the Black Hills. Sedimentary rocks within the Basin have a maximum thickness of about 18,000 feet and rocks of every geologic period are represented. Paleozoic rocks are about 2,500 feet thick and consist of marine bonate rocks and sandstone; Mesozoic rocks are about 9,500 feet thick and consist of both marine and nonmarine siltstone and sandstone; and Cenozoic rocks are from 4,000 to 6,000 feet thick and consist of coal-bearing sandstone and shale. Radioactive waste could be stored in the pore space of permeable sandstone or in shale where space could be developed. Many such rock units that could be used for storing radioactive wastes are present within the Powder River Basin. Permeable sandstone beds that may be possible reservoirs for storage of radioactive waste are present throughout the Powder River Basin. These include sandstone beds in the Flathead Sandstone and equivalent strata in the Deadwood Formation, the Tensleep Sandstone and equivalent strata in the Minnelusa Formation and the Sundance Formation in rocks of pre-Cretaceous age. However, most of the possible sandstone reservoirs are in rocks of Cretaceous age and include sandstone beds in the Fall River, Lakota, Newcastle, Frontier, Cody, and Mesaverde Formations. Problems of containment of waste such as clogging of pore space and chemical incompatibility would have to be solved before a particular sandstone unit could be selected for waste disposal. Several thick sequences of impermeable shale such as those in the Skull Creek, Mowry, Frontier, Belle Fourche, Cody, Lewis, and Pierre Formations, occur in rocks of Cretaceous age in the Basin. Limited storage space for liquid waste might be developed in impermeable shale by fracturing the shale and space for calcined or fused waste could be developed by mining cavities.

Ground-water conditions in the Green Bay area, Wisconsin, 1950-60

USGS Publications Warehouse

Knowles, Doyle B.

1964-01-01

The Green Bay area, which includes parts of Brown, Outagamie, and Shawano Counties, has an area of about 525 square miles in eastern Wisconsin at the south end of Green Bay. In 1960, it had a population estimated at 124,000; Green Bay, the largest city in the area, had a population of 62,888. The Green Bay area is underlain by a basement complex of crystalline rocks of Precambrian age. Sedimentary rocks of Cambrian, Ordovician, and Silurian ages overlie the crystalline rocks. These rocks are divided, in ascending order, as follows: The Dresbach Group, Franconia Sandstone, and Trempealeau Formation of Cambrian age; the Prairie du Chien Group, St. Peter Sandstone, Platteville Formation, and Maquoketa Shale of Ordovician age; and the Niagara Dolomite of Silurian age. The Maquoketa Shale and Niagara Dolomite are present only in the eastern part of the area. Unconsolidated deposits, largely of Pleistocene age and glacial origin, overlie the older rocks in most of the area. The rocks of the Dresbach Group, Franconia Sandstone, Trempealeau Formation, Prairie du Chien Group, and St. Peter Sandstone are connected hydraulically and can be considered to form one aquifer, called the sandstone aquifer. The sandstone aquifer is the principal source of ground-water supply in the Green Bay area and is one of the most productive water-bearing units in Wisconsin. All the public water supplies in the area, except the supply for the city of Green Bay, and many of the industrial water supplies are obtained from wells tapping the sandstone aquifer. Rates of discharge of individual wells range from about 200 to 1,000 gallous per minute. The city of Green Bay also obtained its water supply from wells tapping the sandstone aquifer until August 1957, when it began using Lake Michigan as a source of water supply. Several industries also use large quantities of surface water. The Niagara Dolomite, although largely undeveloped, is potentially an important aquifer, in the eastern part of the area. Small amounts of water are obtained from dolomite of the Platteville Formation and from sand and gravel deposits of Pleistocene age. Recharge to the sandstone aquifer in the Green Bay area is derived chiefly from precipitation that infiltrates at or near the outcrop area of the aquifer in northwestern Brown County, eastern Outagamie and Shawano Counties, and southern Oconto County. The amount of recharge is estimated to be at least 30 mgd (million gallons per day). Withdrawals of water from wells tapping the sandstone aquifer in the area began when the first well was drilled in 1886. The withdrawals gradually increased to an average of about 6 mgd in 1940, about 10 mgd in 1950, and about 13 mgd in January-July of 1957, after which time the city of Green Bay discontinued pumping from wells. From August 1957 through 1960, average annual withdrawals of water remained relatively constant at about 5 mgd. Water levels in wells tapping the sandstone aquifer persistently declined until August 1957 as a result of the gradually increasing withdrawals of water. In the area of concentrated ground-water withdrawals in downtown Green Bay, the piezometric surface, which had been about 100 feet above land surface in 1886, was about 340 feet below land surface in 1957. The cessation of pumping by the city of Green Bay in August 1957 resulted in a decrease in withdrawals of ground water from about 13.1 mgd in the first half of 1957 to about 5.3 mgd in the last half and a rapid recovery in water levels. ]n the area of concentrated withdrawals, the piezometric surface had recovered about 300 feet by September 1960. Rises in water levels were recorded throughout the Green Bay area, with the amount of the rise depending on the distance from the Green Bay city wells. In September 1960, water levels appeared to be affected more by local variations in the rates of pumping than by the recovery resulting from 1957 reduction in pumping. Much additional ground water could

CarbonSAFE Rocky Mountain Phase I : Seismic Characterization of the Navajo Reservoir, Buzzard Bench, Utah

NASA Astrophysics Data System (ADS)

Haar, K. K.; Balch, R. S.; Lee, S. Y.

2017-12-01

The CarbonSAFE Rocky Mountain project team is in the initial phase of investigating the regulatory, financial and technical feasibility of commercial-scale CO2 capture and storage from two coal-fired power plants in the northwest region of the San Rafael Swell, Utah. The reservoir interval is the Jurassic Navajo Sandstone, an eolian dune deposit that at present serves as the salt water disposal reservoir for Ferron Sandstone coal-bed methane production in the Drunkards Wash field and Buzzard Bench area of central Utah. In the study area the Navajo sandstone is approximately 525 feet thick and is at an average depth of about 7000 feet below the surface. If sufficient porosity and permeability exist, reservoir depth and thickness would provide storage for up to 100,000 metric tonnes of CO2 per square mile, based on preliminary estimates. This reservoir has the potential to meet the DOE's requirement of having the ability to store at least 50 million metric tons of CO2 and fulfills the DOE's initiative to develop protocols for commercially sequestering carbon sourced from coal-fired power plants. A successful carbon storage project requires thorough structural and stratigraphic characterization of the reservoir, seal and faults, thereby allowing the creation of a comprehensive geologic model with subsequent simulations to evaluate CO2/brine migration and long-term effects. Target formation lithofacies and subfacies data gathered from outcrop mapping and laboratory analysis of core samples were developed into a geologic model. Synthetic seismic was modeled from this, allowing us to seismically characterize the lithofacies of the target formation. This seismic characterization data was then employed in the interpretation of 2D legacy lines which provided stratigraphic and structural control for more accurate model development of the northwest region of the San Rafael Swell. Developing baseline interpretations such as this are crucial toward long-term carbon storage monitoring.

Understanding creep in sandstone reservoirs - theoretical deformation mechanism maps for pressure solution in granular materials

NASA Astrophysics Data System (ADS)

Hangx, Suzanne; Spiers, Christopher

2014-05-01

Subsurface exploitation of the Earth's natural resources removes the natural system from its chemical and physical equilibrium. As such, groundwater extraction and hydrocarbon production from subsurface reservoirs frequently causes surface subsidence and induces (micro)seismicity. These effects are not only a problem in onshore (e.g. Groningen, the Netherlands) and offshore hydrocarbon fields (e.g. Ekofisk, Norway), but also in urban areas with extensive groundwater pumping (e.g. Venice, Italy). It is known that fluid extraction inevitably leads to (poro)elastic compaction of reservoirs, hence subsidence and occasional fault reactivation, and causes significant technical, economic and ecological impact. However, such effects often exceed what is expected from purely elastic reservoir behaviour and may continue long after exploitation has ceased. This is most likely due to time-dependent compaction, or 'creep deformation', of such reservoirs, driven by the reduction in pore fluid pressure compared with the rock overburden. Given the societal and ecological impact of surface subsidence, as well as the current interest in developing geothermal energy and unconventional gas resources in densely populated areas, there is much need for obtaining better quantitative understanding of creep in sediments to improve the predictability of the impact of geo-energy and groundwater production. The key problem in developing a reliable, quantitative description of the creep behaviour of sediments, such as sands and sandstones, is that the operative deformation mechanisms are poorly known and poorly quantified. While grain-scale brittle fracturing plus intergranular sliding play an important role in the early stages of compaction, these time-independent, brittle-frictional processes give way to compaction creep on longer time-scales. Thermally-activated mass transfer processes, like pressure solution, can cause creep via dissolution of material at stressed grain contacts, grain-boundary diffusion and precipitation on pore walls. As a first step to better describe creep in sands and sandstones, we have derived a simple model for intergranular pressure solution (IPS) within an ordered pack of spherical grains, employing existing IPS rate models, such as those derived by Renard et al. (1999) and Spiers et al. (2004). This universal model is able to predict the conditions under which each of the respective pressure solution serial processes, i.e. diffusion, precipitation or dissolution, is dominant. In essence, this creates generic deformation mechanism maps for any granular material. We have used our model to predict the amount and rate of compaction for sandstone reservoirs, and compared our predictions to known subsidence rates for reservoirs around the world. This gives a first order-comparison to verify whether or not IPS is an important mechanism in controlling reservoir compaction.

3-D reservoir characterization of the House Creek oil field, Powder River Basin, Wyoming

USGS Publications Warehouse

Higley, Debra K.; Pantea, Michael P.; Slatt, Roger M.

1997-01-01

This CD-ROM is intended to serve a broad audience. An important purpose is to explain geologic and geochemical factors that control petroleum production from the House Creek Field. This information may serve as an analog for other marine-ridge sandstone reservoirs. The 3-D slide and movie images are tied to explanations and 2-D geologic and geochemical images to visualize geologic structures in three dimensions, explain the geologic significance of porosity/permeability distribution across the sandstone bodies, and tie this to petroleum production characteristics in the oil field. Movies, text, images including scanning electron photomicrographs (SEM), thin-section photomicrographs, and data files can be copied from the CD-ROM for use in external mapping, statistical, and other applications.

Modeling CO2 distribution in a heterogeneous sandstone reservoir: the Johansen Formation, northern North Sea

NASA Astrophysics Data System (ADS)

Sundal, Anja; Miri, Rohaldin; Petter Nystuen, Johan; Dypvik, Henning; Aagaard, Per

2013-04-01

The last few years there has been broad attention towards finding permanent storage options for CO2. The Norwegian continental margin holds great potential for storage in saline aquifers. Common for many of these reservoir candidates, however, is that geological data are sparse relative to thoroughly mapped hydrocarbon reservoirs in the region. Scenario modeling provides a method for estimating reservoir performances for potential CO2 storage sites and for testing injection strategies. This approach is particularly useful in the evaluation of uncertainties related to reservoir properties and geometry. In this study we have tested the effect of geological heterogeneities in the Johansen Formation, which is a laterally extensive sandstone and saline aquifer at burial depths of 2 - 4 km, proposed as a suitable candidate for CO2 storage by Norwegian authorities. The central parts of the Johansen Formation are underlying the operating hydrocarbon field Troll. In order not to interfere with ongoing gas production, a potential CO2 injection well should be located at a safe distance from the gas reservoir, which consequently implies areas presently without well control. From 3D seismic data, prediction of spatial extent of sandstone is possible to a certain degree, whereas intra-reservoir flow baffles such as draping mudstone beds and calcite cemented layers are below seismic resolution. The number and lateral extent of flow baffles, as well as porosity- and permeability distributions are dependent of sedimentary facies and diagenesis. The interpretation of depositional environment and burial history is thus of crucial importance. A suite of scenario models was established for a potential injection area south of the Troll field. The model grids where made in Petrel based on our interpretations of seismic data, wire line logs, core and cuttings samples. Using Eclipse 300 the distribution of CO2 is modeled for different geological settings; with and without the presence of pervasive low permeability draping mudstone layers, and with varying lateral extent of potential calcite cemented layers in 8 to 15 intra-reservoir depth levels. The modeled area covers 10 x 15.8 km, with a thickness of 110 m at the injection point. Simulations were run with an injection phase of 30 years plus 100 years of migration. The presence of meso-scale flow baffles causes a reduction in vertical permeability in addition to the facies related variation on the micro-scale. Scenarios including potential flow baffles as separate layers in the model grids were compared to scenarios in which the effect of flow baffles were included using harmonic mean average of vertical permeability. The subsequent differences in CO2 distribution are important in estimating the contact area between the plume front and reservoir brine. A heterogeneous reservoir with internal flow baffles is not necessarily a disadvantage as long as sufficient injectivity is maintained within individual sandstone bodies. In each scenario we aim to adapt a suitable injection strategy with respect to utilizing local effects such as the delimitation of gravitational flow, in order to increase reservoir sweep and maximize the effect of trapping mechanisms (i.e. residual, stratigraphic, mineral and dissolution).

Outcrop analogue study of Permocarboniferous geothermal sandstone reservoir formations (northern Upper Rhine Graben, Germany): impact of mineral content, depositional environment and diagenesis on petrophysical properties

NASA Astrophysics Data System (ADS)

Aretz, Achim; Bär, Kristian; Götz, Annette E.; Sass, Ingo

2016-07-01

The Permocarboniferous siliciclastic formations represent the largest hydrothermal reservoir in the northern Upper Rhine Graben in SW Germany and have so far been investigated in large-scale studies only. The Cenozoic Upper Rhine Graben crosses the Permocarboniferous Saar-Nahe Basin, a Variscan intramontane molasse basin. Due to the subsidence in this graben structure, the top of the up to 2-km-thick Permocarboniferous is located at a depth of 600-2900 m and is overlain by Tertiary and Quaternary sediments. At this depth, the reservoir temperatures exceed 150 °C, which are sufficient for geothermal electricity generation with binary power plants. To further assess the potential of this geothermal reservoir, detailed information on thermophysical and hydraulic properties of the different lithostratigraphical units and their depositional environment is essential. Here, we present an integrated study of outcrop analogues and drill core material. In total, 850 outcrop samples were analyzed, measuring porosity, permeability, thermal conductivity and thermal diffusivity. Furthermore, 62 plugs were taken from drillings that encountered or intersected the Permocarboniferous at depths between 1800 and 2900 m. Petrographic analysis of 155 thin sections of outcrop samples and samples taken from reservoir depth was conducted to quantify the mineral composition, sorting and rounding of grains and the kind of cementation. Its influence on porosity, permeability, the degree of compaction and illitization was quantified. Three parameters influencing the reservoir properties of the Permocarboniferous were detected. The strongest and most destructive influence on reservoir quality is related to late diagenetic processes. An illitic and kaolinitic cementation and impregnation of bitumina document CO2- and CH4-rich acidic pore water conditions, which are interpreted as fluids that migrated along a hydraulic contact from an underlying Carboniferous hydrocarbon source rock. Migrating oil and acidic waters led to the dissolution of haematite cements in the lower Permocarboniferous formations. During the Eocene, subsidence of the Upper Rhine Graben porosities and permeabilities of the sandstones of these formations were strongly reduced to 2.5 % and 3.2 × 10-18 m2. The second important influence on reservoir quality is the distinct depositional environment and its influence on early diagenetic processes. In early stage diagenesis, the best influence on reservoir properties exhibits a haematite cementation. It typically occurs in eolian sandstones of the Kreuznach Formation (Upper Permocarboniferous) and is characterized by grain covering haematite coatings, which are interpreted to inhibit cementation, compaction and illitization of pore space during burial. Eolian sandstones taken from outcrops and reservoir depths exhibit the highest porosities (16.4; 12.3 %) and permeabilities (2.0 × 10-15; 8.4 × 10-16 m2). A third important influence on reservoir quality is the general mineral composition and the quartz content which is the highest in the Kreuznach Formation with 73.8 %. Based on the integrated study of depositional environments and diagenetic processes, reservoir properties of the different Permocarboniferous formations within the northern Upper Rhine Graben and their changes with burial depth can be predicted with satisfactory accuracy. This leads to a better understanding of the reservoir quality and enables an appropriate well design for exploration and exploitation of these geothermal resources.

Consolidation of geologic studies of geopressured-geothermal resources in Texas: Barrier-bar tidal-channel reservoir facies architecture, Jackson Group, Prado field, South Texas; Final report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Seni, S.J.; Choh, S.J.

1994-01-01

Sandstone reservoirs in the Jackson barrier/strandplain play are characterized by low recovery efficiencies and thus contain a large hydrocarbon resource target potentially amenable to advanced recovery techniques. Prado field, Jim Hogg County, South Texas, has produced over 23 million bbl of oil and over 32 million mcf gas from combination structural-stratigraphic traps in the Eocene lower Jackson Group. Hydrocarbon entrapment at Prado field is a result of anticlinal nosing by differential compaction and updip pinch-out of barrier bar sandstone. Relative base-level lowering resulted in forced regression that established lower Jackson shoreline sandstones in a relatively distal location in central Jimmore » Hogg County. Reservoir sand bodies at Prado field comprise complex assemblages of barrier-bar, tidal-inlet fill, back-barrier bar, and shoreface environments. Subsequent progradation built the barrier-bar system seaward 1 to 2 mi. Within the barrier-bar system, favorable targets for hydrocarbon reexploration are concentrated in tidal-inlet facies because they possess the greatest degree of depositional heterogeneity. The purpose of this report is (1) to describe and analyze the sand-body architecture, depositional facies variations, and structure of Prado field, (2) to determine controls on distribution of hydrocarbons pertinent to reexploration for bypassed hydrocarbons, (3) to describe reservoir models at Prado field, and (4) to develop new data affecting the suitability of Jackson oil fields as possible candidates for thermally enhanced recovery of medium to heavy oil.« less

Importance of Low Permeability Natural Gas Reservoirs (released in AEO2010)

EIA Publications

2010-01-01

Production from low-permeability reservoirs, including shale gas and tight gas, has become a major source of domestic natural gas supply. In 2008, low-permeability reservoirs accounted for about 40% of natural gas production and about 35% of natural gas consumption in the United States. Permeability is a measure of the rate at which liquids and gases can move through rock. Low-permeability natural gas reservoirs encompass the shale, sandstone, and carbonate formations whose natural permeability is roughly 0.1 millidarcies or below. (Permeability is measured in darcies.)

Gulf of Mexico Oil and Gas Atlas Series: Chronostratigraphically bound reservoir plays in Texas and federal offshore waters

DOE Office of Scientific and Technical Information (OSTI.GOV)

Seni, S.J.; Desselle, B.A.; Standen, A.

1994-09-01

The search for additional hydrocarbons in the Gulf of Mexico is directing exploration toward both deep-water frontier trends and historically productive areas on the shelf. The University of Texas at Austin, Bureau of Economic Geology, in cooperation with the Minerals Management Service, the Gas Research Institute, and the U.S. Department of Energy, is responding to this need through a coordinated research effort to develop an oil and gas atlas series for the offshore northern Gulf of Mexico. The atlas series will group regional trends of oil and gas reservoirs into subregional plays and will display graphical location and reservoir datamore » on a computerized information system. Play methodology includes constructing composite type logs with producing zones for all fields, identifying progradational, aggradational, and retrogradational depositional styles, and displaying geologic data for type fields. Deep-water sand-rich depositional systems are identified separately on the basis of faunal ecozones, chronostratigraphic facies position, and log patterns. To date, 4 Oligocene, 19 Lower Miocene, and 5 Upper Miocene plays have been identified in Texas state offshore waters. Texas state offshore plays are gas prone and are preferentially trapped in rollover anticlines. Lower Miocene plays include deep-water sandstones of Lenticulina hanseni and jeffersonensis; progradational sandstones of Marginulina, Discorbis b, Siphonia davisi, and Lenticulina; transgressive sandstones associated with a barrier-bar system in the Matagorda area; and transgressive sandstones below Amphistegina B shale. Particularly productive gas-prone plays are progradational Siphonia davisi, shelf-margin deltas in the High Island area, and progradational Marginulina shelf and deltaic sands in association with large rollover anticlines in the Matagorda Island and Brazos areas.« less

Origin and heterogeneity of pore sizes in the Mount Simon Sandstone and Eau Claire Formation: Implications for multiphase fluid flow

DOE PAGES

Mozley, Peter S.; Heath, Jason E.; Dewers, Thomas A.; ...

2016-01-01

The Mount Simon Sandstone and Eau Claire Formation represent a principal reservoir - caprock system for wastewater disposal, geologic CO 2 storage, and compressed air energy storage (CAES) in the Midwestern United States. Of primary concern to site performance is heterogeneity in flow properties that could lead to non-ideal injectivity and distribution of injected fluids (e.g., poor sweep efficiency). Using core samples from the Dallas Center Structure, Iowa, we investigate pore structure that governs flow properties of major lithofacies of these formations. Methods include gas porosimetry and permeametry, mercury intrusion porosimetry, thin section petrography, and X-ray diffraction. The lithofacies exhibitmore » highly variable intra- and inter-informational distributions of pore throat and body sizes. Based on pore-throat size, samples fall into four distinct groups. Micropore-throat dominated samples are from the Eau Claire Formation, whereas the macropore-, mesopore-, and uniform-dominated samples are from the Mount Simon Sandstone. Complex paragenesis governs the high degree of pore and pore-throat size heterogeneity, due to an interplay of precipitation, non-uniform compaction, and later dissolution of cements. Furthermore, the cement dissolution event probably accounts for much of the current porosity in the unit. The unusually heterogeneous nature of the pore networks in the Mount Simon Sandstone indicates that there is a greater-than-normal opportunity for reservoir capillary trapping of non-wetting fluids — as quantified by CO 2 and air column heights — which should be taken into account when assessing the potential of the reservoir-caprock system for CO 2 storage and CAES.« less

Anisotropy of permeability of reservoir rocks over Miaoli area, NW Taiwan.

NASA Astrophysics Data System (ADS)

Bo-Siang, Xiong; Loung-Yie, Tsai

2013-04-01

The amount of the CO2 has risen since the Industrial Evolution. In order to reduce the amount of CO2 in atmosphere, CO2 sequestration is considered to be the most effective way. In recent years, research about subsurface storage of CO2 into geological formations has increased rapidly. Assessment of storage capability is needed before selecting a site for sequestration. Porosity and permeability are important assessment factors for CO2 sequestration in reservoir rocks. In order to improve the assessment, reservoir rock properties are important and need to be evaluated in advance. Porosity of sandstone is controlled by texture and degree of cementation, whereas permeability is controlled by pore-throat size, pore types and connectivity of pore throat. Sandstones of Miocene to Pleistocene in Miaoli area, NW Taiwan, were collected in this study. YOKO2 porosity/permeability detector is used to measure their permeability perpendicular and parallel to bedding planes under 3 to 60MPa confining pressure with Helium as media. Optical microscope and scanning electron microscope (SEM) were then used to observe the mineral composition, lithology, texture and pore type of sandstones, so as to explore the influence of rock properties on porosity and anisotropy of permeability, as well as the storage potential for CO2 sequestration in the future. The experimental results show that most of the horizontal permeability exceeds the vertical permeability and the anisotropy increases with increasing confining pressure. Mineral composition of sandstones studied were mainly quartz and lithic with little feldspar content. The pore types were mainly primary pores and micropores in this study. The correlation between quantity of macropores and permeability were higher than total porosity and permeability, mainly due to total porosity contains micropores which contribute little to permeability.

Thermal maturity patterns (conodont color alteration index and vitrinite reflectance) in Upper Ordovician and Devonian rocks of the Appalachian basin: a major revision of USGS Map I-917-E using new subsurface collections: Chapter F.1 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Repetski, John E.; Ryder, Robert T.; Weary, David J.; Harris, Anita G.; Trippi, Michael H.; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

The conodont color alteration index (CAI) introduced by Epstein and others (1977) and Harris and others (1978) is an important criterion for estimating the thermal maturity of Ordovician to Mississippian rocks in the Appalachian basin. Consequently, the CAI isograd maps of Harris and others (1978) are commonly used by geologists to characterize the thermal and burial history of the Appalachian basin and to better understand the origin and distribution of oil and gas resources in the basin. The main objectives of this report are to present revised CAI isograd maps for Ordovician and Devonian rocks in the Appalachian basin and to interpret the geologic and petroleum resource implications of these maps. The CAI isograd maps presented herein complement, and in some areas replace, the CAI-based isograd maps of Harris and others (1978) for the Appalachian basin. The CAI data presented in this report were derived almost entirely from subsurface samples, whereas the CAI data used by Harris and others (1978) were derived almost entirely from outcrop samples. Because of the different sampling methods, there is little geographic overlap of the two data sets. The new data set is mostly from the Allegheny Plateau structural province and most of the data set of Harris and others (1978) is from the Valley and Ridge structural province, east of the Allegheny structural front (fig. 1). Vitrinite reflectance, based on dispersed vitrinite in Devonian black shale, is another important parameter for estimating the thermal maturity in pre-Pennsylvanian-age rocks of the Appalachian basin (Streib, 1981; Cole and others, 1987; Gerlach and Cercone, 1993; Rimmer and others, 1993; Curtis and Faure, 1997). This chapter also presents a revised percent vitrinite reflectance (%R0) isograd map based on dispersed vitrinite recovered from selected Devonian black shales. The Devonian black shales used for the vitrinite studies reported herein also were analyzed by RockEval pyrolysis and total organic carbon (TOC) content in weight percent. Although the RockEval and TOC data are included in this chapter (table 1), they are not shown on the maps. The revised CAI isograd and percent vitrinite reflectance isograd maps cover all or parts of Kentucky, New York, Ohio, Pennsylvania, Virginia, and West Virginia (fig. 1), and the following three stratigraphic intervals: Upper Ordovician carbonate rocks, Lower and Middle Devonian carbonate rocks, and Middle and Upper Devonian black shales. These stratigraphic intervals were chosen for the following reasons: (1) they represent target reservoirs for much of the oil and gas exploration in the Appalachian basin; (2) they are stratigraphically near probable source rocks for most of the oil and gas; (3) they include geologic formations that are nearly continuous across the basin; (4) they contain abundant carbonate grainstone-packstone intervals, which give a reasonable to good probability of recovery of conodont elements from small samples of drill cuttings; and (5) the Middle and Upper Devonian black shale contains large amounts of organic matter for RockEval, TOC, and dispersed vitrinite analyses. Thermal maturity patterns of the Upper Ordovician Trenton Limestone are of particular interest here, because they closely approximate the thermal maturity patterns in the overlying Upper Ordovician Utica Shale, which is the probable source rock for oil and gas in the Upper Cambrian Rose Run Sandstone (sandstone), Upper Cambrian and Lower Ordovician Knox Group (Dolomite), Lower and Middle Ordovician Beekmantown Group (dolomite or Dolomite), Upper Ordovician Trenton and Black River Limestones, and Lower Silurian Clinton/Medina sandstone (Cole and others, 1987; Jenden and others, 1993; Laughrey and Baldassare, 1998; Ryder and others, 1998; Ryder and Zagorski, 2003). The thermal maturity patterns of the Lower Devonian Helderberg Limestone (Group), Middle Devonian Onondaga Limestone, and Middle Devonian Marcellus Shale-Upper Devonian Rhine street Shale Member-Upper Devonian Ohio Shale are of interest, because they closely approximate the thermal maturity patterns in the Marcellus Shale, Upper Devonian Rhinestreet Shale Member, and Upper Devonian Huron Member of the Ohio Shale, which are the most important source rocks for oil and gas in the Appalachian basin (de Witt and Milici, 1989; Klemme and Ulmishek, 1991). The Marcellus, Rhinestreet, and Huron units are black-shale source rocks for oil and (or) gas in the Lower Devonian Oriskany Sandstone, the Upper Devonian sandstones, the Middle and Upper Devonian black shales, and the Upper Devonian-Lower Mississippian(?) Berea Sandstone (Patchen and others, 1992; Roen and Kepferle, 1993; Laughrey and Baldassare, 1998).

Durango delta: Complications on San Juan basin Cretaceous linear strandline theme

DOE Office of Scientific and Technical Information (OSTI.GOV)

Zech, R.S.; Wright, R.

1989-09-01

The Upper Cretaceous Point Lookout Sandstone generally conforms to a predictable cyclic shoreface model in which prograding linear strandline lithosomes dominate formation architecture. Multiple transgressive-regressive cycles results in systematic repetition of lithologies deposited in beach to inner shelf environments. Deposits of approximately five cycles are locally grouped into bundles. Such bundles extend at least 20 km along depositional strike and change from foreshore sandstone to offshore, time-equivalent Mancos mud rock in a downdip distance of 17 to 20 km. Excellent hydrocarbon reservoirs exist where well-sorted shoreface sandstone bundles stack and the formation thickens. This depositional model breaks down in themore » vicinity of Durango, Colorado, where a fluvial-dominated delta front and associated large distributary channels characterize the Point Lookout Sandstone and overlying Menefee Formation.« less

SEQUENCE STRATIGRAPHIC ANALYSIS AND FACIES ARCHITECTURE OF THE CRETACEOUS MANCOS SHALE ON AND NEAR THE JICARILLA APACHE INDIAN RESERVATION, NEW MEXICO-THEIR RELATION TO SITES OF OIL ACCUMULATION

DOE Office of Scientific and Technical Information (OSTI.GOV)

Jennie Ridgley

2000-03-31

Oil distribution in the lower part of the Mancos Shale seems to be mainly controlled by fractures and by sandier facies that are dolomite-cemented. Structure in the area of the Jicarilla Apache Indian Reservation consists of the broad northwest- to southeast-trending Chaco slope, the deep central basin, and the monocline that forms the eastern boundary of the San Juan Basin. Superimposed on the regional structure are broad low-amplitude folds. Fractures seem best developed in the areas of these folds. Using sequence stratigraphic principals, the lower part of the Mancos Shale has been subdivided into four main regressive and transgressive components.more » These include facies that are the basinal time equivalents to the Gallup Sandstone, an overlying interbedded sandstone and shale sequence time equivalent to the transgressive Mulatto Tongue of the Mancos Shale, the El Vado Sandstone Member which is time equivalent to part of the Dalton Sandstone, and an unnamed interbedded sandstone and shale succession time equivalent to the regressive Dalton Sandstone and transgressive Hosta Tongue of the Mesaverde Group. Facies time equivalent to the Gallup Sandstone underlie an unconformity of regional extent. These facies are gradually truncated from south to north across the Reservation. The best potential for additional oil resources in these facies is in the southern part of the Reservation where the top sandier part of these facies is preserved. The overlying unnamed wedge of transgressive rocks produces some oil but is underexplored, except for sandstones equivalent to the Tocito Sandstone. This wedge of rocks is divided into from two to five units. The highest sand content in this wedge occurs where each of the four subdivisions above the Tocito terminates to the south and is overstepped by the next youngest unit. These terminal areas should offer the best targets for future oil exploration. The El Vado Sandstone Member overlies the transgressive wedge. It produces most of the oil (except for the Tocito Sandstone) from the lower Mancos. In the central and southern part of the Reservation, large areas, currently not productive or not tested, have the potential to contain oil in the El Vado simply based on the trend of the facies and structure. There has been little oil or gas production from the overlying regressive-transgressive wedge of rock and much of this interval is untested. Thus, large areas of the Reservation could contain hydrocarbon resources in these strata. Most of the Reservation lies within the oil generation window based on new Rock-Eval data from the Mancos Shale just south of the southern part of the Reservation. If these observations are valid then oil could have been generated locally and would only have needed to migrate short distances in to sandy reservoirs and fractures. This does not rule out long distance migration of oil from the deeper, more thermally mature part of the basin to the north. However, low porosity and permeability characterize sandier rocks in the Mancos, with the exception of Tocito-like sandstones. These factors could retard long distance oil migration through the sediment package, except through fracture or fault conduits. Thus, it is suggested that future oil and gas explorations in the Mancos treat the accumulations and reservoirs as unconventional and consider whether the source and reservoir are in closer proximity than has previously been assumed.« less

An interpretation of core and wireline logs for the Petrophysical evaluation of Upper Shallow Marine sandstone reservoirs of the Bredasdorp Basin, offshore South Africa

NASA Astrophysics Data System (ADS)

Magoba, Moses; Opuwari, Mimonitu

2017-04-01

This paper embodies a study carried out to assess the Petrophysical evaluation of upper shallow marine sandstone reservoir of 10 selected wells in the Bredasdorp basin, offshore, South Africa. The studied wells were selected randomly across the upper shallow marine formation with the purpose of conducting a regional study to assess the difference in reservoir properties across the formation. The data sets used in this study were geophysical wireline logs, Conventional core analysis and geological well completion report. The physical rock properties, for example, lithology, fluid type, and hydrocarbon bearing zone were qualitatively characterized while different parameters such as volume of clay, porosity, permeability, water saturation ,hydrocarbon saturation, storage and flow capacity were quantitatively estimated. The quantitative results were calibrated with the core data. The upper shallow marine reservoirs were penetrated at different depth ranging from shallow depth of about 2442m to 3715m. The average volume of clay, average effective porosity, average water saturation, hydrocarbon saturation and permeability range from 8.6%- 43%, 9%- 16%, 12%- 68% , 32%- 87.8% and 0.093mD -151.8mD respectively. The estimated rock properties indicate a good reservoir quality. Storage and flow capacity results presented a fair to good distribution of hydrocarbon flow.

Integrated geomechanical, petrographical and petrophysical study of the sandstones of the Wajid Group, SW Saudi Arabia

NASA Astrophysics Data System (ADS)

Benaafi, Mohammed; Hariri, Mustafa; Al-Shaibani, Abdulaziz; Abdullatif, Osman; Makkawi, Mohammed

2018-07-01

The Cambro-Permian siliciclastic succession in southwestern Saudi Arabia is represented by the Wajid Group, which consists mainly of fluvial, shallow marine, aeolian, and glacial sandstones. The Wajid Group comprises the Dibsiyah, Sanamah, Qalibah, Khusayyayn, and Juwayl Formations. It is exposed in the Wadi Al-Dawasir area and extends to Najran City. The sandstones of the Wajid Group serve as groundwater aquifers in the Wadi Al-Dawasir and Najran areas and host hydrocarbon (mainly gas) reservoirs in the Rub' Al-Khali Basin. This study aims to characterize the geomechanical properties (rock strength and Young's modulus) of the sandstones of the Wajid Group using field and experimental techniques. A further objective is to investigate the relationships between the geomechanical properties and the petrographical and petrophysical properties of the studied sandstones. The geomechanical properties of the studied sandstones vary from glacial to non-glacial sandstones, as the glacial sandstones display high values of the geomechanical properties with high variability indices. Four geological factors including grain size, cement content, porosity and permeability were observed as the main controls on the geomechanical behaviour of the studied sandstones except for the Khusayyayn sandstone, where the mineral composition was also important. Significant correlations were observed between the petrographical and petrophysical properties and the geomechanical properties of the glacial sandstones. Predictive models of the geomechanical properties (RN, UCS, and E) were generated using regression analysis to account for the glacial sandstones.

Permeability structure of a highly heterogeneous transgressive-marine complex: Tocito Sandstone, New Mexico

DOE Office of Scientific and Technical Information (OSTI.GOV)

Lambert, M.L.; Cole, R.D.

1996-01-01

The Tocito Sandstone Member of the Mancos Shale is an Upper Cretaceous shallow-marine sandstone and mudrock complex deposited along the western margin of the Western Interior seaway. The Tocito is a major hydrocarbon producer in the San Juan Basin (approximately 117 million barrels of oil and 79 billion cubic feet of gas). Because of reservoir heterogeneity, ultimate Tocito oil recovery factors are low, generally between 10 and 20 percent. To enhance understanding of permeability heterogeneity in the Tocito, we have undertaken a detailed surface and subsurface investigation. A total of 2,697 permeability measurements have been made using minipermeameters. Permeability variationmore » within the Tocito is controlled by two principal factors: lithofacies and burial/diagenetic history. Coarser grained and better sorted lithofacies have the highest permeability. The permeability values from outcrop and shallow subsurface cores are dramatically higher than those from deep subsurface cores. This is due to dissolution of grains and calcite cement, and decompaction that preferentially affected the outcrop and shallow subsurface. Correlation lengths for permeability values along horizontal transacts are typically less than 3 m, whereas those for vertical transacts are usually less than 0.6 m. These data suggest that small grid block sizes should be used during reservoir simulations if the investigator wishes to accurately capture the reservoir heterogeneity.« less

Permeability structure of a highly heterogeneous transgressive-marine complex: Tocito Sandstone, New Mexico

DOE Office of Scientific and Technical Information (OSTI.GOV)

Lambert, M.L.; Cole, R.D.

1996-12-31

The Tocito Sandstone Member of the Mancos Shale is an Upper Cretaceous shallow-marine sandstone and mudrock complex deposited along the western margin of the Western Interior seaway. The Tocito is a major hydrocarbon producer in the San Juan Basin (approximately 117 million barrels of oil and 79 billion cubic feet of gas). Because of reservoir heterogeneity, ultimate Tocito oil recovery factors are low, generally between 10 and 20 percent. To enhance understanding of permeability heterogeneity in the Tocito, we have undertaken a detailed surface and subsurface investigation. A total of 2,697 permeability measurements have been made using minipermeameters. Permeability variationmore » within the Tocito is controlled by two principal factors: lithofacies and burial/diagenetic history. Coarser grained and better sorted lithofacies have the highest permeability. The permeability values from outcrop and shallow subsurface cores are dramatically higher than those from deep subsurface cores. This is due to dissolution of grains and calcite cement, and decompaction that preferentially affected the outcrop and shallow subsurface. Correlation lengths for permeability values along horizontal transacts are typically less than 3 m, whereas those for vertical transacts are usually less than 0.6 m. These data suggest that small grid block sizes should be used during reservoir simulations if the investigator wishes to accurately capture the reservoir heterogeneity.« less

Hydrocarbons related to early Cretaceous source rocks, reservoirs and seals, trapped in northeastern Neuqun basin, Argentina

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gulisano, C.; Minniti, S.; Rossi, G.

1996-08-01

The Jurassic-Cretaceous backarc Neuqun Basin, located in the west central part of Argentina, is currently the most prolific oil basin of the country. The primary objective of this study is to evaluate an Early Cretaceous to Tertiary petroleum system in the northeastern portion of the basin, where oil and gas occurrences (e.g., Puesto Hernandez, Chihuido de la Sierra Negra, El Trapial and Filo Morado oil fields, among others) provide 82 MMBO/yr comprising 67% of the basin oil production and 31% of Argentina. The source rocks are represented by two thick sections of basinal kerogen type I and II organic-rich shales,more » deposited during transgressive peaks (Agrio Formation), with TOC content up to 5.1%. Lowstand sandstones bodies, 10 to 100 m thick, are composed of eolian and fluvial facies with good reservoir conditions (Avil and Troncoso Sandstones). The seals are provided by the organic-rich shales resting sharply upon the Avil Sandstone and a widespread Aptian-Albian evaporitic event (Huitrin Formation) on top of the Troncoso reservoir. Tertiary structural traps (duplex anticlines) are developed in the outer foothills, whereas structural, combined and stratigraphic traps are present in the adjacent stable structural platform. Oil-to-source rock and oil-to-oil correlation by chromatographic and biomarker fingerprints, carbon isotopic composition and the geological evidences support the proposed oil system.« less

Characteristics of discrete and basin-centered parts of the Lower Silurian regional oil and gas accumulation, Appalachian basin; preliminary results from a data set of 25 oil and gas fields

USGS Publications Warehouse

Ryder, Robert T.

1998-01-01

Oil and gas trapped in Lower Silurian 'Clinton' sands and Medina Group sandstone constitute a regional hydrocarbon accumulation that extends 425 mi in length from Ontario, Canada to northeastern Kentucky. The 125-mi width of the accumulation extends from central Ohio eastward to western Pennsylvania and west-central New York. Lenticular and intertonguing reservoirs, a gradual eastward decrease in reservoir porosity and permeability, and poorly segregated gas, oil, and water in the reservoirs make it very difficult to recognize clear-cut geologic- and production-based subdivisions in the accumulation that are relevant to resource assessment. However, subtle variations are recognizable that permit the regional accumulation to be subdivided into three tentative parts: a western gas-bearing part having more or less discrete fields; an eastern gas-bearing part having many characteristics of a basin-centered accumulation; and a central oil- and gas-bearing part with 'hybrid' fields that share characteristics of both discrete and basin-centered accumulation. A data set of 25 oil and gas fields is used in the report to compare selected attributes of the three parts of the regional accumulation. A fourth part of the regional accumulation, not discussed here, is an eastern extension of basin-centered accumulation having local commercial gas in the Tuscarora Sandstone, a proximal facies of the Lower Silurian depositional system. A basin-centered gas accumulation is a regionally extensive and commonly very thick zone of gas saturation that occurs in low-permeability rocks in the central, deeper part of a sedimentary basin. Another commonly used term for this type of accumulation is deep-basin gas accumulation. Basin-centered accumulation is a variety of continuous-type accumulation. The 'Clinton' sands and Medina Group sandstone part of the basin-centered gas accumulation is characterized by: a) reservoir porosity ranging from about 5 to 10 percent; b) reservoir permeability equal to or less than 0.1 mD; c) low reservoir water saturation and an average water yield per well less than about 9 to 13 BW/MMCFG; d) a broadly defined updip water-block trap; e) underpressured reservoirs with a gradient ranging from 0.25 to 0.35 psi/ft; and f) reservoir temperature of at least 125? F (52? C). Other than for historical and location purposes, the term field has little or no meaning as an assessment unit for the regional accumulation. In practice, each designated field represents a production sweet spot having relatively high EURs per well that in turn merges with surrounding gas-productive regions that are generally larger in area but have lower EURs per well. This important feature of the Lower Silurian regional accumulation, whereby most wells drilled into it are gas productive, must be considered when assessing its potential for remaining recoverable gas resources. Most of the remaining gas resources reside in 'Clinton' sands and Medina Group sandstone in the basin-centered part of the accumulation where as much as several tens of TCF of natural gas may be technically recoverable. The Tuscarora Sandstone in the eastern extension of the basin-centered part of the accumulation underlies a very large area and, although commonly characterized by very low porosity and permeability and low-Btu gas, probably contains additional gas resources. Remaining undiscovered recoverable gas and oil resources in the discrete and hybrid parts of the accumulation are primarily located beneath Lake Erie.

Petroleum developments in North Africa in 1979

DOE Office of Scientific and Technical Information (OSTI.GOV)

Nicod, M.A.

In the 6 countries covered by this report, the extent of valid petroleum rights, seismic work, and drilling was nearly the same as in 1978. The success rate of wildcat drilling decreased slightly, to 28% (33% in 1978), with 26 oil or gas discoveries. In southwestern Tunisia, the Amoco Sabrina Nord 1 tested 930 bbl of 39/sup 0/ APl oil from Cambrian-Ordovician sandstones - the first oil to come from lower Paleozoic rocks in Tunisia. First commercial oil from Cambrian-Ordovician rocks in western Libya was discovered by Agip A1-NC40 which flowed 1,400 b/d. Highlight of the year in North Africamore » was in the interior basin of Sudan where the Chevron Abu Gabra 1 tested 900 BOPD of 40/sup 0/ APl oil from Cretaceous rocks; 2 other wells, spudded in late 1979 in the same area, have tested 3,200 and 7,300 b/d, respectively, in early 1980. Discovery well of the interior basin was Chevron Unity 1 which tested small amounts of oil in 1978. Oil production in North Africa in 1979 averaged 3,939,500 b/d compared with 3,802,800 b/d in 1978, an increase of 3.6%.« less

Geothermal Data Collection and Interpretation in the State of Alabama: Early Results from the ARRA Geothermal Energy Initiative

NASA Astrophysics Data System (ADS)

Hills, D. J.; Osborne, T. E.; McIntyre, M. R.; Pashin, J. C.

2011-12-01

The Geological Survey of Alabama (GSA) is expanding its efforts to collect, develop, maintain, and analyze statewide geothermal data and to make this information widely and easily accessible to the public through the National Geothermal Data System. The online availability of this data will aid in the effective development of geothermal energy applications and reduce the risks associated with the initial stages of geothermal project development. To this end, the GSA is participating in a collaborative project that the Arizona Geological Survey is coordinating in cooperation with the Association of American State Geologists and with the support of the U.S. Department of Energy as part of the American Reinvestment and Recovery Act. Wells drilled for the exploration and production of hydrocarbons are the primary sources of geothermal data in Alabama. To date, more than 1,200 wells in coalbed methane (CBM) fields in the Black Warrior Basin (BWB) have been examined, in addition to over 500 conventional wells in the basin. Pottsville Formation (Pennsylvanian) bottom-hole temperatures (BHTs) range from less than 80°F to more than 140°F in wells reaching total depth between 1,000 and 6,000 feet (ft). Temperature and depth correlate with a coefficient of determination (r2) of 0.72, reflecting significant variation of the modern geothermal gradient. Mapping and statistical analysis confirm that geothermal gradient in the CBM fairway is typically between 6 and 12°F/1,000 ft. BHTs in the conventional wells penetrating the BWB show even greater variation, with temperature and depth correlating with an r2 of only 0.27. This variability owes to numerous factors, including stratigraphy, lithology, thermal conductivity, and geothermal gradient. Indeed, these wells reach total depth between 500 and 12,000 ft in carbonate and siliciclastic formations ranging in age from Cambrian to Mississippian. The Cambrian section is dominated by low conductivity shale, whereas the Ordovician-Mississippian section contains mainly high-conductivity carbonate. The Upper Mississippian, by contrast, includes complexly interstratified carbonate and siliciclastic rock types with variable thermal conductivity. The Gulf Coast basin of southwest Alabama contains numerous wells penetrating a Mesozoic stratigraphic section that is between 12,000 and 22,000 ft thick. Most wells reach total depth in Jurassic carbonate and sandstone or in Upper Cretaceous sandstone, and the deepest wells have BHTs greater than 400°F. Temperature readings are available at multiple depths for numerous wells, due to multiple log runs. These wells are particularly valuable owing to the availability of data from formations that are not reservoirs. Geothermal gradient is affected by geopressure, which is typically present below 10,000 ft. Gradient is further affected by a thick evaporite section, which can include more than 3,000 ft of salt in the Jurassic section. Thermal data from these wells are invaluable for characterizing petroleum systems and for identifying zones of warm water that can be used as geothermal energy sources.

Implications of Sub-Hydrostatic Pressures in the Bravo Dome Natural CO2 Reservoir for the Long-Term Security of Geological Carbon Dioxide Storage

NASA Astrophysics Data System (ADS)

Akhbari, D.; Hesse, M. A.; Larson, T.

2014-12-01

The Bravo Dome field in northeast New Mexico is one of the largest gas accumulations worldwide and the largest natural CO2 accumulation in North America. The field is only 580-900 m deep and located in the Permian Tubb sandstone that unconformably overlies the granitic basement. Sathaye et al. (2014) estimated that 1.3 Gt of CO2 is stored at the reservoir. A major increase in the pore pressure relative to the hydrostatic pressure is expected due to the large amount of CO2 injected into the reservoir. However, the pre-production gas pressures indicate that most parts of the reservoir are approximately 5 MPa below hydrostatic pressure. Three processes could explain the under pressure in the Bravo Dome reservoir; 1) erosional unloading, 2) CO2 dissolution into the ambient brine, 3) cooling of CO2after injection. Analytical solutions suggest that an erosion rate of 180 m/Ma is required to reduce the pore pressures to the values observed at Bravo Dome. Given that the current erosion rate is only 5 m/Ma (Nereson et al. 2013); the sub-hydrostatic pressures at Bravo Dome are likely due to CO2dissolution and cooling. To investigate the impact of CO2 dissolution on the pore pressure we have developed new analytical solutions and conducted laboratory experiments. We assume that gaseous CO2 was confined to sandstones during emplacement due to the high entry pressure of the siltstones. After emplacement the CO2 dissolves in to the brine contained in the siltstones and the pressure in the sandstones declines. Assuming the sandstone-siltstone system is closed, the pressure decline due to CO2 dissolution is controlled by a single dimensionless number, η = KHRTVw /Vg. Herein, KH is Henry's constant, R is ideal gas constant, T is temperature, Vw is water volume, and Vg is CO2 volume. The pressure drop is controlled by the ratio of water volume to CO2 volume and η varies between 0.1 to 8 at Bravo Dome. This corresponds to pressure drops between 0.8-7.5 MPa and can therefore account for the observed 5 MPa drop in pore pressures at Bravo Dome. This is consistent with geochemical observation suggesting significant dissolution of CO2 at Bravo Dome (Gilfillan 2009). The observation of sub-hydrostatic pressures in CO2 reservoirs is important because they illustrate that CO2 dissolution may mitigate problems due to injection induced overpressure in the long-term.

Stratigraphic comparison of six oil fields (WV) producing from Big Injun sandstones

DOE Office of Scientific and Technical Information (OSTI.GOV)

Zou, X.; Donaldson, A.C.

1993-08-01

Clustered within western West Virginia, six oil fields produce from the lower Mississippian Big Injun sandstones, and three more oil fields also supplement this production either from underlying Squaw or Weir sandstones. Shales separate these sandstones that occur stratigraphically between the Sunbury Shale (maximum flooding surface) and pre-Greenbrier unconformity (maximum regressive erosional surface), and represent highstand regressive deposits associated with the postorogenic phase of foreland basin accumulation. Stratigraphic studies show two Big Injun sandstones. The upper sandstone, called the Maccrady Big Injun, is separated from the lower Price/Pocono Big Injun sandstone by red shales. Both Big Injun sandstones consist ofmore » fine-grained river-mouth bars capped by coarse-grained river-channel deposits. Although the six fields are within three adjacent counties, Maccrady Big Injun sandstones of Blue Creek (Kanawha) and Rock Creek (Roane) fields are younger and were deposited by a different fluvial-deltaic system than the Price/Pocono Big Injun sandstones of Granny Creek (Clay), Tariff (Roane) Clendenin (Clay), and Pond Fork (Kanawha) fields. Upper Weir sandstones are thick, narrow north-trending belts underlying Pond Fork and Blue Creek fields, with properties suggesting wave-dominated shoreline deposits. Allocycles spanning separate drainage systems indicate eustasy. Postorogenic flexural adjustments probably explain stacked sandstone belts with superposed paleovalleys of overlying unconformities (pre-Greenbrier, Pottsville), particularly where aligned along or parallel basement structures of Rome trough or West Virginia dome. Initially, differential subsidence or uplift during sedimentation influenced the position, geometry, trend, and distribution patterns of these reservoir sandstone, then influenced their preserved condition during erosion of pre-Greenbrier unconformity.« less

Permian-triassic paleogeography and stratigraphy of the west Netherlands basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Speksnijder, A.

1993-09-01

During the Permian, the present West Netherlands basin (WNB) was situated at the southernmost margin of the southern Permian basin (SPB). The thickness of Rotilegende sandstones therefore is very much reduced in the WNB. The relatively thin deposits of the Fringe Zechstein in the WNB, however, also contrast strongly in sedimentary facies with thick evaporite/carbonate alternations in the main SPB to the north, although the classic cyclicity of Zechstein deposition still can be recognized. The Fringe Zechstein sediments are mainly siliciclastic and interfinger with both carbonates and anhydrites toward the evaporite basin. End members are thin clay layers that constitutemore » potential seals to underlying Rotliegende reservoirs and relatively thick sandstones (over 100 m net sand) in the western part of the WNB. Nevertheless, favorable reservoir/seal configurations in the Fringe Zechstein seem to be sparse because only minor hydrocarbon occurrences have been proven in the area to date. The situation is dramatically different for the Triassic in the WNB. The [open quotes]Bunter[close quotes] gas play comprises thick Fringe Buntsandstein sandstones (up to 250 m), vertically sealed by carbonates and anhydritic clays of the Muschelkalk and Keuper formations. The Bunter sandstones are largely of the same age as the classic Volpriehausen, Detfurth, and Hardegsen alluvial sand/shale alternations recognized elsewhere, but the upper onlapping transgressive sands and silts correlate with evaporitic clays of the Roet basin to the north. A total volume of 65 x 10[sup 9]m[sup 3] of gas has so far been found in the Triassic Bunter sandstones of the WNB.« less

Heterogeneities of mechanical properties in potential geothermal reservoir rocks of the North German Basin

NASA Astrophysics Data System (ADS)

Reyer, D.; Philipp, S. L.

2012-04-01

Heterogeneous rock properties in terms of layering and complex infrastructure of fault zones are typical phenomena in sedimentary basins such as the North German Basin. To be able to model reservoir stimulation in layered stratifications and to better adapt the drilling strategy to the rock mechanical conditions it is important to have knowledge about the effects of heterogeneous rock properties on fracture propagation and fault zone infrastructure for typical sedimentary reservoir rocks in the North German Basin. Therefore we aim at quantifying these properties by performing structural geological field studies in outcrop analogues combined with laboratory analyses. The field studies in Rotliegend sandstones (Lower Permian), the sandstones of the Middle Bunter (Lower Triassic) and the sandstones of the Upper Keuper (Upper Triassic) focus on 1) host rock fracture systems and 2) fault zone infrastructure. We analyse quantitatively the dimension, geometry, persistence and connectivity of fracture systems separately for host rocks and fault damage zones. The results show that in rocks with distinctive layering (sandstones and shales) natural fractures are often restricted to individual layers, that is, they are stratabound. The probability of fracture arrest seems to depend on the stiffness contrast between the two layers and on the thickness of the softer layer. The field studies are complemented by systematic sampling to obtain mechanical property variations caused by the layering. For the samples we measure the parameters Young's modulus, compressive and tensile strengths, elastic strain energy, density and porosity. The results show that the mechanical properties vary considerably and many samples are clearly anisotropic. That is, samples taken perpendicular to layering commonly have higher strengths but lower stiffnesses than those taken parallel to layering. We combine the results of laboratory analyses and field measurements to specify the mechanical heterogeneities of the sedimentary reservoir rocks of the North German Basin and of the mechanical units of fault zones therein. To estimate the in situ rock properties at different depths it is further important to understand how rocks from outcrops differ from rocks at depth (for example due to alteration and removal of the overburden load). To answer these questions we analyse samples from drill cores from depths relevant for the use as geothermal reservoirs which are stratigraphically and lithologically equivalent to those taken in outcrop analogues. The results from drill-core sample analyses are then compared with the results from the outcrop samples. Another approach is to analyse how rock mechanical properties correlate with petrographic properties (e.g., mineral content, cementation, fabric, porosity) to use this knowledge to extrapolate the data to depth. Altogether these results will be very useful to make better assumptions on natural reservoir permeabilities and to better adapt the drilling and reservoir stimulation strategy to the rock mechanical conditions.

Use of micro-resistivity imaging tools in developing lower Pennsylvanian Morrow channel sandstone reservoirs, Cheyenne, Kiowa and Lincoln Counties, Colorado

DOE Office of Scientific and Technical Information (OSTI.GOV)

Germinario, M.P.

1996-01-01

In southeastern Colorado, Lower Pennsylvanian Morrow channel sandstones are part of complex valley-fill sequences incised into Morrow marine deposits. Morrow valleys are approximately [1/2] to 1 mile wide. Valley-fill consists of floodplain and channel filling shales, very fine-grained estuarine sandstones and fine- to coarse-grained channel sandstones that are up to 50' thick. Channel sandstones represent a sequence of stacked fluvial bars deposited in braided, anastomosing and meandering fluvial environments. Cross-stratification in channel sandstones can be imaged by micro-resistivity wireline logging tools and interpreted interactively on various workstation software packages. Recognition, interpretation and measurement of current, stoss face, and lateral accretionmore » beds in these sandstones can result in an estimated direction of paleocurrent flow of the channel. Determination of the channel's local paleoflow direction can provide significant sand risk reduction in developmental drilling, especially in 80 acre or less spacing patterns. As the distance between offset drilling locations increases, the reliability of paleoflow prediction decreases, and the corresponding sand risk rises. Lateral accretion bedding in Morrow channel sandstones has proven to be a poor indicator of sand thickening direction, due to the complex stacking of multiple channel sandstones within any given valley-fill sequence. Micro-resistivity imaging reduces risk in Morrow channel sandstone development drilling programs. Furthermore, these interpretation techniques could be applicable in other fluvial channel sandstone plays.« less

Use of micro-resistivity imaging tools in developing lower Pennsylvanian Morrow channel sandstone reservoirs, Cheyenne, Kiowa and Lincoln Counties, Colorado

DOE Office of Scientific and Technical Information (OSTI.GOV)

Germinario, M.P.

1996-12-31

In southeastern Colorado, Lower Pennsylvanian Morrow channel sandstones are part of complex valley-fill sequences incised into Morrow marine deposits. Morrow valleys are approximately {1/2} to 1 mile wide. Valley-fill consists of floodplain and channel filling shales, very fine-grained estuarine sandstones and fine- to coarse-grained channel sandstones that are up to 50` thick. Channel sandstones represent a sequence of stacked fluvial bars deposited in braided, anastomosing and meandering fluvial environments. Cross-stratification in channel sandstones can be imaged by micro-resistivity wireline logging tools and interpreted interactively on various workstation software packages. Recognition, interpretation and measurement of current, stoss face, and lateral accretionmore » beds in these sandstones can result in an estimated direction of paleocurrent flow of the channel. Determination of the channel`s local paleoflow direction can provide significant sand risk reduction in developmental drilling, especially in 80 acre or less spacing patterns. As the distance between offset drilling locations increases, the reliability of paleoflow prediction decreases, and the corresponding sand risk rises. Lateral accretion bedding in Morrow channel sandstones has proven to be a poor indicator of sand thickening direction, due to the complex stacking of multiple channel sandstones within any given valley-fill sequence. Micro-resistivity imaging reduces risk in Morrow channel sandstone development drilling programs. Furthermore, these interpretation techniques could be applicable in other fluvial channel sandstone plays.« less

Geology of deep-water sandstones in the Mississippi Stanley Shale at Cossatot Falls, Arkansas

DOE Office of Scientific and Technical Information (OSTI.GOV)

Coleman, J.L. Jr.

1993-09-01

The Mississippian Stanley Shale crops out along the Cossatot River in the Ouachita Mountains of western Arkansas. Here, exposures of deep-water sandstones and shales, on recently established public lands, present a rare, three-dimensional look at sandstones of the usually obscured Stanley. Cossatot Falls, within the Cossatot River State Park Natural Area, is a series of class IV and V rapids developed on massive- to medium-bedded quartz sandstones on the northern flank of an asymmetric, thrust-faulted anticline. In western Arkansas, the Stanley Shale is a 10,000-ft (3200-m) succession of deep-water sandstone and shale. At Cossatot Falls, approximately 50 ft (155 m)more » of submarine-fan-channel sedimentary rocks are exposed during low-river stages. This section is composed primarily of sets of thinning-upward sandstone beds. With rare exceptions, the sandstones are turbidites, grading from massive, homogeneous, basal beds upward through festoon-cross-bedded thick beds, into rippled medium and thin beds. Sandstone sets are capped by thin shales and siltstones. Regional, north-northwestward paleocurrent indicators are substantiated by abundant, generally east-west ripple crests asymmetric to the north-northwest. Flute casts at the top of the sandstone sequence indicate an additional east-ward flow component. Based on regional, lithologic characteristics, the sandstones at Cossatot Falls appear to be within the Moyers Formation. The Moyers is the upper sandstone unit of the Stanley and is an oil and gas reservoir in the eastern Oklahoma Ouachita Mountains.« less

Nd-Sr isotopic and geochemical systematics in Cambrian boninites and tholeiites from Victoria, Australia

NASA Astrophysics Data System (ADS)

Nelson, D. R.; Crawford, A. J.; McCulloch, M. T.

1984-11-01

Rocks with boninitic affinities have been recognised in a number of “ophiolites”, including the Cambrian Heathcote and Mt Wellington Greenstone Belts of Victoria. Boninites and high-Mg andesites from the Heathcote Greenstone Belt show a restricted range of initial ɛ Nd values of between +3.3 to +5.8. Extremely refractory boninites from the Mt Wellington Greenstone Belt have ɛ Nd ranging from +1.3 to -9. Ti/Zr is positively correlated with Sm/Nd with the Heathcote lavas generally possessing greater depletion of Ti and enrichment of Zr relative to the middle and heavy REE with increasing LREE/HREE. These data are consistent with the generation of boninites by partial melting of refractory peridotite following invasion by LREE- and Zr-enriched, low ɛ Nd fluids. Tholeiites overlying the boninites in both greenstone belts have flat REE patterns and ɛ Nd˜+5, lower than that anticipated for lavas derived from depleted MORB source reservoirs in the Cambrian, suggesting that their source was also contaminated by a LREE-enriched, low ɛ Nd component similar to that involved in the generation of the Howqua boninites. The added components have characteristics compatible with their derivation from subducted altered oceanic crust and/or from wet subducted sediments. The identification of boninites and other low-Ti lavas in the Victorian greenstone belts is strong evidence for island arc development in southeastern Australia during the Lower Cambrian and provides further support for a subduction-related origin for many ophiolites.

Simulation of the recharge area for Frederick Springs, Dane County, Wisconsin

USGS Publications Warehouse

Hunt, R.J.; Steuer, J.J.

2000-01-01

Analysis of samples from the springs and a nearby municipal well identified large contrasts in chemistry, even for springs within 50 feet of one another. The differences were stable over time, were present in both ion and isotope analyses, and showed a distinct gradation from high nitrate, high calcium, Ordovician-carbonate dominated water in western spring vents to low nitrate, lower calcium, Cambrian-sandstone influenced water in eastern spring vents. The difference in chemistry was attributed to distinctive bedrock geology as demonstrated by overlaying the 50 percent probability capture zone over a bedrock geology map for the area. This finding gives additional confidence to the capture zone calculated by the ground-water flow model.

Primary Data on U/Pb-Isotope Ages and Lu/Hf-Isotope Geochemical Systematization of Detrital Zircons from the Lopatinskii Formation (Vendian-Cambrian Transition Levels) and the Tectonic Nature of Teya-Chapa Depression (Northeastern Yenisei Ridge)

NASA Astrophysics Data System (ADS)

Kuznetsov, N. B.; Priyatkina, N. S.; Rud'ko, S. V.; Shatsillo, A. V.; Collins, W. J.; Romanyuk, T. V.

2018-03-01

The main results are presented on U/Pb-isotope dating of 100 detrital zircons and, selectively, on the Lu/Hf-isotope system of 43 grains from sandstones of the Lopatinskii formation (the lower stratigraphic level of the Chingasan group). Ages from 896 ± 51 to 2925 ± 38 Ma were obtained with a pronounced maximum of 1890 Ma in the curve of probability density, along with ɛHf estimates from +8.4 to-15.1, which allow one to throw doubt upon the molasse nature of the Lopatinskii formation.

Pore structure characterization of Chang-7 tight sandstone using MICP combined with N2GA techniques and its geological control factors

NASA Astrophysics Data System (ADS)

Cao, Zhe; Liu, Guangdi; Zhan, Hongbin; Li, Chaozheng; You, Yuan; Yang, Chengyu; Jiang, Hang

2016-11-01

Understanding the pore networks of unconventional tight reservoirs such as tight sandstones and shales is crucial for extracting oil/gas from such reservoirs. Mercury injection capillary pressure (MICP) and N2 gas adsorption (N2GA) are performed to evaluate pore structure of Chang-7 tight sandstone. Thin section observation, scanning electron microscope, grain size analysis, mineral composition analysis, and porosity measurement are applied to investigate geological control factors of pore structure. Grain size is positively correlated with detrital mineral content and grain size standard deviation while negatively related to clay content. Detrital mineral content and grain size are positively correlated with porosity, pore throat radius and withdrawal efficiency and negatively related to capillary pressure and pore-to-throat size ratio; while interstitial material is negatively correlated with above mentioned factors. Well sorted sediments with high debris usually possess strong compaction resistance to preserve original pores. Although many inter-crystalline pores are produced in clay minerals, this type of pores is not the most important contributor to porosity. Besides this, pore shape determined by N2GA hysteresis loop is consistent with SEM observation on clay inter-crystalline pores while BJH pore volume is positively related with clay content, suggesting N2GA is suitable for describing clay inter-crystalline pores in tight sandstones.

Pore structure characterization of Chang-7 tight sandstone using MICP combined with N2GA techniques and its geological control factors

PubMed Central

Cao, Zhe; Liu, Guangdi; Zhan, Hongbin; Li, Chaozheng; You, Yuan; Yang, Chengyu; Jiang, Hang

2016-01-01

Understanding the pore networks of unconventional tight reservoirs such as tight sandstones and shales is crucial for extracting oil/gas from such reservoirs. Mercury injection capillary pressure (MICP) and N2 gas adsorption (N2GA) are performed to evaluate pore structure of Chang-7 tight sandstone. Thin section observation, scanning electron microscope, grain size analysis, mineral composition analysis, and porosity measurement are applied to investigate geological control factors of pore structure. Grain size is positively correlated with detrital mineral content and grain size standard deviation while negatively related to clay content. Detrital mineral content and grain size are positively correlated with porosity, pore throat radius and withdrawal efficiency and negatively related to capillary pressure and pore-to-throat size ratio; while interstitial material is negatively correlated with above mentioned factors. Well sorted sediments with high debris usually possess strong compaction resistance to preserve original pores. Although many inter-crystalline pores are produced in clay minerals, this type of pores is not the most important contributor to porosity. Besides this, pore shape determined by N2GA hysteresis loop is consistent with SEM observation on clay inter-crystalline pores while BJH pore volume is positively related with clay content, suggesting N2GA is suitable for describing clay inter-crystalline pores in tight sandstones. PMID:27830731

Sequence Stratigraphic Analysis and Facies Architecture of the Cretaceous Mancos Shale on and Near the Jicarilla Apache Indian Reservation, New Mexico-their relation to Sites of Oil Accumulation

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ridgley, Jennie

2001-08-21

The purpose of phase 1 and phase 2 of the Department of Energy funded project Analysis of oil- bearing Cretaceous Sandstone Hydrocarbon Reservoirs, exclusive of the Dakota Sandstone, on the Jicarilla Apache Indian Reservation, New Mexico was to define the facies of the oil producing units within the Mancos Shale and interpret the depositional environments of these facies within a sequence stratigraphic context. The focus of this report will center on (1) redefinition of the area and vertical extent of the ''Gallup sandstone'' or El Vado Sandstone Member of the Mancos Shale, (2) determination of the facies distribution within themore » ''Gallup sandstone'' and other oil-producing sandstones within the lower Mancos, placing these facies within the overall depositional history of the San Juan Basin, (3) application of the principals of sequence stratigraphy to the depositional units that comprise the Mancos Shale, and (4) evaluation of the structural features on the Reservation as they may control sites of oil accumulation.« less

Carboniferous and older carbonate rocks: Lithofacies, extent, and reservoir quality: Chapter CC in The oil and gas resource potential of the Arctic National Wildlife Refuge 1002 area, Alaska

USGS Publications Warehouse

Dumoulin, Julie A.

1999-01-01

Carboniferous and older carbonate rocks are potential hydrocarbon reservoir facies for four plays in the 1002 area of the Arctic National Wildlife Refuge. These rocks include several units in the pre-Carboniferous basement and the Carboniferous Lisburne Group. Data from exploratory wells west of the 1002 area, outcrops south of the 1002 area, seismic lines, and well logs are synthesized herein to infer carbonate lithofacies, extent, and reservoir character beneath the northeastern Arctic coastal plain.A chiefly shallow-water basement carbonate succession of Late Proterozoic through Early Devonian age (Katakturuk Dolomite, Nanook Limestone, and Mount Copleston Limestone) is interpreted to be present beneath much of the south-central 1002 area; it reaches 3,700 m thick in outcrop and is the primary reservoir for the Deformed Franklinian Play. A more heterogeneous lithologic assemblage of uncertain age forms basement in the northwestern part of the 1002 area; well data define three subunits that contain carbonate intervals 5- 50 m thick. These strata are prospective reservoirs for the Undeformed Franklinian Play and could also be reservoirs for the Niguanak- Aurora Play. Regional lithologic correlations suggest a Cambrian-Late Proterozoic(?) age for subunits one and two, and a slightly younger, later Cambrian-Silurian age for subunit three. Seismic and well data indicate that subunit one overlies subunit two and is overlain by subunit three. The Mississippian and Pennsylvanian Lisburne Group, a predominantly carbonate platform succession as much as 1 km thick, is projected beneath the southernmost part of the 1002 area and is a potential reservoir for the Ellesmerian Thrust-belt and Niguanak-Aurora Plays.Carbonate rocks in the 1002 area probably retain little primary porosity but may have locally well developed secondary porosity. Measured reservoir parameters in basement carbonate strata are low (porosity generally ≤ 5%; permeability ≤ 0.2 md) but drill-stem tests found locally reasonable flow rates (4,220-4,800 bpd) and, in the Flaxman Island area, recovered gas and condensate from these rocks. The Lisburne Group has produced up to 50,000 bbl of oil/ day from the Lisburne field at Prudhoe Bay. Reservoir parameters of the Lisburne in northeastern Alaska range from low (porosities ≤ 5% in most limestones) to good (porosities average 6.5-10% in some dolostones). Reservoir quality in Carboniferous and older carbonate strata in the 1002 area should be greatest where these rocks are highly fractured and (or) truncated by the Lower Cretaceous Unconformity.

Flow unit modeling and fine-scale predicted permeability validation in Atokan sandstones: Norcan East Kansas

USGS Publications Warehouse

Bhattacharya, S.; Byrnes, A.P.; Watney, W.L.; Doveton, J.H.

2008-01-01

Characterizing the reservoir interval into flow units is an effective way to subdivide the net-pay zone into layers for reservoir simulation. Commonly used flow unit identification techniques require a reliable estimate of permeability in the net pay on a foot-by-foot basis. Most of the wells do not have cores, and the literature is replete with different kinds of correlations, transforms, and prediction methods for profiling permeability in pay. However, for robust flow unit determination, predicted permeability at noncored wells requires validation and, if necessary, refinement. This study outlines the use o f a spreadsheet-based permeability validation technique to characterize flow units in wells from the Norcan East field, Clark County, Kansas, that produce from Atokan aged fine- to very fine-grained quartzarenite sandstones interpreted to have been deposited in brackish-water, tidally dominated restricted tidal-flat, tidal-channel, tidal-bar, and estuary bay environments within a small incised-valley-fill system. The methodology outlined enables the identification of fieldwide free-water level and validates and refines predicted permeability at 0.5-ft (0.15-m) intervals by iteratively reconciling differences in water saturation calculated from wire-line log and a capillary-pressure formulation that models fine- to very fine-grained sandstone with diagenetic clay and silt or shale laminae. The effectiveness of this methodology was confirmed by successfully matching primary and secondary production histories using a flow unit-based reservoir model of the Norcan East field without permeability modifications. The methodologies discussed should prove useful for robust flow unit characterization of different kinds of reservoirs. Copyright ?? 2008. The American Association of Petroleum Geologists. All rights reserved.

Frictional Properties of Simulated Fault Gouges from the Seismogenic Groningen Gas Field Under In Situ P-T -Chemical Conditions

NASA Astrophysics Data System (ADS)

Hunfeld, L. B.; Niemeijer, A. R.; Spiers, C. J.

2017-11-01

We investigated the frictional properties of simulated fault gouges derived from the main lithologies present in the seismogenic Groningen gas field (NE Netherlands), employing in situ P-T conditions and varying pore fluid salinity. Direct shear experiments were performed on gouges prepared from the Carboniferous shale/siltstone substrate, the Upper Rotliegend Slochteren sandstone reservoir, the overlying Ten Boer claystone, and the Basal Zechstein anhydrite-carbonate caprock, at 100°C, 40 MPa effective normal stress, and sliding velocities of 0.1-10 μm/s. As pore fluids, we used pure water, 0.5-6.2 M NaCl solutions, and a 6.9 M mixed chloride brine mimicking the formation fluid. Our results show a marked mechanical stratigraphy, with a maximum friction coefficient (μ) of 0.66 for the Basal Zechstein, a minimum of 0.37 for the Ten Boer claystone, 0.6 for the reservoir sandstone, and 0.5 for the Carboniferous. Mixed gouges showed intermediate μ values. Pore fluid salinity had no effect on frictional strength. Most gouges showed velocity-strengthening behavior, with little systematic effect of pore fluid salinity or sliding velocity on (a-b). However, Basal Zechstein gouge showed velocity weakening at low salinities and/or sliding velocities, as did 50:50 mixtures with sandstone gouge, tested with the 6.9 M reservoir brine. From a rate and state friction viewpoint, our results imply that faults incorporating Basal Zechstein anhydrite-carbonate material at the top of the reservoir are the most prone to accelerating slip, that is, have the highest seismogenic potential. The results are equally relevant to other Rotliegend fields in the Netherlands and N. Sea region and to similar sequences globally.

A rock physics and seismic reservoir characterization study of the Rock Springs Uplift, a carbon dioxide sequestration site in Southwestern Wyoming

DOE Office of Scientific and Technical Information (OSTI.GOV)

Grana, Dario; Verma, Sumit; Pafeng, Josiane

We present a reservoir geophysics study, including rock physics modeling and seismic inversion, of a carbon dioxide sequestration site in Southwestern Wyoming, namely the Rock Springs Uplift, and build a petrophysical model for the potential injection reservoirs for carbon dioxide sequestration. Our objectives include the facies classification and the estimation of the spatial model of porosity and permeability for two sequestration targets of interest, the Madison Limestone and the Weber Sandstone. The available dataset includes a complete set of well logs at the location of the borehole available in the area, a set of 110 core samples, and a seismicmore » survey acquired in the area around the well. The proposed study includes a formation evaluation analysis and facies classification at the well location, the calibration of a rock physics model to link petrophysical properties and elastic attributes using well log data and core samples, the elastic inversion of the pre-stack seismic data, and the estimation of the reservoir model of facies, porosity and permeability conditioned by seismic inverted elastic attributes and well log data. In particular, the rock physics relations are facies-dependent and include granular media equations for clean and shaley sandstone, and inclusion models for the dolomitized limestone. The permeability model has been computed by applying a facies-dependent porosity-permeability relation calibrated using core sample measurements. Finally, the study shows that both formations show good storage capabilities. The Madison Limestone includes a homogeneous layer of high-porosity high-permeability dolomite; the Weber Sandstone is characterized by a lower average porosity but the layer is thicker than the Madison Limestone.« less

Lithology and chemical analyses of core and cuttings from USGS drill hole near Gold Acres, Lander County, Nevada

USGS Publications Warehouse

Wrucke, Chester T.

1975-01-01

Upper Paleozoic to Mesozoic eolian blanket sandstones of the Colorado Plateau and the Rocky Mountains of Colorado and southern Wyoming are texturally complex. As petroleum reservoirs they commonly have poor performance histories. They contain the sediments of a depositional system comprised of three closely associated depositional subenvironments: dune, interdune, and extradune. Sediments of each subenvironment have different textural properties which resulted from different depositional processes. Dune sediments are usually more porous and permeable than interdune or extradune sediments and may be better quality reservoirs than interdune or extradune sediments. Interdune sediments are here restricted to those nondune sediments deposited in the relatively flat areas between dunes. Extradune sediments (a new term) include all deposits adjacent to a dune field and are mainly subaqueous deposits. Dune sediments may be enveloped by extradune sediments as the depositional system evolves resulting in a texturally inhomogeneous reservoir having poor fluid migration properties. This model of textural inhomogeneity in eolian blanket sandstones. was applied to the Weber (Tensleep) Sandstone in Brady, Wertz, and Lost Soldier fields, Sweetwater County, Wyoming. Data were obtained from both outcrop and subsurface and included environmental interpretation, textural analysis, and plotting of the distribution of depositional subenvironments. As predicted from the model, the texture of dune sediments in Brady field differed markedly from interdune and extradune sediments. The predicted geometric distribution of subenvironments was confirmed in Lost Soldier and Wertz fields. However, secondary cementation and fracturing there has obscured the original porosity and permeability contrasts. The porosity and permeability distribution, a characteristic depending partly on depositional processes, could impede fluid migration in the reservoir and significantly reduce recovery of hydrocarbons.

A rock physics and seismic reservoir characterization study of the Rock Springs Uplift, a carbon dioxide sequestration site in Southwestern Wyoming

DOE PAGES

Grana, Dario; Verma, Sumit; Pafeng, Josiane; ...

2017-06-20

We present a reservoir geophysics study, including rock physics modeling and seismic inversion, of a carbon dioxide sequestration site in Southwestern Wyoming, namely the Rock Springs Uplift, and build a petrophysical model for the potential injection reservoirs for carbon dioxide sequestration. Our objectives include the facies classification and the estimation of the spatial model of porosity and permeability for two sequestration targets of interest, the Madison Limestone and the Weber Sandstone. The available dataset includes a complete set of well logs at the location of the borehole available in the area, a set of 110 core samples, and a seismicmore » survey acquired in the area around the well. The proposed study includes a formation evaluation analysis and facies classification at the well location, the calibration of a rock physics model to link petrophysical properties and elastic attributes using well log data and core samples, the elastic inversion of the pre-stack seismic data, and the estimation of the reservoir model of facies, porosity and permeability conditioned by seismic inverted elastic attributes and well log data. In particular, the rock physics relations are facies-dependent and include granular media equations for clean and shaley sandstone, and inclusion models for the dolomitized limestone. The permeability model has been computed by applying a facies-dependent porosity-permeability relation calibrated using core sample measurements. Finally, the study shows that both formations show good storage capabilities. The Madison Limestone includes a homogeneous layer of high-porosity high-permeability dolomite; the Weber Sandstone is characterized by a lower average porosity but the layer is thicker than the Madison Limestone.« less

Geologic assessment of undiscovered conventional oil and gas resources in the Lower Paleogene Midway and Wilcox Groups, and the Carrizo Sand of the Claiborne Group, of the Northern Gulf coast region

USGS Publications Warehouse

Warwick, Peter D.

2017-09-27

The U.S. Geological Survey (USGS) recently conducted an assessment of the undiscovered, technically recoverable oil and gas potential of Tertiary strata underlying the onshore areas and State waters of the northern Gulf of Mexico coastal region. The assessment was based on a number of geologic elements including an evaluation of hydrocarbon source rocks, suitable reservoir rocks, and hydrocarbon traps in an Upper Jurassic-Cretaceous-Tertiary Composite Total Petroleum System defined for the region by the USGS. Five conventional assessment units (AUs) were defined for the Midway (Paleocene) and Wilcox (Paleocene-Eocene) Groups, and the Carrizo Sand of the Claiborne Group (Eocene) interval including: (1) the Wilcox Stable Shelf Oil and Gas AU; (2) the Wilcox Expanded Fault Zone Gas and Oil AU; (3) the Wilcox-Lobo Slide Block Gas AU; (4) the Wilcox Slope and Basin Floor Gas AU; and (5) the Wilcox Mississippi Embayment AU (not quantitatively assessed).The USGS assessment of undiscovered oil and gas resources for the Midway-Wilcox-Carrizo interval resulted in estimated mean values of 110 million barrels of oil (MMBO), 36.9 trillion cubic feet of gas (TCFG), and 639 million barrels of natural gas liquids (MMBNGL) in the four assessed units. The undiscovered oil resources are almost evenly divided between fluvial-deltaic sandstone reservoirs within the Wilcox Stable Shelf (54 MMBO) AU and deltaic sandstone reservoirs of the Wilcox Expanded Fault Zone (52 MMBO) AU. Greater than 70 percent of the undiscovered gas and 66 percent of the natural gas liquids (NGL) are estimated to be in deep (13,000 to 30,000 feet), untested distal deltaic and slope sandstone reservoirs within the Wilcox Slope and Basin Floor Gas AU.

Geologic map of the Horse Mountain Quadrangle, Garfield County, Colorado

USGS Publications Warehouse

Perry, W.J.; Shroba, R.R.; Scott, R.B.; Maldonado, Florian

2003-01-01

New 1:24,000-scale geologic map of the Horse Mountain 7.5' quadrangle, in support of the USGS Western Colorado I-70 Corridor Cooperative Geologic Mapping Project, summarizes available geologic information for the quadrangle. It provides new interpretations of the stratigraphy, structure, and geologic hazards in the area of the southwest flank of the White River uplift. Bedrock strata include the Paleocene and early Eocene Wasatch Formation down through Ordovician and Cambrian units into Precambrian hornblende tonalite. The Wasatch Formation includes the Shire, Molina and Atwell Gulch Members which are mapped separately. The underlying Upper Cretaceous Mesaverde Group is subdivided into the Willams Fork and Iles Formations. The Cameo-Fairfield clinker zone within the Williams Fork Formation is mapped separately. The Iles Formation includes the Rollins Sandstone Member at the top, mapped separately, and the Cozzette Sandstone and Corcoran Sandstone Members, which are undivided. The Mancos Shale consists of four members, an upper member, the Niobrara Member, the Juana Lopez Member, and a lower member, undivided. The Lower Cretaceous Dakota Sandstone, the Upper Jurassic Morrison Formation, and Jurassic Entrada Sandstone are mapped separately. The Lower Jurassic and Upper Triassic Glen Canyon Sandstone is mapped with the Entrada in the Horse Mountain Quadrangle. The upper Triassic Chinle Formation and the Lower Permian and Triassic(?) State Bridge Formation are present. The Pennsylvanian and Permian Maroon Formation is undivided. All the exposures of the Middle Pennsylvanian Eagle Valley Evaporite are diapiric, intruded into the Middle Pennsylvanian Eagle Valley Formation, which includes locally mappable limestone beds. The Lower and Middle Pennsylvanian Belden Formation and the Lower Mississippian Leadville Limestone are present. The Upper Devonian Chaffee Group consists of the Dyer Dolomite and the underlying Parting Quartzite, undivided. Locally, the Lower Ordovician Manitou Formation is mapped separately beneath the Chaffee. Elsewhere, Ordovician through Cambrian units, the Manitou and Dotsero Formations, underlain by the Sawatch Quartzite, are undivided. The southwest flank of the White River uplift is a late Laramide structure that is represented by the steeply southwest-dipping Grand Hogback, which is only present in the southwestern corner of the map area, and less steeply southwest-dipping older strata that flatten to nearly horizontal attitudes in the northern part of the map area. Between these two are a complex of normal faults, the largest of which dips southward placing Chafee dolostone and Leadville Limestone adjacent to Eagle Valley and Maroon Formations. Diapiric Eagle Valley Evaporite intruded close to the fault on the down-thrown side. Removal of evaporite by either flow or dissolution from under younger parts of the strata create structural benches, folds, and sink holes on either side of the normal fault. A prominent dipslope of the Morrison-Dakota-Mancos part of the section forms large slide blocks and mass movement deposits consisting of a chaos of admixed Morrison and Dakota lithologies. The major geologic hazard in the area consists of large landslides both associated with dip-slope slide blocks and the steep slopes of the Eagle Valley Formation and Belden Formation in the northern part of the map. Abandoned coal mines are present along the north face of the Grand Hogback in the lower part of the Mesaverde Group

Mechanical changes caused by CO2-driven cement dissolution in the Morrow B Sandstone at reservoir conditions: Experimental observations

NASA Astrophysics Data System (ADS)

Wu, Z.; Luhmann, A. J.; Rinehart, A. J.; Mozley, P.; Dewers, T. A.

2017-12-01

Carbon Capture, Utilization and Storage (CCUS) in transmissive reservoirs is a proposed mechanism in reducing CO2 emissions. Injection of CO2 perturbs reservoir chemistry, and can modify porosity and permeability and alter mineralogy. However, little work has been done on the coupling of rock alteration by CO2 injection and the mechanical integrity of the reservoir. In this study, we perform flow-through experiments on calcite- and dolomite-cemented Pennsylvanian Morrow B Sandstone (West Texas, USA) cores. We hypothesize that poikilotopic calcite cement has a larger impact on chemo-mechanical alteration than disseminated dolomite cement given similar CO2 exposure. With one control brine flow-through experiment and two CO2-plus-brine flow-through experiments for each cement composition, flow rates of 0.1 and 0.01 ml/min were applied under 4200 psi pore fluid pressure and 5000 psi confining pressure at 71 °C. Fluid chemistry and permeability data enable monitoring of mineral dissolution. Ultrasonic velocities were measured pre-test using 1.2 MHz source-receiver pairs at 0.5 MPa axial load and show calcite-cemented samples with higher dynamic elastic moduli than dolomite-cemented samples. Velocities measured post-experiment will identify changes from fluid-rock interaction. We plan to conduct cylinder-splitting destructive mechanical test (Brazil test) to measure the pristine and altered tensile strength of different cemented sandstones. The experiments will identify extents to which cement composition and texture control chemo-mechanical degradation of CCUS reservoirs. Funding for this project is provided by the U.S. Department of Energy's (DOE) National Energy Technology Laboratory (NETL) through the Southwest Regional Partnership on Carbon Sequestration (SWP) under Award No. DE-FC26-05NT42591. Sandia National Laboratories is a multimission laboratory managed and operated by National Technology and Engineering Solutions of Sandia LLC, a wholly owned subsidiary of Honeywell International Inc. for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-NA0003525.

Conversion of crude oil to methane by a microbial consortium enriched from oil reservoir production waters

PubMed Central

Berdugo-Clavijo, Carolina; Gieg, Lisa M.

2014-01-01

The methanogenic biodegradation of crude oil is an important process occurring in petroleum reservoirs and other oil-containing environments such as contaminated aquifers. In this process, syntrophic bacteria degrade hydrocarbon substrates to products such as acetate, and/or H2 and CO2 that are then used by methanogens to produce methane in a thermodynamically dependent manner. We enriched a methanogenic crude oil-degrading consortium from production waters sampled from a low temperature heavy oil reservoir. Alkylsuccinates indicative of fumarate addition to C5 and C6 n-alkanes were identified in the culture (above levels found in controls), corresponding to the detection of an alkyl succinate synthase encoding gene (assA/masA) in the culture. In addition, the enrichment culture was tested for its ability to produce methane from residual oil in a sandstone-packed column system simulating a mature field. Methane production rates of up to 5.8 μmol CH4/g of oil/day were measured in the column system. Amounts of produced methane were in relatively good agreement with hydrocarbon loss showing depletion of more than 50% of saturate and aromatic hydrocarbons. Microbial community analysis revealed that the enrichment culture was dominated by members of the genus Smithella, Methanosaeta, and Methanoculleus. However, a shift in microbial community occurred following incubation of the enrichment in the sandstone columns. Here, Methanobacterium sp. were most abundant, as were bacterial members of the genus Pseudomonas and other known biofilm forming organisms. Our findings show that microorganisms enriched from petroleum reservoir waters can bioconvert crude oil components to methane both planktonically and in sandstone-packed columns as test systems. Further, the results suggest that different organisms may contribute to oil biodegradation within different phases (e.g., planktonic vs. sessile) within a subsurface crude oil reservoir. PMID:24829563

Field aided characterization of a sandstone reservoir: Arroyo Grande Oil Field, California, USA

DOE Office of Scientific and Technical Information (OSTI.GOV)

Antonellini, M.; Aydin, A.

1995-08-01

The Arroyo Grande Oil Field in Central California has been productive since 1905 from the miopliocene Edna member of the Pismo formation. The Edna member is a massive poorly consolidated sandstone unit with an average porosity of 0.2 and a permeability of 1000-5000 md; the producing levels are shallow, 100 to 500 m from the ground surface. Excellent surface exposures of the same formation along road cuts across the field and above the reservoir provide an opportunity to study reservoir rocks at the surface and to relate fracture and permeability distribution obtained from cores to folds and faults observed inmore » outcrops. We mapped in outcrops the major structures of the oil field and determine the statistical distribution and orientation of small faults (deformation bands) that have been observed both in cores and outcrop. The relation between deformation bands and major structures has also been characterized with detailed mapping. By using synthetic logs it is possible to determine the log signature of structural heterogeneities such as deformation bands in sandstone; these faults cause a neutron porosity drop respect to the host rock in the order of 1-4%. Image analysis has been used to determine the petrophysical properties of the sandstone in outcrop and in cores; permeability is three orders of magnitude lower in faults than in the host rock and capillary pressure is 1-2 orders of magnitude larger in faults than in the host rock. Faults with tens of meters offsets are associated with an high density of deformation bands (10 to 250 m{sup -1}) and with zones of cement precipitation up to 30 m from the fault. By combining well and field data, we propose a structural model for the oil field in which high angle reverse faults with localized deformation bands control the distribution of the hydrocarbons on the limb of a syncline, thereby explaining the seemingly unexpected direction of slope of the top surface of the reservoir which was inferred by well data only.« less

Fate of injected CO2 in the Wilcox Group, Louisiana, Gulf Coast Basin: Chemical and isotopic tracers of microbial–brine–rock–CO2 interactions

USGS Publications Warehouse

Shelton, Jenna L.; McIntosh, Jennifer C.; Warwick, Peter D.; Lee Zhi Yi, Amelia

2014-01-01

The “2800’ sandstone” of the Olla oil field is an oil and gas-producing reservoir in a coal-bearing interval of the Paleocene–Eocene Wilcox Group in north-central Louisiana, USA. In the 1980s, this producing unit was flooded with CO2 in an enhanced oil recovery (EOR) project, leaving ∼30% of the injected CO2 in the 2800’ sandstone post-injection. This study utilizes isotopic and geochemical tracers from co-produced natural gas, oil and brine to determine the fate of the injected CO2, including the possibility of enhanced microbial conversion of CO2 to CH4 via methanogenesis. Stable carbon isotopes of CO2, CH4 and DIC, together with mol% CO2 show that 4 out of 17 wells sampled in the 2800’ sandstone are still producing injected CO2. The dominant fate of the injected CO2appears to be dissolution in formation fluids and gas-phase trapping. There is some isotopic and geochemical evidence for enhanced microbial methanogenesis in 2 samples; however, the CO2 spread unevenly throughout the reservoir, and thus cannot explain the elevated indicators for methanogenesis observed across the entire field. Vertical migration out of the target 2800’ sandstone reservoir is also apparent in 3 samples located stratigraphically above the target sand. Reservoirs comparable to the 2800’ sandstone, located along a 90-km transect, were also sampled to investigate regional trends in gas composition, brine chemistry and microbial activity. Microbial methane, likely sourced from biodegradation of organic substrates within the formation, was found in all oil fields sampled, while indicators of methanogenesis (e.g. high alkalinity, δ13C-CO2 and δ13C-DIC values) and oxidation of propane were greatest in the Olla Field, likely due to its more ideal environmental conditions (i.e. suitable range of pH, temperature, salinity, sulfate and iron concentrations).

Experimental study on the CO2-flow mechanism in the two different sandstones

NASA Astrophysics Data System (ADS)

Imasato, M.; Honda, H.; Kitamura, K.

2016-12-01

It is important to discuss the flow properties of CO2 in the reservoir for estimations of storage potential and safety of CCS operation. In this study, we conducted the CO2-injection tests into two different types of porous sandstones with extremely low CO2 flow rate (10µl/min) under supercritical CO2 conditions. It was measured CO2 saturation (SCO2) and differential pressure (ΔP) between upstream and downstream of specimen. It was also monitored P-wave velocity (Vp) and electrical impedance (Z) for the monitoring of CO2 behavior in the specimen. We set three Vp measurement lines in different height for monitoring the movement of CO2 front. The results of ΔP measurement indicated that the Berea sandstone showed no obvious change, but the Ainoura sandstone was increasing gradually and peaked in 73 hours. After that, ΔP of the Ainoura sandstone started reducing. Both sandstones showed stepwise Vp-reduction from the bottom Vp-measurement line, which is near CO2 injection end. There are large differences of CO2 arrival time at the bottom line between Berea and Ainoura sandstone. In case of Ainoura sandstone, it took 29 hours to reduce Vp which is the nearest to CO2 injection end, but in case of Berea sandstone, it took 3.3 hours. This is also confirmed the arrival time at the top channel, 2.5 hours in the Berea sandstone and 11 hours in the Ainoura sandstone. The impedances of both sandstones indicted the gradual increment. It took 25 hours to become constant in the Berea sandstone and 148 hours in the Ainoura sandstone. SCO2 of the Berea sandstone was about 6% and Ainoura sandstone reached over 20%. These results suggest that it is due to the difference of the pore structure of Berea sandstone and Ainoura sandstone.

Stratigraphy and sedimentology of the Cambrian base (La Herrería Formation) in the area of Los Barrios de Luna (N of Spain)

NASA Astrophysics Data System (ADS)

Florez Rodriguez, Adriana Georgina; Aramburu, Carlos; Toyos, Jose Maria

2017-04-01

La Herrería Formation comprises the base of the Cambrian in the Cantabrian Zone (ZC), the external part of the Variscan Orogen in the NW Iberian Peninsula (Spain). In other zones of the Iberian Massif, comparable stratigraphic formations are found overlying the Precambrian basement: La Herrería Formation lays with angular unconformity over the Narcea-Mora Formation. Previous studies have proposed a variety of interpretations for the Herrería Formation. Based on the identified facies and facies associations, in this study it is interpreted in terms of progradation and abandonment of a braidplain delta system, in agreement with some of the previous investigations. Due to its particular location within a foreland fold-and-thrust belt, the formation appears dismembered so that relatively distal sections are currently found displaced towards the NE. Through the analysis of previously investigated and newly identified outcrops, the present study aims to provide a better insight into the features of the sedimentary environment, as well as a detailed characterization of the entire formation, something that would facilitate its mapping in the complexly deformed study area. The study supports a previously proposed subdivision of the Herrería Formation in three informal members, and has identified a 5 m-thick level of fine-grained reddish and mica-rich sandstones proposed as the boundary between the lower and middle members, which has also been utilized as a marker bed for correlations among the different sections. The lower member is formed by shaly to sandy facies associations of pro-delta and delta front, and can include shallow-water carbonates deposited during delta lobe temporal abandonment. Within the middle member, the lower part is composed by coarse- to moderately-sorted feldspathic reddish sandstones of the delta plain, defining the top of a large-scale progradational sequence which starts at the lower member. Towards the upper part of this member, the sandstones turn into quartzarenites with glauconite, reflecting costal reworking by sea waves and then, the beginning of retrogradation. Finally, in the upper member, fine-grained-quarzarenites and shales are found, indicating a stronger marine influence interpreted as a consequence of a retrogradational trend that would culminate with the onset of carbonate deposition as shown by the limestones of the overlying Láncara Formation. Paleocurrent distribution analysis, based on cross-laminated sandstones, indicates that sedimentary supply was directed towards the SSW and that sediment redistribution occurred along a WNW-ESE trending paleoshore. Sedimentation would be linked to one of the graben basins created during the rifting that the northern margin of Gondwana was experiencing at that time.

Deformation Bands in an Exhumed Oil Reservoir, Corona del Mar, California, USA

NASA Astrophysics Data System (ADS)

Sample, J.; Woods, S.; Bender, E.; Loveall, M.

2002-12-01

Deformation bands in coarse-grained sandstones are commonly narrow zones of reduced porosity that restrict migration of fluids. Deformation bands are known from core observations and outcrop studies, but we present for the first time results from an exhumed oil reservoir. The deformation bands occur in a poorly consolidated, oil-bearing sandstone of the Miocene Monterey Formation, within the active, right-slip Newport-Inglewood fault zone (NIFZ). The deformation bands crop out as resistant ribs and fins in a very coarse-grained sandstone comprising mainly quartz and feldspar detritus. Deformation bands strike 323°, similar to the NIFZ, and dip variably (N = 113). There are three clusters of dips within the main set: 88NE, 60NE, and 47SW. A fourth cluster has an orientation of 353 °, 70W. Although the kinematic history is complex, steep bands generally are youngest. Deformation bands exhibit both normal and right-slip separations, but net slip was rarely possible to determine. The deformation bands are closely spaced. They formed by porosity reduction and locally cataclasis. Most deformation bands are oil-free, indicating formation before oil migration, and that they were barriers to flow. There are at least two modes of oil-bearing bands: 1) bands with oil in pore spaces; and 2) bands containing oil in small open pockets, especially lining the edges of bands. Case 1 suggests that porosity reduction did not completely preclude oil penetration or that at least some band formation occurred after oil migration. Case 2 is consistent with reactivation of bands as tensional features, perhaps late in the evolution of the reservoir. Other evidence for late-stage tensional deformation during oil migration includes the presence of young sandstone dikes and bitumen veins up to 7 cm in width lined with euhedral quartz. The relationships observed at Corona del Mar are generally consistent with deformation bands acting as barriers to flow, but clearly deformation bands can be reactivated as fluid conduits. This is probably due to differences in mechanical strength between bands and the surrounding sandstone matrix, focusing tensional failure at deformation band boundaries.

Tidal dunes versus tidal bars: The sedimentological and architectural characteristics of compound dunes in a tidal seaway, the lower Baronia Sandstone (Lower Eocene), Ager Basin, Spain

NASA Astrophysics Data System (ADS)

Olariu, Cornel; Steel, Ronald J.; Dalrymple, Robert W.; Gingras, Murray K.

2012-11-01

The Lower Eocene Baronia Formation in the Ager Basin is interpreted as a series of stacked compound dunes confined within a tectonically generated embayment or tidal seaway. This differs from the previous interpretation of lower Baronia sand bodies as tidal bars in the front of a delta. The key architectural building block of the succession, the deposit of a single compound dune, forms a 1-3 m-thick, upward coarsening succession that begins with highly bioturbated, muddy, very fine to fine grained sandstone that contains an open-marine Cruziana ichnofacies. This is overlain gradationally by ripple-laminated sandstone that is commonly bioturbated and contains mud drapes. The succession is capped by fine- to coarse-grained sandstones that contain both planar and trough cross-strata with unidirectional or bi-directional paleocurrent directions and occasional thin mud drapes on the foresets. The base of a compound dune is gradational where it migrated over muddy sandstone deposited between adjacent dunes, but is sharp and erosional where it migrated over the stoss side of a previous compound dune. The cross strata that formed by simple superimposed dunes dip in the same direction as the inclined master bedding planes within the compound dune, forming a forward-accretion architecture. This configuration is the fundamental reason why these sandbodies are interpreted as compound tidal dunes rather than as tidal bars, which, in contrast, generate lateral-accretion architecture. In the Baronia, fields of compound dunes generated tabular sandbodies 100s to 1000s of meters in extent parallel to the paleocurrent direction and up to 6 m thick that alternate vertically with highly bioturbated muddy sandstones (up to 10 m thick) that represent the low-energy fringes of the dune fields or periods of high sea level when current speeds decreased. Each cross-stratified sandstone sheet (compound-dune complexes) contains overlapping lenticular "shingles" formed by individual compound dunes, separated by 10-30 cm of bioturbated muddy sandstone, which migrated over each other in an offlapping, progradational fashion. Each compound-dune complex (the best reservoir rock) thins as it downlaps, at average rates of 3-4 m/km in a dip direction. These reservoir units can be comprised of discrete compartments, each formed by a single compound dune, that extend for 500-1000 m in the direction of the current, and are at least 350-600 m wide in a flow-transverse direction. Distinguishing between tidal bars and tidal dunes in an ancient tidal succession can be difficult because both can contain similar cross-bedded facies and have overlapping thicknesses; however, the internal architecture and sandbody orientations are different. Tidal bars have their long axis almost parallel both to the tidal current direction and to the strike of the lateral-accretion master surfaces. In inshore areas, they are bounded by channels and fine upward. Large compound tidal dunes, in contrast, have their crest oriented approximately normal to the tidal currents and contain a forward-accretion architecture. Coeval channels are uncommon within large, sub-tidal dune fields. The above distinctions are very important to reservoir description and modeling, because the long axis of the intra-reservoir compartments in the two cases will be 90° apart.

Hydrogeology of the Potsdam Sandstone in northern New York

USGS Publications Warehouse

Williams, John H.; Reynolds, Richard J.; Franzi, David A.; Romanowicz, Edwin A.; Paillet, Frederick L.

2010-01-01

The Potsdam Sandstone of Cambrian age forms a transboundary aquifer that extends across northern New York and into southern Quebec. The Potsdam Sandstone is a gently dipping sequence of arkose, subarkose, and orthoquartzite that unconformably overlies Precambrian metamorphic bedrock. The Potsdam irregularly grades upward over a thickness of 450 m from a heterogeneous feldspathic and argillaceous rock to a homogeneous, quartz-rich and matrix-poor rock. The hydrogeological framework of the Potsdam Sandstone was investigated through an analysis of records from 1,500 wells and geophysical logs from 40 wells, and through compilation of GIS coverages of bedrock and surficial geology, examination of bedrock cores, and construction of hydrogeological sections. The upper several metres of the sandstone typically is weathered and fractured and, where saturated, readily transmits groundwater. Bedding-related fractures in the sandstone commonly form sub-horizontal flow zones of relatively high transmissivity. The vertical distribution of sub-horizontal flow zones is variable; spacings of less than 10 m are common. Transmissivity of individual flow zones may be more than 100 m2/d but typically is less than 10 m2/d. High angle fractures, including joints and faults, locally provide vertical hydraulic connection between flow zones. Hydraulic head gradients in the aquifer commonly are downward; a laterally extensive series of sub-horizontal flow zones serve as drains for the groundwater flow system. Vertical hydraulic head differences between shallow and deep flow zones range from 1 m to more than 20 m. The maximum head differences are in recharge areas upgradient from the area where the Chateauguay and Chazy Rivers, and their tributaries, have cut into till and bedrock. Till overlies the sandstone in much of the study area; its thickness is generally greatest in the western part, where it may exceed 50 m. A discontinuous belt of bedrock pavements stripped of glacial drift extends across the eastern part of the study area; the largest of these is Altona Flat Rock. Most recharge to the sandstone aquifer occurs in areas of thin, discontinuous till and exposed bedrock; little recharge occurs in areas where this unit is overlain by thick till and clay. Discharge from the sandstone aquifer provides stream and river baseflow and is the source of many springs. A series of springs that are used for municipal bottled water and fish-hatchery supply discharge from 1,000 to 5,000 L/min adjacent to several tributaries east of the Chateauguay River. The major recharge areas for the Chateauguay springs are probably upgradient to the southeast, where the till cover is thin or absent.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Balashov, Victor N.; Brantley, Susan L.; Guthrie, George D.

One idea for mitigating the increase in fossil- fuel generated carbon dioxide (CO 2) in the atmosphere is to inject CO 2 into subsurface saline sandstone reservoirs, thereby storing it in those geologic formations and out of the atmosphere.

Implications of heterogeneous fracture distribution on reservoir quality; an analogue from the Torridon Group sandstone, Moine Thrust Belt, NW Scotland

NASA Astrophysics Data System (ADS)

Watkins, Hannah; Healy, David; Bond, Clare E.; Butler, Robert W. H.

2018-03-01

Understanding fracture network variation is fundamental in characterising fractured reservoirs. Simple relationships between fractures, stress and strain are commonly assumed in fold-thrust structures, inferring relatively homogeneous fracture patterns. In reality fractures are more complex, commonly appearing as heterogeneous networks at outcrop. We use the Achnashellach Culmination (NW Scotland) as an outcrop analogue to a folded tight sandstone reservoir in a thrust belt. We present fracture data is collected from four fold-thrust structures to determine how fracture connectivity, orientation, permeability anisotropy and fill vary at different structural positions. We use a 3D model of the field area, constructed using field observations and bedding data, and geomechanically restored using Move software, to determine how factors such as fold curvature and strain influence fracture variation. Fracture patterns in the Torridon Group are consistent and predictable in high strain forelimbs, however in low strain backlimbs fracture patterns are inconsistent. Heterogeneities in fracture connectivity and orientation in low strain regions do not correspond to fluctuations in strain or fold curvature. We infer that where strain is low, other factors such as lithology have a greater control on fracture formation. Despite unpredictable fracture attributes in low strain regions, fractured reservoir quality would be highest here because fractures in high strain forelimbs are infilled with quartz. Heterogeneities in fracture attribute data on fold backlimbs mean that fractured reservoir quality and reservoir potential is difficult to predict.

Burial, thermal, and petroleum generation history of the Upper Cretaceous Steele Member of the Cody Shale (Shannon Sandstone Bed Horizon), Powder River Basin, Wyoming (Chapter A). Bulletin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Nuccio, V.F.

The purposes of the study are to (1) present burial histories representative of the northwestern and southwestern parts of the Powder River Basin (south of lat 45 N.), (2) show the maximum level of thermal maturity for the Steele Member and its Shannon Sandstone Bed, and (3) show the source-rock potential and timing of petroleum generation for the Steele. It is hoped that data presented in the study will also lead to a better understanding of the burial and temperature history of the Shannon Sandstone Bed, an understanding crucial for diagenetic studies, fluid-flow modeling, and reservoir-rock characterization.

Isotopically zoned carbonate cements in Early Paleozoic sandstones of the Illinois Basin: δ18O and δ13C records of burial and fluid flow

NASA Astrophysics Data System (ADS)

Denny, Adam C.; Kozdon, Reinhard; Kitajima, Kouki; Valley, John W.

2017-11-01

SEM/SIMS imaging and analysis of δ18O and δ13C in sandstones from a transect through the Illinois Basin (USA) show systematic μm-scale isotopic zonation of up to 10‰ in both carbonate and quartz cements of the middle-Ordovician St. Peter and Cambrian Mt. Simon formations. Quartz δ18O values are broadly consistent with the model of Hyodo et al. (2014), wherein burial and heating in the Illinois Basin is recorded in systematically zoned quartz overgrowths. Observations of zoned dolomite/ankerite cements indicate that they preserve a more extended record of temperature and fluid compositions than quartz, including early diagenesis before or during shallow burial, and late carbonates formed after quartz overgrowths. Many carbonate cements show innermost dolomite with δ18O values (21-25‰ VSMOW) that are too low to have formed by deposition at low temperatures from ancient seawater (δ18O > - 3‰) and most likely reflect mixing with meteoric water. A sharp increase in Fe content is commonly observed in zoned carbonate cements to be associated with a drop in δ18O and an abrupt shift in δ13C to higher or lower values. These changes are interpreted to record the passage of hot metal-rich brines through sandstone aquifers, that was associated with Mississippi-Valley Type (MVT) Pb-Zn deposits (ca. 270 Ma) of the Upper Mississippi Valley. Local variability and individual trends in δ13C are likely controlled by the sources of carbon and the degree to which carbon is sourced from adjacent carbonate units or thermal maturation of organic matter. Quartz overgrowths in sandstones provide an excellent record of conditions during burial, heating, and pressure-solution, whereas carbonate cements in sandstones preserve a more-extended record including initial pre-burial conditions and punctuated fluid flow events.

Preservation of primary porosity in the Neogene clastic reservoirs of the Surma Basin, Bangladesh

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ferdous, H.S.; Renaut, R.W.

1996-01-01

The Surma Basin is a Tertiary sub-basin within the greater Bengal Basin, in N.E. Bangladesh. The Neogene sequence ([approximately]17 km thick) contains the producing hydrocarbon reservoirs with proven gas reserves. These sediments are alternating coarse and fine clastics, representing a complex interfingering of deltaic and marine subenvironments, with the former dominating. The principal reservoir facies are distributary channel-fill sandstones in a lower delta-plain setting. Kailashtila, Beanibazar and Rashidpur, located in anticlinal structures, are major hydrocarbon-producing fields in the E. Surma Basin. Petrographic analysis shows that primary intergranular porosity mainly controls the reservoir quality of these Neogene sands, which occur atmore » a depth of [approximately]3000 m. Most samples show primary pores with about 20% porosity and permeabilities of about 200 mD. The preservation of a higher proportion of primary pores in fine to medium grained sandstones is a result of (1) moderate compaction resulting from overpressuring caused by a higher rate of subsidence and sedimentation, (2) weak cementation, and (3) a general lack of deleterious clays and the presence of some grain-rimming chlorites. The general absence of long and sutured grain contacts also supports these observations. Some of the existing literature suggests that secondary pores are dominant in the Neogene sandy reservoirs of the Bengal Basin; however, they contribute little ([approximately]2%) to the total porosity in the Surma Basin.« less

Preservation of primary porosity in the Neogene clastic reservoirs of the Surma Basin, Bangladesh

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ferdous, H.S.; Renaut, R.W.

1996-12-31

The Surma Basin is a Tertiary sub-basin within the greater Bengal Basin, in N.E. Bangladesh. The Neogene sequence ({approximately}17 km thick) contains the producing hydrocarbon reservoirs with proven gas reserves. These sediments are alternating coarse and fine clastics, representing a complex interfingering of deltaic and marine subenvironments, with the former dominating. The principal reservoir facies are distributary channel-fill sandstones in a lower delta-plain setting. Kailashtila, Beanibazar and Rashidpur, located in anticlinal structures, are major hydrocarbon-producing fields in the E. Surma Basin. Petrographic analysis shows that primary intergranular porosity mainly controls the reservoir quality of these Neogene sands, which occur atmore » a depth of {approximately}3000 m. Most samples show primary pores with about 20% porosity and permeabilities of about 200 mD. The preservation of a higher proportion of primary pores in fine to medium grained sandstones is a result of (1) moderate compaction resulting from overpressuring caused by a higher rate of subsidence and sedimentation, (2) weak cementation, and (3) a general lack of deleterious clays and the presence of some grain-rimming chlorites. The general absence of long and sutured grain contacts also supports these observations. Some of the existing literature suggests that secondary pores are dominant in the Neogene sandy reservoirs of the Bengal Basin; however, they contribute little ({approximately}2%) to the total porosity in the Surma Basin.« less

Fluvial reservoir architecture in the Malay Basin: Opportunities and challenges

DOE Office of Scientific and Technical Information (OSTI.GOV)

Elias, M.R.; Dharmarajan, K.

1994-07-01

Miocene fluvial sandstones are significant hydrocarbon-bearing reservoirs in the Malay Basin. These include high energy, braided stream deposits of group K, associated with late development of extensional half grabens and relatively lower energy, meandering, and anastomosing channel deposits of group I formed during the subsequent basin sag phase. Group K reservoirs are typically massive, commonly tens of meters thick, and cover an extensive part of the Malay Basin. These reservoirs have good porosity and permeability at shallow burial depths. However, reservoir quality deteriorates rapidly with increasing depth. Lateral and vertical reservoir continuity is generally good within a field, commonly formingmore » a single system. Good water drive enhances recovery. Seismic modeling to determine fluid type and the extent of interfluvial shales is possible due to reservoir homogeneity.« less

Evaluation of input output efficiency of oil field considering undesirable output —A case study of sandstone reservoir in Xinjiang oilfield

NASA Astrophysics Data System (ADS)

Zhang, Shuying; Wu, Xuquan; Li, Deshan; Xu, Yadong; Song, Shulin

2017-06-01

Based on the input and output data of sandstone reservoir in Xinjiang oilfield, the SBM-Undesirable model is used to study the technical efficiency of each block. Results show that: the model of SBM-undesirable to evaluate its efficiency and to avoid defects caused by traditional DEA model radial angle, improve the accuracy of the efficiency evaluation. by analyzing the projection of the oil blocks, we find that each block is in the negative external effects of input redundancy and output deficiency benefit and undesirable output, and there are greater differences in the production efficiency of each block; the way to improve the input-output efficiency of oilfield is to optimize the allocation of resources, reduce the undesirable output and increase the expected output.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Montgomery, S.L.

Recent discovery of natural gas in sandstones of the Jackfork Group of southeastern Oklahoma has led to revised interpretations of hydrocarbon potential in the Ouachita thrust province of eastern Oklahoma. Jackfork reservoirs consist of fine to very fine grained, submarine-fan lobe sandstones with low matrix permeability and porosity. Production is dependent upon natural fractures, enhanced in most cases by artificial stimulation. Individual wells have produced at rates of 1.3-5.7 Mcf per day and possess estimated reserves in the range of 2.0-7.6 Gcf. Hyperbolic decline suggests gas contribution from the matrix, possibly due to the presence of microfractures. Drilling has concentratedmore » on two subsidiary thrust blocks in the hanging wall of the Ti Valley thrust, southern Latimer County. However, recent outcrop, petrographic, and sedimentological analyses have shown that traditional depositional models of the Jackfork are overly limited and that potential Jackfork reservoirs exist across a broad area to the south of the current play. Such analyses have revealed the existence of thick, medium-coarse-grained channel sequences at a number of localities in the Lynn Mountain syncline. Similar sequences may also exist well to the south, in the Boktukola syncline, where thick sand intervals have been identified. Petrographic study of samples from the Lynn Mountain syncline suggests that channel sequences may have significantly higher reservoir quality than is found in productive Jackfork sandstones to the north. Traditional assumptions postulating low regional hydrocarbon potential for the Jackfork therefore stand in need of revision.« less

Proterozoic structure, cambrian rifting, and younger faulting as revealed by a regional seismic reflection network in the Southern Illinois Basin

USGS Publications Warehouse

Potter, C.J.; Drahovzal, James A.; Sargent, M.L.; McBride, J.H.

1997-01-01

Four high-quality seismic reflection profiles through the southern Illinois Basin, totaling 245 km in length, provide an excellent regional subsurface stratigraphic and structural framework for evaluation of seismic risk, hydrocarbon occurrence, and other regional geologic studies. These data provide extensive subsurface information on the geometry of the intersection of the Cambrian Reelfoot and Rough Creek rifts, on extensive Proterozoic reflection sequences, and on structures (including the Fluorspar Area Fault Complex and Hicks Dome) that underlie a transitional area between the well-defined New Madrid seismic zone (to the southwest) and a more diffuse area of seismicity in the southern Illinois Basin. Our principal interpretations from these data are listed here in order of geologic age, from oldest to youngest: 1. Prominent Proterozoic layering, possibly equivalent to Proterozoic (???1 Ga) Middle Run Formation clastic strata and underlying (1.3-1.5 Ga) volcanic rocks of the East Continent rift basin, has been strongly deformed, probably as part of the Grenville foreland fold and thrust belt. 2. A well-defined angular unconformity is seen in many places between Proterozoic and Cambrian strata; a post-Grenville Proterozoic sequence is also apparent locally, directly beneath the base of the Cambrian. 3. We infer a major reversal in Cambrian rift polarity (accommodation zone) in the Rough Creek Graben in western Kentucky. 4. Seismic facies analysis suggests the presence of basin-floor fan complexes at and near the base of the Cambrian interval and within parts of a Proterozoic post-Grenville sequence in several parts of the Rough Creek Graben. 5. There is an abrupt pinchout of the Mount Simon Sandstone against crystalline basement beneath the Dale Dome (near the Texaco no. 1 Cuppy well, Hamilton County) in southeastern Illinois, and a more gradual Mount Simon pinchout to the southeast. 6. Where crossed by the seismic reflection line in southeast Illinois, some faults in the Wabash Valley Fault System produce discrete offset in Ordovician and younger strata only; one of the Wabash Valley faults cuts the top of the Precambrian on this seismic profile. 7. The data show clear evidence of late Paleozoic reverse faulting along both boundaries of the Rough Creek Graben in western Kentucky, although significant unreactivated Cambrian rift-bounding faults are also preserved. 8. Chaotic reflection patterns in the lower and middle Paleozoic strata near Hicks Dome, southern Illinois, are related to a combination of intrusive brecciation, intense faulting, and alteration of carbonate strata by acidic mineralizing fluids, all of which occurred in the Permian. 9. Late Paleozoic(?) reverse faulting is interpreted on one flank of the Rock Creek Graben, southern Illinois. 10. Permian and Mesozoic(?) extensional faulting is clearly imaged in the Fluorspar Area Fault Complex; neotectonic studies suggest that these structures were reactivated in the Quaternary.

South Sumatra Basin Province, Indonesia; the Lahat/Talang Akar-Cenozoic total petroleum system

USGS Publications Warehouse

Bishop, Michele G.

2000-01-01

Oil and gas are produced from the onshore South Sumatra Basin Province. The province consists of Tertiary half-graben basins infilled with carbonate and clastic sedimentary rocks unconformably overlying pre-Tertiary metamorphic and igneous rocks. Eocene through lower Oligocene lacustrine shales and Oligocene through lower Miocene lacustrine and deltaic coaly shales are the mature source rocks. Reserves of 4.3 billion barrels of oil equivalent have been discovered in reservoirs that range from pre-Tertiary basement through upper Miocene sandstones and carbonates deposited as synrift strata and as marine shoreline, deltaic-fluvial, and deep-water strata. Carbonate and sandstone reservoirs produce oil and gas primarily from anticlinal traps of Plio-Pleistocene age. Stratigraphic trapping and faulting are important locally. Production is compartmentalized due to numerous intraformational seals. The regional marine shale seal, deposited by a maximum sea level highstand in early middle Miocene time, was faulted during post-depositional folding allowing migration of hydrocarbons to reservoirs above the seal. The province contains the Lahat/Talang Akar-Cenozoic total petroleum system with one assessment unit, South Sumatra.

Diagenetic history of the Surma Group sandstones (Miocene) in the Surma Basin, Bangladesh

NASA Astrophysics Data System (ADS)

Rahman, M. Julleh Jalalur; McCann, Tom

2012-02-01

This study examines the various diagenetic controls of the Miocene Surma Group sandstones encountered in petroleum exploration wells from the Surma Basin, which is situated in the northeastern part of the Bengal Basin, Bangladesh. The principal diagenetic minerals/cements in the Surma Group sandstones are Fe-carbonates (with Fe-calcite dominating), quartz overgrowths and authigenic clays (predominantly chlorite, illite-smectite and minor kaolin). The isotopic composition of the carbonate cement revealed a narrow range of δ 18O values (-10.3‰ to -12.4‰) and a wide range of δ 13C value (+1.4‰ to -23.1‰). The δ 13C VPDB and δ 18O VPDB values of the carbonate cements reveal that carbon was most likely derived from the thermal maturation of organic matter during burial, as well as from the dissolution of isolated carbonate clasts and precipitated from mixed marine-meteoric pore waters. The relationship between the intergranular volume (IGV) versus cement volume indicates that compaction played a more significant role than cementation in destroying the primary porosity. However, cementation also played a major role in drastically reducing porosity and permeability in sandstones with poikilotopic, pore-filling blocky cements formed in early to intermediate and deep burial areas. In addition to Fe-carbonate cements, various clay minerals including illite-smectite and chlorite occur as pore-filling and pore-lining authigenic phases. Significant secondary porosity has been generated at depths from 2500 m to 4728 m. The best reservoir rocks found at depths of 2500-3300 m are well sorted, relatively coarse grained; more loosely packed and better rounded sandstones having good porosities (20-30%) and high permeabilities (12-6000 mD). These good quality reservoir rocks are, however, not uniformly distributed and can be considered to be compartmentalized as a result of interbedding with sandstone layers of low to moderate porosities, low permeabilities owing to poor sorting and extensive compaction and cementation.

Unraveling the stratigraphy of the Oriskany Sandstone: A necessity in assessing its site-specific carbon sequestration potential

USGS Publications Warehouse

Kostelnik, J.; Carter, K.M.

2009-01-01

The widespread distribution, favorable reservoir characteristics, and depth make the Lower Devonian Oriskany Sandstone a viable sequestration target in the Appalachian Basin. The Oriskany Sandstone is thickest in the structurally complex Ridge and Valley Province, thins toward the northern and western basin margins, and is even absent in other parts of the basin (i.e., the no-sand area of northwestern Pennsylvania). We evaluated four regions using petrographic data, core analyses, and geophysical log analyses. Throughout the entire study area, average porosities range from 1.35 to 14%. The most notable porosity types are primary intergranular, secondary dissolution, and fracture porosity. Intergranular primary porosity dominates at stratigraphic pinch-out zones near the Oriskany no-sand area and at the western limit of the Oriskany Sandstone. Secondary porosity occurs from dissolution of carbonate constituents primarily in the combination-traps natural gas play extending through western Pennsylvania, western West Virginia, and eastern Ohio. Fracture porosity dominates in the central Appalachian Plateau Province and Valley and Ridge Province. Based on average porosity, the most likely regions for successful sequestration in the Oriskany interval are (1) updip from Oriskany Sandstone pinch-outs in eastern Ohio, and (2) western Pennsylvania, western West Virginia, and eastern Ohio where production occurs from a combination of stratigraphic and structural traps. Permeability data, where available, were used to further evaluate the potential of these regions. Permeability ranges from 0.2 to 42.7 md. Stratigraphic pinch-outs at the northern and western limits of the basin have the highest permeabilities. We recommend detailed site assessments when evaluating the sequestration potential of a given injection site based on the variability observed in the Oriskany structure, lithology, and reservoir characteristics. ?? 2009. The American Association of Petroleum Geologists/Division of Environmental Ceosciences. All rights reserved.

Valley-fill sequences and onlap geometries, Lower Cretaceous Muddy Sandstone, Kitty Field, Powder River basin, Wyoming

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gardner, M.H.; Gustason, E.R.

1987-05-01

The Muddy Sandstone at Kitty field is a valley-fill sequence that records a late Albian sea level rise and accompanying transgression. The valley was cut during a preceding sea level lowstand. Stratal geometries and facies successions within the valley fill demonstrate the history of transgression was not gradual and progressive. Rather, the valley fill comprises a series of discrete, time-bounded, depositional units which onlap the erosional surface. Five time-bounded depositional units were defined by facies successions and were used to define onlap geometries. Facies successions within individual units record progressive shoaling. Capping each succession, there may be a planar disconformity,more » a thin bioturbated interval, or the deepest water facies of the next depositional event. Thus, the termination of each depositional event is marked by an episode of rapid deepening. At a single geographic location, stratal successions within older depositional units represent more landward facies than those within younger units. Therefore, the onlap geometry of the valley-fill sequence consists of a landward-stepping arrangement of depositional units. The primary reservoirs within the valley-fill sequence, at Kitty field, are laterally coalesced, channel-belt sandstones at the base and barrier island sandstones at the top. Reservoir sandstones of lesser quality occur within the intermediate estuarine facies. The stacking pattern, developed by onlap of the units, results in multiple pay zones within mid-valley reaches. The boundaries of each depositional unit define a high-resolution, chronostratigraphic correlation of valley-fill strata, a correlation corroborated by bentonites. This correlation method gives an accurate description of the internal geometry of valley-fill strata and, therefore, provides a basis for understanding the process of transgressive onlap.« less

Single well productivity prediction of carbonate reservoir

NASA Astrophysics Data System (ADS)

Le, Xu

2018-06-01

It is very important to predict the single-well productivity for the development of oilfields. The fracture structure of carbonate fractured-cavity reservoirs is complex, and the change of single-well productivity is inconsistent with that of sandstone reservoir. Therefore, the establishment of carbonate oil well productivity It is very important. Based on reservoir reality, three different methods for predicting the productivity of carbonate reservoirs have been established based on different types of reservoirs. (1) To qualitatively analyze the single-well capacity relations corresponding to different reservoir types, predict the production capacity according to the different wells encountered by single well; (2) Predict the productivity of carbonate reservoir wells by using numerical simulation technology; (3) According to the historical production data of oil well, fit the relevant capacity formula and make single-well productivity prediction; (4) Predict the production capacity by using oil well productivity formula of carbonate reservoir.

Gravity and magnetic data in the vicinity of Virgin Valley, southern Nevada

USGS Publications Warehouse

Morin, Robert L.

2006-01-01

This report contains 10 interpretive cross sections and an integrated text describing the geology of parts of the Colorado, White River, and Death Valley regional ground-water flow systems, Nevada, Utah, and Arizona. The primary purpose of the report is to provide geologic framework data for input into a numerical ground-water model. Therefore, the stratigraphic and structural summaries are written in a hydrogeologic context. The oldest rocks (basement) are Early Proterozoic metamorphic and intrusive crystalline rocks that are considered confining units because of their low permeability. Late Proterozoic to Lower Cambrian clastic units overlie the crystalline rocks and are also considered confining units within the regional flow systems. Above the clastic units are Middle Cambrian to Lower Permian carbonate rocks that are the primary aquifers in the flow systems. The Middle Cambrian to Lower Permian carbonate rocks are overlain by a sequence of mainly clastic rocks of late Paleozoic to Mesozoic age that are mostly considered confining units, but they may be permeable where faulted. Tertiary volcanic and plutonic rocks are exposed in the northern and southern parts of the study area. In the Clover and Delamar Mountains, these rocks are highly deformed by north- and northwest-striking normal and strike-slip faults that are probably important conduits in transmitting ground water from the basins in the northern Colorado and White River flow systems to basins in the southern part of the flow systems. The youngest rocks in the region are Tertiary to Quaternary basin-fill deposits. These rocks consist of middle to late Tertiary sediments consisting of limestone, conglomerate, sandstone, tuff, and gypsum, and younger Quaternary surficial units consisting of alluvium, colluvium, playa deposits, and eolian deposits. Basin-fill deposits are both aquifers and aquitards.

Oligo-Miocene reservoir sequence characterization and structuring in the Sisseb El Alem-Kalaa Kebira regions (Northeastern Tunisia)

NASA Astrophysics Data System (ADS)

Houatmia, Faten; Khomsi, Sami; Bédir, Mourad

2015-11-01

The Sisseb El Alem-Enfidha basin is located in the northeastern Tunisia, It is borded by Nadhour - Saouaf syncline to the north, Kairouan plain to the south, the Mediterranean Sea to the east and Tunisian Atlassic "dorsale" to the west. Oligocene and Miocene deltaic deposits present the main potential deep aquifers in this basin with high porosity (25%-30%). The interpretation of twenty seismic reflection profiles, calibrated by wire line logging data of twelve oil wells, hydraulic wells and geologic field sections highlighted the impact of tectonics on the structuring geometry of Oligo-Miocene sandstones reservoirs and their distribution in raised structures and subsurface depressions. Miocene seismostratigraphy analysis from Ain Ghrab Formation (Langhian) to the Segui Formation (Quaternary) showed five third-order seismic sequence deposits and nine extended lenticular sandy bodies reservoirs limited by toplap and downlap surfaces unconformities, Oligocene deposits presented also five third- order seismic sequences with five extended lenticular sandy bodies reservoirs. The Depth and the thickness maps of these sequence reservoir packages exhibited the structuring of this basin in sub-basins characterized by important lateral and vertical geometric and thichness variations. Petroleum wells wire line logging correlation with clay volume calculation showed an heterogeneous multilayer reservoirs of Oligocene and Miocene formed by the arrangement of fourteen sandstone bodies being able to be good reservoirs, separated by impermeable clay packages and affected by faults. Reservoirs levels correspond mainly to the lower system tract (LST) of sequences. Intensive fracturing by deep seated faults bounding the different sub-basins play a great role for water surface recharge and inter-layer circulations between affected reservoirs. The total pore volume of the Oligo-Miocene reservoir sandy bodies in the study area, is estimated to about 4 × 1012 m3 and equivalent to 4 × 109 m3 of deep water reserves.

Reservoir studies with geostatistics to forecast performance

DOE Office of Scientific and Technical Information (OSTI.GOV)

Tang, R.W.; Behrens, R.A.; Emanuel, A.S.

1991-05-01

In this paper example geostatistics and streamtube applications are presented for waterflood and CO{sub 2} flood in two low-permeability sandstone reservoirs. Thy hybrid approach of combining fine vertical resolution in cross-sectional models with streamtubes resulted in models that showed water channeling and provided realistic performance estimates. Results indicate that the combination of detailed geostatistical cross sections and fine-grid streamtube models offers a systematic approach for realistic performance forecasts.

Sedimentary petrology and reservoir quality of the Middle Jurassic Red Glacier Formation, Cook Inlet forearc basin: Initial impressions

USGS Publications Warehouse

Helmold, K.P.; LePain, D.L.; Stanley, Richard G.

2016-01-01

The Division of Geological & Geophysical Surveys and Division of Oil & Gas are currently conducting a study of the hydrocarbon potential of Cook Inlet forearc basin (Gillis, 2013, 2014; LePain and others, 2013; Wartes, 2015; Herriott, 2016 [this volume]). The Middle Jurassic Tuxedni Group is recognized as a major source of oil in Tertiary reservoirs (Magoon, 1994), although the potential for Tuxedni reservoirs remains largely unknown. As part of this program, five days of the 2015 field season were spent examining outcrops, largely sandstones, of the Middle Jurassic Red Glacier Formation (Tuxedni Group) approximately 6.4 km northeast of Johnson Glacier on the western side of Cook Inlet (fig. 4-1). Three stratigraphic sections (fig. 4-2) totaling approximately 307 m in thickness were measured and described in detail (LePain and others, 2016 [this volume]). Samples were collected for a variety of analyses including palynology, Rock-Eval pyrolysis, vitrinite reflectance, detrital zircon geochronology, and petrology. This report summarizes our initial impressions of the petrology and reservoir quality of sandstones encountered in these measured sections. Interpretations are based largely on hand-lens observations of hand specimens and are augmented by stereomicroscope observations. Detailed petrographic (point-count) analyses and measurement of petrophysical properties (porosity, permeability, and grain density) are currently in progress.

Real-time detection of dielectric anisotropy or isotropy in unconventional oil-gas reservoir rocks supported by the oblique-incidence reflectivity difference technique

NASA Astrophysics Data System (ADS)

Zhan, Honglei; Wang, Jin; Zhao, Kun; Lű, Huibin; Jin, Kuijuan; He, Liping; Yang, Guozhen; Xiao, Lizhi

2016-12-01

Current geological extraction theory and techniques are very limited to adequately characterize the unconventional oil-gas reservoirs because of the considerable complexity of the geological structures. Optical measurement has the advantages of non-interference with the earth magnetic fields, and is often useful in detecting various physical properties. One key parameter that can be detected using optical methods is the dielectric permittivity, which reflects the mineral and organic properties. Here we reported an oblique-incidence reflectivity difference (OIRD) technique that is sensitive to the dielectric and surface properties and can be applied to characterization of reservoir rocks, such as shale and sandstone core samples extracted from subsurface. The layered distribution of the dielectric properties in shales and the uniform distribution in sandstones are clearly identified using the OIRD signals. In shales, the micro-cracks and particle orientation result in directional changes of the dielectric and surface properties, and thus, the isotropy and anisotropy of the rock can be characterized by OIRD. As the dielectric and surface properties are closely related to the hydrocarbon-bearing features in oil-gas reservoirs, we believe that the precise measurement carried with OIRD can help in improving the recovery efficiency in well-drilling process.

Real-time detection of dielectric anisotropy or isotropy in unconventional oil-gas reservoir rocks supported by the oblique-incidence reflectivity difference technique

PubMed Central

Zhan, Honglei; Wang, Jin; Zhao, Kun; Lű, Huibin; Jin, Kuijuan; He, Liping; Yang, Guozhen; Xiao, Lizhi

2016-01-01

Current geological extraction theory and techniques are very limited to adequately characterize the unconventional oil-gas reservoirs because of the considerable complexity of the geological structures. Optical measurement has the advantages of non-interference with the earth magnetic fields, and is often useful in detecting various physical properties. One key parameter that can be detected using optical methods is the dielectric permittivity, which reflects the mineral and organic properties. Here we reported an oblique-incidence reflectivity difference (OIRD) technique that is sensitive to the dielectric and surface properties and can be applied to characterization of reservoir rocks, such as shale and sandstone core samples extracted from subsurface. The layered distribution of the dielectric properties in shales and the uniform distribution in sandstones are clearly identified using the OIRD signals. In shales, the micro-cracks and particle orientation result in directional changes of the dielectric and surface properties, and thus, the isotropy and anisotropy of the rock can be characterized by OIRD. As the dielectric and surface properties are closely related to the hydrocarbon-bearing features in oil-gas reservoirs, we believe that the precise measurement carried with OIRD can help in improving the recovery efficiency in well-drilling process. PMID:27976746

New exploration targets in Malaysia: Deep sandstone reservoirs in Malay basin and turbidites in Sabah basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ngah, K.B.

1996-12-31

Much of the production in Malaysia is from middle to upper Miocene sandstones and carbonates in three main basins: Malay, Sarawak (Its three subbasins-Central Luconia, Balingian and Baram), and Sabah. Fifteen fields produce an average of 630,000 bopd and 3.0 bcfgpd. More than 4.0 billion barrels of oil and 20 tcf of gas have been produced, and reserves are 4.2 billion barrels of oil and 90 tcf. Oil production will decline within the next 1 0 years unless new discoveries are made and/or improved oil recovery methods introduced, but gas production of 5 tcf, expected after the turn of themore » century, can be sustained for several decades. Successful exploratory wells continue to be drilled in the Malaysian Tertiary basins, and others are anticipated with application of new ideas and technology. In the Malay basin, Miocene sandstone reservoirs in Groups L and M have been considered as very {open_quote}high risk{close_quotes} targets, the quality of the reservoirs has generally been thought to be poor, especially toward the basinal center, where they occur at greater depth. The cause of porosity loss is primarily burial-related. Because of this factor and overpressuring, drilling of many exploration wells has been suspended at or near the top of Group L. In a recent prospect drilled near the basinal axis on the basis of advanced seismic technology, Groups L and M sandstones show fair porosity (8-15%) and contain gas. In the Sabah basin, turbidite play has received little attention, partly because of generally poor seismic resolution in a very complex structural setting. Only one field is known to produce oil from middle Miocene turbidities. However, using recently acquired 3-D seismic data over this field, new oil pools have been discovered, and they are currently being developed. These finds have created new interest, as has Shell`s recent major gas discovery from a turbidite play in this basin.« less

New exploration targets in Malaysia: Deep sandstone reservoirs in Malay basin and turbidites in Sabah basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ngah, K.B.

1996-01-01

Much of the production in Malaysia is from middle to upper Miocene sandstones and carbonates in three main basins: Malay, Sarawak (Its three subbasins-Central Luconia, Balingian and Baram), and Sabah. Fifteen fields produce an average of 630,000 bopd and 3.0 bcfgpd. More than 4.0 billion barrels of oil and 20 tcf of gas have been produced, and reserves are 4.2 billion barrels of oil and 90 tcf. Oil production will decline within the next 1 0 years unless new discoveries are made and/or improved oil recovery methods introduced, but gas production of 5 tcf, expected after the turn of themore » century, can be sustained for several decades. Successful exploratory wells continue to be drilled in the Malaysian Tertiary basins, and others are anticipated with application of new ideas and technology. In the Malay basin, Miocene sandstone reservoirs in Groups L and M have been considered as very [open quote]high risk[close quotes] targets, the quality of the reservoirs has generally been thought to be poor, especially toward the basinal center, where they occur at greater depth. The cause of porosity loss is primarily burial-related. Because of this factor and overpressuring, drilling of many exploration wells has been suspended at or near the top of Group L. In a recent prospect drilled near the basinal axis on the basis of advanced seismic technology, Groups L and M sandstones show fair porosity (8-15%) and contain gas. In the Sabah basin, turbidite play has received little attention, partly because of generally poor seismic resolution in a very complex structural setting. Only one field is known to produce oil from middle Miocene turbidities. However, using recently acquired 3-D seismic data over this field, new oil pools have been discovered, and they are currently being developed. These finds have created new interest, as has Shell's recent major gas discovery from a turbidite play in this basin.« less

Citronelle Dome: A giant opportunity for multizone carbon storage and enhanced oil recovery in the Mississippi Interior Salt Basin of Alabama

USGS Publications Warehouse

Esposito, R.A.; Pashin, J.C.; Walsh, P.M.

2008-01-01

The Citronelle Dome is a giant, salt-cored anticline in the eastern Mississippi Interior Salt Basin of southern Alabama that is located near several large-scale, stationary, carbon-emitting sources in the greater Mobile area. The dome forms an elliptical, four-way structural closure containing opportunities for CO2-enhanced oil recovery (CO2-EOR) and large-capacity saline reservoir CO2 sequestration. The Citronelle oil field, located on the crest of the dome, has produced more than 169 million bbl of 42-46?? API gravity oil from sandstone bodies in the Lower Cretaceous Rodessa Formation. The top seal for the oil accumulation is a thick succession of shale and anhydrite, and the reservoir is underfilled such that oil-water contacts are typically elevated 30-60 m (100-200 ft) above the structural spill point. Approximately 31-34% of the original oil in place has been recovered by primary and secondary methods, and CO2-EOR has the potential to increase reserves by up to 20%. Structural contour maps of the dome demonstrate that the area of structural closure increases upward in section. Sandstone units providing prospective carbon sinks include the Massive and Pilot sands of the lower Tuscaloosa Group, as well as several sandstone units in the upper Tuscaloosa Group and the Eutaw Formation. Many of these sandstone units are characterized by high porosity and permeability with low heterogeneity. The Tuscaloosa-Eutaw interval is capped by up to 610 m (2000 ft) of chalk and marine shale that are proven reservoir seals in nearby oil fields. Therefore, the Citronelle Dome can be considered a major geologic sink where CO2 can be safely stored while realizing the economic benefits associated with CO2-EOR. Copyright ?? 2008. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Reconnaissance geology of the Wadi Wassat quadrangle, Kingdom of Saudi Arabia

USGS Publications Warehouse

Overstreet, William C.; Rossman, D.L.

1970-01-01

The Wadi Wassat quadrangle covers an area of 2926 sq km in the southwestern part of the Kingdom of Saudi Arabia. The west half of the quadrangle is underlain by crystalline rocks of the Arabian Shield, but in the eastern half of the quadrangle the Precambrian rocks are covered by Permian or older sandstone which is succeeded farther east by aeolian sands of Ar Rub' al Khali. The Shield consists of a sequence of unmetamorphosed to metamorphosed interlayered volcanic and sedimentary rocks intruded by igneous rocks ranging in composition from gabbro to syenite and in age from Precambrian to Cambrian(?). The volcanic rocks range in composition from andesite to rhyolite and in texture from agglomerate to thick, massive flows and lithic tuff. They are interlayered with conglomerate, fine-grained graywacke sandstone, calcareous graywacke, siltstone, tuffaceous laminated shale, pyritiferous sediment, carbonaceous shale, limestone, and dolomite. Most clastic debris is derived from andesite. In places the rocks are polymetamorphosed; elsewhere they are unmetamorphosed. The rocks on which this volcano-sedimentary eugeosynclinal sequence was deposited are not exposed in the area of the quadrangle. Reglonal dynamothermal metamorphism was .the dominant process affecting the volcanic-sedimentary rocks in the western part of the quadrangle. In the eastern part of the Precambrian area the chief metamorphic effect results from contact action along the walls of intrusive plutons. The oldest igneous rock to intrude the volcanic-sedimentary sequence, after the dikes and sills of the sequence itself, is granite gneiss and gneissic granodiorite. The gneiss is sparsely present in the quadrangle, but northwest of the quadrangle it forms an immense batholith which is one of the major geologic features of southwestern Arabia. However, the most common intrusive rocks of the quadrangle are a magnetic differentiation sequence that ranges in composition from gabbro and diorite to granite, rhyolite, and syenite. The siliceous members of the differentiation sequence commonly contain aluminous pyroxene or amphibole, and to the sequence the name peralkalic magma series has been given. Plutonic rocks of the series are widely intruded by hypabyssal rocks of the series. In most places, the older hypabyssal rocks tend to form interior dikes in the plutonic rocks, and the younger hypabyssal rocks commonly form the exterior dike swarms outside the plutonic rocks of the magma series. Many exterior dike swarms are concentrated in roof pendants of volcano-sedimentary rocks over the plutonic members of the magma series. Isotopic ages of rocks in the peralkalic magma series range from 598 +/-24 m.y. to 509 +/-15 m.y. by K/Ar and Rb/Sr methods. A profound angular unconformity exists between the Precambrian and Cambrian(?) crystalline rocks and the Permian or older sandstone which laps onto the Shield from the east and south. This sandstone, is reddish-brown, yellow, tan, and white called Wajid Sandstone, crossbedded sandstone with ferruginous cement and concretions in some layers. Locally, the rocks underlying the Wajid Sandstone are deeply weathered. Poorly sorted alluvial sand and gravel mantle the wadi floors. In the northeastern and southwestern parts of the quadrangle well-sorted aeolian sand is common. The volcanic and sedimentary rocks of the quadrangle are part of the east limb of an immense synclinorium(?) that closes south-westward around a batholitic core of gneissic granite and granodiorite. These layered rocks were isoclinally folded along northerly and north-northeasterly trending axes prior to the intrusion of the peralkalic magma series. During intrusion, the layered rocks were again folded as they were pushed aside, and major old regional northerly faults were reactivated with persistent left-lateral displacement. Reconnaissance geochemical sampling disclosed several notable groupings of threshold and anomalous elements with spe

DOE Office of Scientific and Technical Information (OSTI.GOV)

Nibbelink, K.A.; Sorgenfrei, M.C.; Rice, D.E.

Yombo field in the Congo is sourced from the lacustrine shales of the presalt rift stage and produces from the Albian and Cenomanian, postsalt, Sendji carbonate and Tchala Sandstone. The Yombo prospect exploration model included an upper Sendji stratigraphic trap with two components and a structural nose. The buried hill component of the trap is formed by topographic relief on the reservoir below the top Sendji unconformity. The lower Sendji slump blocks provide a high on which the upper Sendji grainstone shoal facies develop. Both depositional relief and erosion during the top Sendji unconformity contribute to the topography. An isochronmore » thick in the overlying Tchala valley-fill sediments defined a drainage pattern on the unconformity around the buried hill of the underlying upper Sendji. The facies change component is formed by the pinch-out of the grainstone shoal reservoir facies into porous, but impermeable lagoonal dolomite interbedded with anhydrite and shale. Capillary pressure measurements on the 16% porosity, 0.1 md permeability lagoonal dolomite, along with pore throat radius and buoyancy calculations, demonstrated this facies could trap a significant column of low-gravity oil at shallow depth. The Tchala Sandstone contains several separate hydrocarbon accumulations. A stratigraphic trap in the lower Tchala is formed by marine and tidal channel sandstones pinching out into lagoonal shales. The nearshore marine sandstones of the upper Tchala contain additional hydrocarbons in structural and stratigraphic traps. The stratigraphic pinch-out that cross the Yombo nose trap a significant hydrocarbon accumulation, even though the four-way structural closure is relatively small.« less

Analysis of some seismic expressions of Big Injun sandstone and its adjacent interval

DOE Office of Scientific and Technical Information (OSTI.GOV)

Xiangdong, Zou; Wilson, T.A.; Donaldson, A.C.

1991-08-01

The Big Injun sandstone is an important oil and gas reservoir in western West Virginia. The pre-Greenbrier unconformity has complicated correlations, and hydrocarbon explorationists commonly have misidentified the Big Injun in the absence of a regional stratigraphic study. Paleogeologic maps on this unconformity show the West Virginia dome, with the Price/Pocono units truncated resulting in pinch-outs of different sandstones against the overlying Big Lime (Greenbrier Limestone). Drillers have named the first sandstone below the Big Lime as Big Injun, and miscorrelated the real Big Injun with Squaw, upper Weir, and even the Berea sandstone. In this report, an 8-mi (13-km)more » seismic section extending from Kanawha to Clay counties was interpreted. The study area is near the pinch-out of the Big Injun sandstone. A stratigraphic cross section was constructed from gamma-ray logs for comparison with the seismic interpretation. The modeling and interpretation of the seismic section recognized the relief on the unconformity and the ability to determine facies changes, too. Both geophysical wireline and seismic data can be used for detailed stratigraphic analysis within the Granny Creek oil field of Clay and Roane countries.« less

Sedimentary facies of the upper Cambrian (Furongian; Jiangshanian and Sunwaptan) Tunnel City Group, Upper Mississippi Valley: new insight on the old stormy debate

USGS Publications Warehouse

Eoff, Jennifer D.

2014-01-01

New data from detailed measured sections permit a comprehensive revision of the sedimentary facies of the Furongian (upper Cambrian; Jiangshanian and Sunwaptan stages) Tunnel City Group (Lone Rock Formation and Mazomanie Formation) of Wisconsin and Minnesota. Heterogeneous sandstones, comprising seven lithofacies along a depositional transect from shoreface to transitional-offshore environments, record sedimentation in a storm-dominated, shallow-marine epicontinental sea. The origin of glauconite in the Birkmose Member and Reno Member of the Lone Rock Formation was unclear, but its formation and preserved distribution are linked to inferred depositional energy rather than just net sedimentation rate. Flat-pebble conglomerate, abundant in lower Paleozoic strata, was associated with the formation of a condensed section during cratonic flooding. Hummocky cross-stratification was a valuable tool used to infer depositional settings and relative paleobathymetry, and the model describing formation of this bedform is expanded to address flow types dominant during its genesis, in particular the importance of an early unidirectional component of combined flow. The depositional model developed here for the Lone Rock Formation and Mazomanie Formation is broadly applicable to other strata common to the early Paleozoic that document sedimentation along flooded cratonic interiors or shallow shelves.

Sedimentation, zoning of reservoir rocks in W. Siberian basin oil fields

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kliger, J.A.

1994-02-07

A line pattern of well cluster spacing was chosen in western Siberia because of taiga, marshes, etc., on the surface. The zoning of the oil pools within productive Upper Jurassic J[sub 3] intervals is complicated. This is why until the early 1990s almost each third well drilled in the Shaimsky region on the western edge of the West Siberian basin came up dry. The results of development drilling would be much better if one used some sedimentological relationships of zoning of the reservoir rocks within the oil fields. These natural phenomena are: Paleobasin bathymetry; Distances from the sources of themore » clastic material; and Proximity of the area of deposition. Using the diagram in this article, one can avoid drilling toward areas where the sandstone pinch out, area of argillization of sand-stones, or where the probability of their absence is high.« less

Geological characterization and statistical comparison of outcrop and subsurface facies: Shannon Shelf sand ridges

NASA Astrophysics Data System (ADS)

Jackson, S.; Szpaklewicz, M.; Tomutsa, L.

1987-09-01

The primary objective of this research is to develop a methodology for constructing accurate quantitative models of reservoir heterogeneities. The resulting models are expected to improve predictions of flow patterns, spatial distribution of residual oil after secondary and tertiary recovery operations, and ultimate oil recovery. The purpose of this study is to provide preliminary evaluation of the usefulness of outcrop information in characterizing analogous reservoirs and to develop research techniques necessary for model development. The Shannon Sandstone, a shelf sand ridge deposit in the Powder River Basin, Wyoming, was studied. Sedimentologic and petrophysical features of an outcrop exposure of the High-Energy Ridge-Margin facies (HERM) within the Shannon were compared with those from a Shannon sandstone reservoir in Teapot Dome field. Comparisons of outcrop and subsurface permeability and porosity histograms, cumulative distribution functions, correlation lengths and natural logarithm of permeability versus porosity plots indicate a strong similarity between Shannon outcrop and Teapot Dome HERM facies petrophysical properties. Permeability classes found in outcrop samples can be related to crossbedded zones and shaley, rippled, and bioturbated zones. Similar permeability classes related to similar sedimentologic features were found in Teapot Dome field. The similarities of outcrop and Teapot Dome petrophysical properties, which are from the same geologic facies but from different depositional episodes, suggest that rocks deposited under similar depositional processes within a given deposystem have similar reservoir properties. The results of the study indicate that the use of quantitative outcrop information in characterizing reservoirs may provide a significant improvement in reservoir characterization.

Reservoir management in a hydrodynamic environment, Iagifu-Hedinia area, Southern Highlands, Papua New Guinea

DOE Office of Scientific and Technical Information (OSTI.GOV)

Eisenberg, L.I.; Langston, M.V.; Fitzmorris, R.E.

Northwest to southeast regional scale flow in the Toro Sandstone parallels the Papuan Fold and Thrust Belt for a distance of 115 km, passing through Iagifu/Hedinia oil field along the way. This has had a profound effect on oil distribution in the Toro there, having swept the northwest side free of movable oil. A structurally controlled flow restriction causes a local, rapid drop in hydraulic potential, tilting local oil/water contacts up to six degrees and causing the three sandstone members of the Toro to locally behave as separate reservoirs, each with its own hydrocarbon/water contact. Reservoir simulations of Iagifu/Hedinia whichmore » include a flowing aquifer are able to match observed production history. Without a flowing aquifer, simulation predicts greater and earlier water production, and a greater pressure drop in the oil leg than has been observed. Reservoir modeling using a flowing aquifer has allowed downhole, structural targeting of later infill wells to be much closer to the OWC than would otherwise have been thought prudent, and has raised questions as to the potential effectiveness of a downdip water injection scheme. Production results from a small satellite field upstream of the main Iagifu/Hedinia field have shown a sudden increase in water production and reservoir pressure after a long period of pressure decline and no water production. This behavior appears to be due to an influx of higher hydraulic potential from a separate reservoir sand, the influx being brought about by pressure draw down during production and consequent breakdown of fault seal.« less

Origin of a classic cratonic sheet sandstone: Stratigraphy across the Sauk II-Sauk III boundary in the Upper Mississippi Valley

USGS Publications Warehouse

Runkel, Anthony C.; McKay, R.M.; Palmer, A.R.

1998-01-01

The origin of cratonic sheet sandstones of Proterozoic and early Paleozoic age has been a long-standing problem for sedimentologists. Lower Paleozoic strata in the Upper Mississippi Valley are best known for several such sandstone bodies, the regional depositional histories of which are poorly understood. We have combined outcrop and subsurface data from six states to place the Upper Cambrian Wonewoc (Ironton and Galesville) Sandstone in a well-constrained stratigraphic framework across thousands of square kilometers. This framework makes it possible for the first time to construct a regional-scale depositional model that explains the origin of this and other cratonic sheet sandstones. The Wonewoc Sandstone, although mapped as a single contiguous sheet, is a stratigraphically complex unit that was deposited during three distinct conditions of relative sea level that span parts of four trilobite zones. During a relative highstand of sea level in Crepicephalus Zone time, quartzose sandstone lithofacies aggraded more or less vertically in nearshore-marine and terrestrial environments across much of the present-day out-crop belt around the Wisconsin arch. At the same time, finer grained, feldspathic sandstone, siltstone, and shale aggraded in deeper water immediately seaward of the quartzose sand, and shale and carbonate sediment accumulated in the most distal areas. During Aphelaspis and Dunderbergia Zones time a relative fall in sea level led to the dispersal of quartzose sand into a basinward-tapering, sheet-like body across much of the Upper Mississippi Valley. During early Elvinia Zone time a major transgression led to deposition of a second sheet sandstone that is generally similar to the underlying regressive sheet. The results of this investigation also demonstrate how subtle sequence-bounding unconformities may be recognized in mature, cratonic siliciclastics. We place the Sauk II-Sauk III subsequence boundary at the base of the coarsest bed in the Wonewoc Sandstone, a lag developed through erosion that occurred during the regional regressive-transgressive event that spanned Aphelaspis to early Elvinia Zones time. Such sequence-bounding unconformities are difficult to recognize where they are contained within coarse siliciclastics of the Upper Mississippi Valley, because they separate strata that are texturally and mineralogically similar, and because erosion occurred on a loose, sandy substrate along a low, uniform gradient, and in a nonvegetated terrestrial environment. Furthermore, the ultramature mineral composition of the exposed substrate is resistant to the development of a recognizable weathering profile. The well-known sheet geometry of the Wonewoc and other units of lower Paleozoic sandstone of this area is not dependent on atypical terrestrial depositional conditions conducive to the widespread distribution of sand, as commonly believed. Sand was spread into a sheet dominantly within the marine realm in a manner similar to that inferred for many better-known sandstone bodies deposited in the North American Cretaceous Western Interior seaway and Tertiary Gulf of Mexico. The laterally extensive, thin character of the Upper Mississippi Valley sandstone bodies compared to these other sandstone bodies simply reflects deposition of a continuously abundant supply of sand on a relatively stable, nearly flat basin of slow, uniform subsidence during changes in sea level. The dearth of shale in this and other cratonic sandstones can be indirectly attributed to the same controls, which led to an uncommonly low preservation potential for fairweather deposits on the shoreface.

Geology and ground-water resources of Rock County, Wisconsin

USGS Publications Warehouse

LeRoux, E.F.

1964-01-01

Rock County is in south-central Wisconsin adjacent to the Illinois State line. The county has an area of about 723 square miles and had a population of about 113,000 in 1957 ; it is one of the leading agricultural and industrial counties in the State. The total annual precipitation averages about 32 inches, and the mean annual temperature is about 48 ? F. Land-surface altitudes are generally between 800 and 00 feet, but range from 731 feet, where the Rock River flows into Illinois, to above 1,080 feet, at several places in the northwestern part of the county. The northern part of Rock County consists of the hills and kettles of a terminal moraine which slopes southward to a flat, undissected outwash plain. The southeastern part of the county is an area of gentle slopes, whereas the southwestern part consists of steep-sided valleys and ridges. Rock County is within the drainage basin of the Rock River, which flows southward through the center of the county. The western and southwestern parts of ,the county are drained by the Sugar River und Coon Creek, both of which flow into the Pecatonica River in Illinois and thence into the Rock River. The southeastern part of the county is drained by Turtle Creek, which also flows into Illinois before joining the Rock River. Nearly all the lakes and ponds are in the northern one-third of the county, the area of most recent glaciation. The aquifers in Rock County are of sedimentary origin and include deeply buried sandstones, shales, and dolomites of the Upper Cambrian series. This series overlies crystalline rocks of Precambrian age and supplies water to all the cities and villages in the county. The St. Peter sandstone of Ordovician age underlies all Rock County except where the formation has been removed by erosion in the Rock and Sugar River valleys, and perhaps in Coon Creek valley. The St. Peter sandstone is the principal source of water for domestic, stock, and small industrial wells in the western half of the county. This sandstone also yields some water to uncased wells that tap the deeper rocks of the Upper Cambrian series. East of the Rock River the Platteville, Decorah, and Galena formations undifferentiated, or Platteville-Galena unit, is the principal source of water for domestic and stock wells. Unconsolidated deposits of glacial origin cover most of Rock County and supply water to many small wells. In the outwash deposits along the Rock River, wells of extremely high capacity have been developed for industrial and municipal use. The most significant feature of the bedrock surface in Rock County is the ancestral Rock River valley, which has been filled with glacial outwash to a depth of at least 396 feet below the present land surface. East of the buried valley the bedrock has a fiat, relatively undissected surface. West of the valley the bedrock surface is rugged and greatly dissected. Ground water in Rock County occurs under both water-table and artesian conditions; however, because of the interconnection and close relation of all ground water in the county, the entire system is considered to be a single groundwater body whose surface may be represented by one piezometric map. Recharge occurs locally, throughout the county. Nearly all recharge is derived directly from precipitation that percolates downward to become a part of the groundwater body. Natural movement of water in the consolidated water-bearing units is generally toward the buried Rock and Sugar River valleys. Movement of water in the sandstones of Cambrian age was calculated to be about 44 million gallons a day toward the Rock River. Discharge from wells in Rock County in 1957 was about 23 million gallons a day. Nearly 90 percent of this water was drawn from the area along the Rock River. Drilled wells, most of which were drilled by the cable-tool method, range in diameter from 3 to 26 inches, and in depth from 46 to 1,225 feet. Driven wells in alluvium and glacial drift are usually 1? to 2? in

Potential effects of deep-well waste disposal in western New York

USGS Publications Warehouse

Waller, Roger Milton; Turk, John T.; Dingman, Robert James

1978-01-01

Mathematical and laboratory models were used to observe, respectively, the hydraulic and chemical reactions that may take place during proposed injection of a highly acidic, iron-rich waste pickle liquor into a deep waste-disposal well in western New York. Field temperature and pressure conditions were simulated in the tests. Hydraulic pressure in the middle stages of the initial (1968) injection test had probably hydraulically fractured the Cambrian sandstone-dolomite formation adjacent to the borehole. Transmissivity of the formation is 13 feet squared per day. The proposed rate of injection (72,000 gallons per day) of waste pickle liquor would approach a wellhead pressure of 600 pounds per square inch in about a year. Hydraulic fracturing would reoccur at about 580 pounds per square inch. The measurable cone of influence would extend about 22 miles after injection for 1 year. Chemical reactions between acidic wastes and brine-saturated dolomite would create precipitates that would drastically reduce the permeability of the unfractured part of the dolomite. Nondolomitic sandstone permeability would not be affected by chemical reactions, but the pores might be plugged by the iron-bearing waste. The digital model can be used for qualitative predictions on a regional scale. (Woodard-USGS)

Redefining fluids relative permeability for reservoir sands. (Osland oil and gas field, offshore Niger Delta, Nigeria)

NASA Astrophysics Data System (ADS)

Richardson, M. A.-A.; Taioli, F.

2018-06-01

Redefining oil and water relative permeability for the evaluation of reservoir sands, a case study of Osland oil and gas field, Offshore Niger Delta, Nigeria has been carried out. The aim of this study is to modify water relative permeability (Kwr) and oil relative permeability (Kor) equations in sandstone units. The objectives are to provide alternative expressions for Kwr and Kor in sandstone units, use the equations as inputs in a simplified water cut (Cw) equation to predict the volume of water that will be associated with the recoverable volume of oil (VRo) in penetrated reservoirs. The relationship between porosity (Φ) and water saturation (Sw) , with the relationship between porosity and hydrocarbon saturation ( Sh), were used to evaluate KWr and Kor in order to predict Cw in the selected reservoirs. Reservoir X in Well D1 shows about 2.0 ×106bbl for VRo and 18.78% for Cw but in D2 it shows about 7.4 ×106bbl and 1.73% for VRo and Cw respectively. Similarly, in Reservoir Y, D1 has about 6.8 ×106bbl of VRo and 0.034% of Cw , but in D2 it has about 9.3 ×106 bbl of VRo and 0.015% of Cw . The results suggest that high Φ with corresponding high Sw resulted in high associated Cw in Reservoir X. The evaluation also confirmed that the decrease in the ratio of oil relative permeability to water relative permeability (Kor /Kwr) corresponds to the increase in Cw . The total recoverable volumes of hydrocarbons from the two wells are estimated at 7.7 ×109cu .ft for gas and at 2.54 ×107bbl for oil. With the present conditions of the two reservoirs, the values of Cw in Reservoir X are low and are extremely low and negligible in Reservoir Y. Reservoir X in Well D1 has a smaller volume of VRo but the Cw is higher than others. Nonetheless, the Cw in Reservoir X is still within acceptable range.

Characterization of coal-derived hydrocarbons and source-rock potential of coal beds, San Juan Basin, New Mexico and Colorado, U.S.A.

USGS Publications Warehouse

Rice, D.D.; Clayton, J.L.; Pawlewicz, M.J.

1989-01-01

Coal beds are considered to be a major source of nonassociated gas in the Rocky Mountain basins of the United States. In the San Juan basin of northwestern New Mexico and southwestern Colorado, significant quantities of natural gas are being produced from coal beds of the Upper Cretaceous Fruitland Formation and from adjacent sandstone reservoirs. Analysis of gas samples from the various gas-producing intervals provided a means of determining their origin and of evaluating coal beds as source rocks. The rank of coal beds in the Fruitland Formation in the central part of the San Juan basin, where major gas production occurs, increases to the northeast and ranges from high-volatile B bituminous coal to medium-volatile bituminous coal (Rm values range from 0.70 to 1.45%). On the basis of chemical, isotopic and coal-rank data, the gases are interpreted to be thermogenic. Gases from the coal beds show little isotopic variation (??13C1 values range -43.6 to -40.5 ppt), are chemically dry (C1/C1-5 values are > 0.99), and contain significant amounts of CO2 (as much as 6%). These gases are interpreted to have resulted from devolatilization of the humic-type bituminous coal that is composed mainly of vitrinite. The primary products of this process are CH4, CO2 and H2O. The coal-generated, methane-rich gas is usually contained in the coal beds of the Fruitland Formation, and has not been expelled and has not migrated into the adjacent sandstone reservoirs. In addition, the coal-bed reservoirs produce a distinctive bicarbonate-type connate water and have higher reservoir pressures than adjacent sandstones. The combination of these factors indicates that coal beds are a closed reservoir system created by the gases, waters, and associated pressures in the micropore coal structure. In contrast, gases produced from overlying sandstones in the Fruitland Formation and underlying Pictured Cliffs Sandstone have a wider range of isotopic values (??13C1 values range from -43.5 to -38.5 ppt), are chemically wetter (C1/C1-5 values range from 0.85 to 0.95), and contain less CO2 (< 2%). These gases are interpreted to have been derived from type III kerogen dispersed in marine shales of the underlying Lewis Shale and nonmarine shales of the Fruitland Formation. In the underlying Upper Cretaceous Dakota Sandstone and Tocito Sandstone Lentil of the Mancos Shale, another gas type is produced. This gas is associated with oil at intermediate stages of thermal maturity and is isotopically lighter and chemically wetter at the intermediate stage of thermal maturity as compared with gases derived from dispersed type III kerogen and coal; this gas type is interpreted to have been generated from type II kerogen. Organic matter contained in coal beds and carbonaceous shales of the Fruitland Formation has hydrogen indexes from Rock-Eval pyrolysis between 100 and 350, and atomic H:C ratios between 0.8 and 1.2. Oxygen indexes and atomic O:C values are less than 24 and 0.3, respectively. Extractable hydrocarbon yields are as high as 7,000 ppm. These values indicate that the coal beds and carbonaceous shales have good potential for the generation of liquid hydrocarbons. Voids in the coal filled with a fluorescent material that is probably bitumen is evidence that liquid hydrocarbon generation has taken place. Preliminary oil-source rock correlations based on gas chromatography and stable carbon isotope ratios of C15+ hydrocarbons indicate that the coals and (or) carbonaceous shales in the Fruitland Formation may be the source of minor amounts of condensate produced from the coal beds at relatively low levelsof thermal maturity (Rm=0.7). ?? 1989.

Microseismicity Induced by Hydraulic Fracturing in Oil and Gas Wells

NASA Astrophysics Data System (ADS)

Warpinski, N. R.; Maxwell, S.; Waltman, C.

2006-12-01

The detection and analysis of microseismicity induced by injection of fluids at high pressure has proved to be an effective technology for monitoring the placement of the fluid in applications such as hydraulic fracture stimulation of oil and gas wells, "shear-dilation" enhancement of hot-dry-rock reservoirs, waterflooding and tertiary recovery processes in oil reservoirs, CO2 injection for sequestration, drill cuttings injection, and many others. Microseismic mapping of hydraulic fractures, in particular, has grown into an extensive industry that provides critical information on many facets of fracture behavior and the overall geometry, with the results showing both expected and unexpected behavior in various tests. These industrial fractures are typically mapped with arrays of downhole tri-axial receivers placed in one or more wells at the reservoir level. With the number of microseismically mapped fractures now exceeding 1,000, numerous observations and inferences about fracture mechanisms can be made. In a large group of reservoirs, the created hydraulic fractures are mostly planar and follow a consistent azimuth. In other reservoirs, such as naturally fractured shales similar to the Barnett shale in the Fort Worth basin, the created fracture is highly dependent on the treatment. In these shale reservoirs, the use of viscous gels results in a mostly planar geometry, but stimulations with high-rate, large-volume "waterfracs" result in network fractures that may exceed 400 m by 1200 m in areal extent. In horizontal wells where several stages of these waterfracs are commonly pumped, the stages are found to often interfere and redirect subsequent stages. In many reservoirs, the heights of the hydraulic fractures have been found to be less than the expected heights based on known or inferred in situ stress contrasts between the reservoir layer and the bounding rocks, suggesting that some properties of the layering are important for limiting height growth. In lenticular sandstones, fractures are commonly observed to follow the sandstone lithologies and migrate upward or downward to remain within the accreted sandstone beds. A number of mapping tests have been performed in environments where the hydraulic fracture has interacted with faults. In such cases, the log-scale relative magnitudes of the events may suddenly increase by two or more. The faults often extend hundreds of meters upward or downward out of zone, or in directions different from the initial hydraulic fracture. Overall, the orientations and dimensions of the mapped fractures are providing the necessary information to optimize field development and improve hydraulic fracture effectiveness. In addition, these tests are providing important clues to help understand the geomechanical conditions of the reservoir and the changes induced by hydraulic fracturing.

Submarine fans: Characteristics, models, classification, and reservoir potential

NASA Astrophysics Data System (ADS)

Shanmugam, G.; Moiola, R. J.

1988-02-01

Submarine-fan sequences are important hydrocarbon reservoirs throughout the world. Submarine-fan sequences may be interpreted from bed-thickness trends, turbidite facies associations, log motifs, and seismic-reflection profiles. Turbidites occurring predominantly in channels and lobes (or sheet sands) constitute the major portion of submarine-fan sequences. Thinning- and thickening-upward trends are suggestive of channel and lobe deposition, respectively. Mounded seismic reflections are commonly indicative of lower-fan depositional lobes. Fan models are discussed in terms of modern and ancient fans, attached and detached lobes, highly efficient and poorly efficient systems, and transverse and longitudinal fans. In general, depositional lobes are considered to be attached to feeder channels. Submarine fans can be classified into four types based on their tectonic settings: (1) immature passive-margin fans (North Sea type); (2) mature passive-margin fans (Atlantic type); (3) active-margin fans (Pacific type); and (4) mixed-setting fans. Immature passive-margin fans (e.g., Balder, North Sea), and active-margin fans (e.g., Navy, Pacific Ocean) are usually small, sand-rich, and possess well developed lobes. Mature passive-margin fans (e.g., Amazon, Atlantic Ocean) are large, mud-rich, and do not develop typical lobes. However, sheet sands are common in the lower-fan regions of mature passive-margin fans. Mixed-setting fans display characteristics of either Atlantic type (e.g., Bengal, Bay of Bengal), or Pacific type (Orinoco, Caribbean), or both. Conventional channel-lobe models may not be applicable to fans associated with mature passive margins. Submarine fans develop primarily during periods of low sea level on both active- and passive-margin settings. Consequently, hydrocarbon-bearing fan sequences are associated generally with global lowstands of sea level. Channel-fill sandstones in most tectonic settings are potential reservoirs. Lobes exhibit the most favorable reservoir quality in terms of sand content, lateral continuity, and porosity development. Lower-fan sheet sands may also make good reservoirs. Quartz-rich sandstones of mature passive-margin fans are most likely to preserve depositional porosity, whereas lithic sandstones of active-margin fans may not.

Incorporating the Impacts of Small Scale Rock Heterogeneity into Models of Flow and Trapping in Target UK CO2 Storage Systems

NASA Astrophysics Data System (ADS)

Jackson, S. J.; Reynolds, C.; Krevor, S. C.

2017-12-01

Predictions of the flow behaviour and storage capacity of CO2 in subsurface reservoirs are dependent on accurate modelling of multiphase flow and trapping. A number of studies have shown that small scale rock heterogeneities have a significant impact on CO2flow propagating to larger scales. The need to simulate flow in heterogeneous reservoir systems has led to the development of numerical upscaling techniques which are widely used in industry. Less well understood, however, is the best approach for incorporating laboratory characterisations of small scale heterogeneities into models. At small scales, heterogeneity in the capillary pressure characteristic function becomes significant. We present a digital rock workflow that combines core flood experiments with numerical simulations to characterise sub-core scale capillary pressure heterogeneities within rock cores from several target UK storage reservoirs - the Bunter, Captain and Ormskirk sandstone formations. Measured intrinsic properties (permeability, capillary pressure, relative permeability) and 3D saturations maps from steady-state core flood experiments were the primary inputs to construct a 3D digital rock model in CMG IMEX. We used vertical end-point scaling to iteratively update the voxel by voxel capillary pressure curves from the average MICP curve; with each iteration more closely predicting the experimental saturations and pressure drops. Once characterised, the digital rock cores were used to predict equivalent flow functions, such as relative permeability and residual trapping, across the range of flow conditions estimated to prevail in the CO2 storage reservoirs. In the case of the Captain sandstone, rock cores were characterised across an entire 100m vertical transect of the reservoir. This allowed analysis of the upscaled impact of small scale heterogeneity on flow and trapping. Figure 1 shows the varying degree to which heterogeneity impacted flow depending on the capillary number in the Captain sandstone. At low capillary numbers, typical of regions where flow is dominated by buoyancy, fluid flow is impeded and trapping enhanced. At high capillary numbers, typical of the near wellbore environment, the fluid distributed homogeneously and the equivalent relative permeability was higher leading to improved injectivity.

Core analysis of heterogeneous rocks using experimental observations and digital whole core simulation

NASA Astrophysics Data System (ADS)

Jackson, S. J.; Krevor, S. C.; Agada, S.

2017-12-01

A number of studies have demonstrated the prevalent impact that small-scale rock heterogeneity can have on larger scale flow in multiphase flow systems including petroleum production and CO2sequestration. Larger scale modeling has shown that this has a significant impact on fluid flow and is possibly a significant source of inaccuracy in reservoir simulation. Yet no core analysis protocol has been developed that faithfully represents the impact of these heterogeneities on flow functions used in modeling. Relative permeability is derived from core floods performed at conditions with high flow potential in which the impact of capillary heterogeneity is voided. A more accurate representation would be obtained if measurements were made at flow conditions where the impact of capillary heterogeneity on flow is scaled to be representative of the reservoir system. This, however, is generally impractical due to laboratory constraints and the role of the orientation of the rock heterogeneity. We demonstrate a workflow of combined observations and simulations, in which the impact of capillary heterogeneity may be faithfully represented in the derivation of upscaled flow properties. Laboratory measurements that are a variation of conventional protocols are used for the parameterization of an accurate digital rock model for simulation. The relative permeability at the range of capillary numbers relevant to flow in the reservoir is derived primarily from numerical simulations of core floods that include capillary pressure heterogeneity. This allows flexibility in the orientation of the heterogeneity and in the range of flow rates considered. We demonstrate the approach in which digital rock models have been developed alongside core flood observations for three applications: (1) A Bentheimer sandstone with a simple axial heterogeneity to demonstrate the validity and limitations of the approach, (2) a set of reservoir rocks from the Captain sandstone in the UK North Sea targeted for CO2 storage, and for which the use of capillary pressure hysteresis is necessary, and (3) a secondary CO2-EOR production of residual oil from a Berea sandstone with layered heterogeneities. In all cases the incorporation of heterogeneity is shown to be key to the ultimate derivation of flow properties representative of the reservoir system.

Geohydrology of the Navajo sandstone in western Kane, southwestern Garfield, and southeastern Iron counties, Utah

USGS Publications Warehouse

Freethey, G.W.

1988-01-01

The upper Navajo and Lamb Point aquifers in the Navajo Sandstone are the principal source of water for the city of Kanab, irrigation, stock, and for rural homes in the study area. Well logs and outcrop descriptions indicate the Navajo Sandstone consists of the Lamb Point Tongue and an unnamed upper member that are separated by the Tenney Canyon Tongue of the Kayenta Formation. The main Kayenta Formation underlies the Lamb Point Tongue. The Lamb Point Tongue and the upper member of the Navajo Sandstone are saturated and hydraulically connected through the Tenney Canyon Tongue. Available data indicate that precipitation percolates to the groundwater reservoir where the Navajo Sandstone crops out. Estimates of the rate of recharge at the outcrop range from 0.1 to as much as 2.8 in/yr. Water level data indicate that water moves from the upper member of the Navajo Sandstone, through the Tenney Canyon Tongue, and into the Lamb Point Tongue. Lateral flow is generally from the outcrop areas toward the incised canyons formed by tributaries of Kanab Creek and Johnson Wash. Direction and rate of groundwater movement and the location and character of the natural hydrologic boundaries in the northern part of the area where the Navajo Sandstone is buried cannot be determined conclusively without additional water level data. (Author 's abstract)

Section of Morgan formation, Pennsylvanian, at Split Mountain in Dinosaur National Monument, Uintah County, Utah

USGS Publications Warehouse

McCann, Franklin T.; Raman, Norman D.; Henbest, Lloyd G.

1946-01-01

Extension of the oil pool in the Weber sandstone (Pennsylvanian), in the Rangely oil field, Rio Blanco County, Colorado, subsequent to the completion of the filed work on which Preliminary Chart 16 is based, has stimulated special interest in the beds beneath that sandstone as potential oil reservoirs. In compliance with the demand for additional information concerning these beds, a detailed description of the sequence immediately underlying the Weber sandstone at Split Mountain, Utah, is here given. That part of Split Mountain where the section was measured is approximately 35 airline miles northwest of the town of Rangely. The section itself is shown graphically and somewhat generalized in column 8, sheet 2, Preliminary Chart 16. A more detailed graphic section is presented in the accompanying column section.

Origin of lower Tyler Oil in central Montana

DOE Office of Scientific and Technical Information (OSTI.GOV)

Kranzler, I.

A study of the Heath (Mississippian) and lower Tyler (Pennsylvanian) sediments of central Montana suggests a close relationship between the oil accumulations and the relative positions of the Heath limestone and the lower Tyler sandstones. Reconstruction of the pre-Amsden structure and the Tyler-Heath paleogeology shows that the oil accumulations at Sumatra, Stensvad, Ivanhoe, Keg Coulee, Bascom, Melstone, and Big Wall Fields occur where the paleostructural position of the lower Tyler sandstones is updip from, and in direct contact with, the Heath limestone. The foregoing relationships seem to be further supported by a study of Alice and Porcupine domes. These domesmore » have barren sandstone reservoirs in excellent structural- stratigraphic traps. The peleostructural attitude in the area of the domes was flat and the Heath limestone apparently not well developed.« less

Timing of compaction and quartz cementation from integrated petrographic and burial-history analyses, Lower Cretaceous Fall River Formation, Wyoming and South Dakota

DOE Office of Scientific and Technical Information (OSTI.GOV)

Dutton, S.P.

1997-01-01

Integrated petrographic and burial-history studies of Fall River sandstones from outcrop and the subsurface provide insight into the timing of compaction and quartz cementation, the two main porosity-reducing processes in quartzose sandstones. Petrographic study of 95 thin sections of Fall River fluvial valley-fill sandstones from outcrop, Donkey Creek field at 2 km burial depth, and Buck Draw field at 3.8 km indicates that reservoir quality differs significantly in these three areas. Fall River sandstones at the surface contain an average of 31% intergranular volume (IGV) and 2% quartz cement. In both Donkey Creek and Buck Draw fields, the sandstones averagemore » 22% IGV, but quartz-cement volume averages 8% in the shallower field and 12% in the deeper. Geometric mean permeability at the surface is 4,700 md, compared with 42 md at 2 km and 2 md at 3.8 km. Burial history of the Fall River sandstone differs greatly in the three areas. The outcropping sandstones were buried to 2 km and had reached 80 C by the end of the Cretaceous. They were then uplifted and have remained at near-surface temperatures since the Paleocene; the calculated time-temperature index (TTI) of these sandstones is 1. Fall River sandstones at Donkey Creek were also buried to 2 km and had reached 80 C by the end of the Cretaceous but remained at that depth during the Tertiary; TTI is 14. In Buck Draw field, Fall River sandstones were buried to 2.5 km during the Cretaceous and then continued to subside during the Tertiary, reaching depths of 4 km and temperatures of 140 C; TTI is 512.« less

Geology of the Gladys McCall geopressured-geothermal prospect, Cameron Parish, Louisiana

DOE Office of Scientific and Technical Information (OSTI.GOV)

John, C.J.

The Gladys McCall prospect lies at the western edge of the Rockefeller Wildlife Refuge about 88 km (55 mi) southeast of Lake Charles in Cameron Parish, Louisiana. The test well is 4825 m (15,831 ft) deep and was drilled in 1981 under the U.S. Department of Energy geopressured-geothermal research program. The well was shut in at the end of October 1987 after it had produced over 27 million barrels of brine and 676 MMscf gas, without any significant pressure decline. The stratigraphic section seen in this test well consists of alternating sandstones and shales with about 350 m (1150 ft)more » of net sand between 4393 m (14,412 ft) and 4974 m (16,320 ft). The producing reservoir is bounded on the north and south by faults. The east-west dimension is poorly defined due to lack of deep well control. Eleven prospective production zones have been identified. The pressure maintenance and the continuous high brine yield from the reservoir may be due to laterally overlapping and connected sandstones, communication between overlying and/or underlying reservoirs, growth faults acting as passageways for brine, shale dewatering, or possible communication of zones behind the casing.« less

The Fault Block Model: A novel approach for faulted gas reservoirs

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ursin, J.R.; Moerkeseth, P.O.

1994-12-31

The Fault Block Model was designed for the development of gas production from Sleipner Vest. The reservoir consists of marginal marine sandstone of Hugine Formation. Modeling of highly faulted and compartmentalized reservoirs is severely impeded by the nature and extent of known and undetected faults and, in particular, their effectiveness as flow barrier. The model presented is efficient and superior to other models, for highly faulted reservoir, i.e. grid based simulators, because it minimizes the effect of major undetected faults and geological uncertainties. In this article the authors present the Fault Block Model as a new tool to better understandmore » the implications of geological uncertainty in faulted gas reservoirs with good productivity, with respect to uncertainty in well coverage and optimum gas recovery.« less

Physical and economic potential of geological CO2 storage in saline aquifers.

PubMed

Eccles, Jordan K; Pratson, Lincoln; Newell, Richard G; Jackson, Robert B

2009-03-15

Carbon sequestration in sandstone saline reservoirs holds great potential for mitigating climate change, but its storage potential and cost per ton of avoided CO2 emissions are uncertain. We develop a general model to determine the maximum theoretical constraints on both storage potential and injection rate and use it to characterize the economic viability of geosequestration in sandstone saline aquifers. When applied to a representative set of aquifer characteristics, the model yields results that compare favorably with pilot projects currently underway. Over a range of reservoir properties, maximum effective storage peaks at an optimal depth of 1600 m, at which point 0.18-0.31 metric tons can be stored per cubic meter of bulk volume of reservoir. Maximum modeled injection rates predict minima for storage costs in a typical basin in the range of $2-7/ ton CO2 (2005 U.S.$) depending on depth and basin characteristics in our base-case scenario. Because the properties of natural reservoirs in the United States vary substantially, storage costs could in some cases be lower or higher by orders of magnitude. We conclude that available geosequestration capacity exhibits a wide range of technological and economic attractiveness. Like traditional projects in the extractive industries, geosequestration capacity should be exploited starting with the low-cost storage options first then moving gradually up the supply curve.

Petroleum system of the Shelf Rift Basin, East China Sea

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cunningham, A.C.; Armentrout, J.M.; Prebish, M.

1996-12-31

The Tertiary section of the Oujioang and Quiontang Depressions of the East China Sea Basin consists of at least eight rift-related depositional sequences identified seismically by regionally significant onlap and truncation surfaces. These sequences are calibrated by several wells including the Wenzhou 6-1-1 permitting extrapolation of petroleum system elements using seismic facies analysis. Gas and condensate correlated to non-marine source rocks and reservoired in sandstone at the Pinghu field to the north of the study area provides an known petroleum system analogue. In the Shelf Rift Basin, synrift high-amplitude parallel reflections within the graben axes correlate with coaly siltstone stratamore » and are interpreted as coastal plain and possibly lacustrine facies with source rock potential. Synrift clinoform seismic facies prograding from the northwest footwall correlate with non-marine to marginal marine conglomerate, sandstone and siltstone, and are interpreted as possible delta or fan-delta facies with reservoir potential although porosity and permeability is low within the Wenzhou 6-1-1 well. Post-rift thermal sag sequences are characterized by parallel and relatively continuous seismic reflections and locally developed clinoform packages. These facies correlate with porous and permeable marine sandstone and siltstone. Shales of potential sealing capacity occur within marine flooding intervals of both the synrift and post-rift sequences. Traps consist of differentially rotated synrift fill, and post-rift inversion anticlines. Major exploration risk factors include migration from the synrift coaly source rocks to the post-rift porous and permeable sandstones, and seismic imaging and drilling problems associated with extensive Tertiary igneous intrusions.« less

Petroleum system of the Shelf Rift Basin, East China Sea

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cunningham, A.C.; Armentrout, J.M.; Prebish, M.

1996-01-01

The Tertiary section of the Oujioang and Quiontang Depressions of the East China Sea Basin consists of at least eight rift-related depositional sequences identified seismically by regionally significant onlap and truncation surfaces. These sequences are calibrated by several wells including the Wenzhou 6-1-1 permitting extrapolation of petroleum system elements using seismic facies analysis. Gas and condensate correlated to non-marine source rocks and reservoired in sandstone at the Pinghu field to the north of the study area provides an known petroleum system analogue. In the Shelf Rift Basin, synrift high-amplitude parallel reflections within the graben axes correlate with coaly siltstone stratamore » and are interpreted as coastal plain and possibly lacustrine facies with source rock potential. Synrift clinoform seismic facies prograding from the northwest footwall correlate with non-marine to marginal marine conglomerate, sandstone and siltstone, and are interpreted as possible delta or fan-delta facies with reservoir potential although porosity and permeability is low within the Wenzhou 6-1-1 well. Post-rift thermal sag sequences are characterized by parallel and relatively continuous seismic reflections and locally developed clinoform packages. These facies correlate with porous and permeable marine sandstone and siltstone. Shales of potential sealing capacity occur within marine flooding intervals of both the synrift and post-rift sequences. Traps consist of differentially rotated synrift fill, and post-rift inversion anticlines. Major exploration risk factors include migration from the synrift coaly source rocks to the post-rift porous and permeable sandstones, and seismic imaging and drilling problems associated with extensive Tertiary igneous intrusions.« less

Pore Structure and Diagenetic Controls on Relative Permeability: Implications for Enhanced Oil Recovery and CO2 Storage

NASA Astrophysics Data System (ADS)

Feldman, J.; Dewers, T. A.; Heath, J. E.; Cather, M.; Mozley, P.

2016-12-01

Multiphase flow in clay-bearing sandstones of the Morrow Sandstone governs the efficiency of CO2 storage and enhanced oil recovery at the Farnsworth Unit, Texas. This formation is the target for enhanced oil recovery and injection of one million metric ton of anthropogenically-sourced CO2. The sandstone hosts eight major flow units that exhibit distinct microstructural characteristics due to diagenesis, including: "clean" macro-porosity; quartz overgrowths constricting some pores; ghost grains; intergranular porosity filled by microporous authigenic clay; and feldspar dissolution. We examine the microstructural controls on macroscale (core scale) relative permeability and capillary pressure behavior through: X-ray computed tomography, Robomet.3d, and focused ion beam-scanning electron microscopy imaging of the pore structure of the major flow units of the Morrow Sandstone; relative permeability and capillary pressure in the laboratory using CO2, brine, and oil at reservoir pressure and effective stress conditions. The combined data sets inform links between patterns of diagenesis and multiphase flow. These data support multiphase reservoir simulation and performance assessment by the Southwest Regional Partnership on Carbon Sequestration (SWP). Funding for this project is provided by the U.S. Department of Energy's National Energy Technology Laboratory through the SWP under Award No. DE-FC26-05NT42591. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000.

Tyler sandstones (Pennsylvanian), Dickinson area, North Dakota: a 24-million barrel soil-zone stratigraphic trap

DOE Office of Scientific and Technical Information (OSTI.GOV)

Land, C.B.

Approximately 24 million bbl of recoverable oil has been found in stratigraphic traps in the lower Pennsylvanian Tyler formation at the Dickinson, South Heart, and E. Green River Fields, Stark County, North Dakota. Production is from a multiple sequence of quartzose sandstones 5 to 18 ft (1.5 to 5 m) thick deposited as barrier islands along regressive shorelines. A typical vertical sequence is given. Throughout much of the subject area, porosity and permeability in the sandstones have been greatly reduced or completely destroyed by development of caliche paleosols. In the western part, the caliche consists of gray to brown limestonemore » nodules or nodular layers of limestone in the sandstones and contains abundant pyrite. It is estimated that the caliche destroys as much as 50% of the potential reservoir rock in the area and is an essential factor in the stratigraphic entrapment of the petroleum accumulations by providing an eastern (updip) barrier to migration.« less

Geothermal and heavy-oil resources in Texas

DOE Office of Scientific and Technical Information (OSTI.GOV)

Seni, S.J.; Walter, T.G.

1994-01-01

In a five-county area of South Texas, geopressured-geothermal reservoirs in the Paleocene-Eocene Wilcox Group lie below medium- to heavy-oil reservoirs in the Eocene Jackson Group. This fortuitous association suggests the use of geothermal fluids for thermally enhanced oil recovery (TEOR). Geothermal fairways are formed where thick deltaic sandstones are compartmentalized by growth faults. Wilcox geothermal reservoirs in South Texas are present at depths of 11,000 to 15,000 ft (3,350 to 4,570 m) in laterally continuous sandstones 100 to 200 ft (30 to 60 m) thick. Permeability is generally low (typically 1 md), porosity ranges from 12 to 24 percent, andmore » temperature exceeds 250{degrees}F (121{degrees}C). Reservoirs containing medium (20{degrees} to 25{degrees} API gravity) to heavy (10{degrees} to 20{degrees} API gravity) oil are concentrated along the Texas Coastal Plain in the Jackson-Yegua Barrier/Strandplain (Mirando Trend), Cap Rock, and Piercement Salt Dome plays and in the East Texas Basin in Woodbine Fluvial/Deltaic Strandplain and Paluxy Fault Line plays. Injection of hot, moderately fresh to saline brines will improve oil recovery by lowering viscosity and decreasing residual oil saturation. Smectite clay matrix could swell and clog pore throats if injected waters have low salinity. The high temperature of injected fluids will collapse some of the interlayer clays, thus increasing porosity and permeability. Reservoir heterogeneity resulting from facies variation and diagenesis must be considered when siting production and injection wells within the heavy-oil reservoir. The ability of abandoned gas wells to produce sufficient volumes of hot water over the long term will also affect the economics of TEOR.« less

Predictive modeling of CO2 sequestration in deep saline sandstone reservoirs: Impacts of geochemical kinetics

DOE Office of Scientific and Technical Information (OSTI.GOV)

Balashov, Victor N.; Guthrie, George D.; Hakala, J. Alexandra

2013-03-01

One idea for mitigating the increase in fossil-fuel generated CO{sub 2} in the atmosphere is to inject CO{sub 2} into subsurface saline sandstone reservoirs. To decide whether to try such sequestration at a globally significant scale will require the ability to predict the fate of injected CO{sub 2}. Thus, models are needed to predict the rates and extents of subsurface rock-water-gas interactions. Several reactive transport models for CO{sub 2} sequestration created in the last decade predicted sequestration in sandstone reservoirs of ~17 to ~90 kg CO{sub 2} m{sup -3|. To build confidence in such models, a baseline problem including rockmore » + water chemistry is proposed as the basis for future modeling so that both the models and the parameterizations can be compared systematically. In addition, a reactive diffusion model is used to investigate the fate of injected supercritical CO{sub 2} fluid in the proposed baseline reservoir + brine system. In the baseline problem, injected CO{sub 2} is redistributed from the supercritical (SC) free phase by dissolution into pore brine and by formation of carbonates in the sandstone. The numerical transport model incorporates a full kinetic description of mineral-water reactions under the assumption that transport is by diffusion only. Sensitivity tests were also run to understand which mineral kinetics reactions are important for CO{sub 2} trapping. The diffusion transport model shows that for the first ~20 years after CO{sub 2} diffusion initiates, CO{sub 2} is mostly consumed by dissolution into the brine to form CO{sub 2,aq} (solubility trapping). From 20-200 years, both solubility and mineral trapping are important as calcite precipitation is driven by dissolution of oligoclase. From 200 to 1000 years, mineral trapping is the most important sequestration mechanism, as smectite dissolves and calcite precipitates. Beyond 2000 years, most trapping is due to formation of aqueous HCO{sub 3}{sup -}. Ninety-seven percent of the maximum CO{sub 2} sequestration, 34.5 kg CO{sub 2} per m{sup 3} of sandstone, is attained by 4000 years even though the system does not achieve chemical equilibrium until ~25,000 years. This maximum represents about 20% CO{sub 2} dissolved as CO{sub 2},aq, 50% dissolved as HCO{sub 3}{sup -}{sub ,aq}, and 30% precipitated as calcite. The extent of sequestration as HCO{sub 3}{sup -} at equilibrium can be calculated from equilibrium thermodynamics and is roughly equivalent to the amount of Na+ in the initial sandstone in a soluble mineral (here, oligoclase). Similarly, the extent of trapping in calcite is determined by the amount of Ca2+ in the initial oligoclase and smectite. Sensitivity analyses show that the rate of CO{sub 2} sequestration is sensitive to the mineral-water reaction kinetic constants between approximately 10 and 4000 years. The sensitivity of CO{sub 2} sequestration to the rate constants decreases in magnitude respectively from oligoclase to albite to smectite.« less

Geology and ground-water resources of Fond du Lac County, Wisconsin

USGS Publications Warehouse

Newport, Thomas G.

1962-01-01

The principal water-bearing rocks underlying Fond du Lac County, Wis., are sandstones of Cambrian and Ordovician age and dolomite of Silurian age. Other aquifers include dolomite of Ordovician age and sand. and gravel of Quaternary age. Crystalline rocks of Precambrian age, which underlie all the water-bearing formations, form a practically impermeable basement complex and yield little or no water to wells. Ground water is the source of all public and most private and industrial water supplies in the county. The municipalities and industries obtain water chiefly from wells that penetrate the sandstones of Cambrian and Ordorician age. The Platteville formation and Galena dolomite of Ordovician age and the Niagara dolomite of Silurian age supply water to most domestic and stock wells and to a few industrial wells. Several buried valleys in the bedrock surface contain water-bearing deposits of sand and gravel. The source of the ground water in Fond du Lac County is local precipitation. Recharge to the water-bearing beds occurs in most of the county but is greatest where the bedrock formations are near the surface. Ground water is discharged by seeps and springs, by evaporation and transpiration, and by wells. Ground-water levels in wells fluctuate in response to recharge and to natural discharge and pumping. In areas not affected by pumping, water levels generally decline through the summer months because of natural discharge and lack of recharge, recover slightly in the fall after the first killing frost, decline during the winter, and recover in the spring when recharge is greatest. In areas of heavy pumping, the water levels are lowest in late summer and highest in late winter. Water levels in wells in the Fond du Lac area were about 5 to 50 feet above the land surface in 1885, but they had declined to as low as 185 feet below the land surface by 1957. Coefficients of transmissibility and storage of the sandstones of Cambrian and Ordovician age were determined by making controlled aquifer tests at Fond du Lac. The coefficients were verified by comparing computed water-level declines with actual declines. The computed values were within about 30 percent of the actual values, a reasonable agreement for coefficients of this type. Probable declines of water levels by 1966 were computed, using the same coefficients of transmissibility and storage. If the distribution of wells and the rate of pumping remain the same in 1957-66 as they were in 1956, the water levels will decline about 5 feet more by 1966. If, however, the distribution of pumped wells remains the same but the pumping by the city of Fond du Lac increases at a uniform rate from the 3 mgd (million gallons per day) pumped in 1956 to 5 mgd in 1966, the water levels in 1966 will be at least 60 feet below those of 1956. Dispersal of wells to the northwest toward the recharge area would reduce the water-level declines. The results of pumping tests, of test holes tapping the Niagara dolomite indicate that wells producing at least 200 gpm (gallons per minute) could be developed east of the Niagara escarpment. The ground water in Fond do Lac County is, in general, a hard calcium and magnesium bicarbonate water, which contains excessive iron in some areas.

Reservoir characterization combining elastic velocities and electrical resistivity measurements

NASA Astrophysics Data System (ADS)

Gomez, Carmen Teresa

2009-12-01

The elastic and electric parameters of rocks that can be obtained from seismic and electromagnetic data depend on porosity, texture, mineralogy, and fluid. However, seismic data seldom allow us to accurately quantify hydrocarbon saturation. On the other hand, in the case of common reservoir rocks (i.e., sandstones and carbonates), resistivity strongly depends on porosity and saturation. Therefore, the recent progress of controlled-source-electromagnetic (CSEM) methods opens new possibilities in identifying and quantifying potential hydrocarbon reservoirs, although its resolution is much lower than that of seismic data. Hence, a combination of seismic and CSEM data arguably offers a powerful means of finally resolving the problem of remote sensing of saturation. The question is how to combine the two data sources (elastic data and electrical resistivity data) to better characterize a reservoir. To address this question, we introduce the concept of P-wave impedance and resistivity templates as a tool to estimate porosity and saturation from well log data. Adequate elastic and resistivity models, according to the lithology, cementation, fluid properties must be chosen to construct these templates. These templates can be upscaled to seismic and CSEM scale using Backus average for seismic data, and total resistance for CSEM data. We also measured velocity and resistivity in Fontainebleau samples in the laboratory. Fontainebleau formation corresponds to clean sandstones (i.e., low clay content). We derived an empirical relation between these P-wave velocity and resistivity at 40MPa effective pressure, which is around 3 km depth at normal pressure gradients. We were not able to test if this relation could be used at well or field data scales (once appropriate upscaling was applied), since we did not have a field dataset over a stiff sandstone reservoir. A relationship between velocity and resistivity laboratory data was also found for a set of carbonates. This expression was quadratic, and not linear as in the case of Fontainebleau sandstones. There are other factors that influence this relationship in the case of these carbonates, which include pore geometry, and amount of micritic cement. We observed that the expression is almost linear, but it deviates as we approach lower resistivities. This deviation can be explained by the presence of stiff pores such as moldic or intra-granular pores, which causes high velocity but low resistivity values when water-saturated. In the same way, the effect of micrite cement on velocity is stronger than its effect on resistivity, and that also is responsible for some of the scatter that we observe. We also modeled both velocity and resistivity using self-consistent approximation with the same pore or inclusion geometries in both carbonate and sandstone laboratory datasets. In the case of carbonates, we found that we had to include needle-like pores to explain the low resistivity but high velocities. Needle is one of the geometries that allow us to have connected stiff pores. However, we also found that a fraction of compliant pores also had to be included in order to explain the velocity measurements on the carbonate dataset. The self-consistent model also approximated well the velocity and resistivity laboratory measurements on the Fontainebleau sandstones, using similar aspect ratios for both the velocity and the resistivity. As far as semi-empirical and empirical models, we observed how the stiff-sand model fit well the Fontainebleau data at 40MPa, including S-wave velocities. The Raymer-Hunt-Gardner relation also did a good job at predicting P-wave velocity. Archie's equation with cementation exponent between 1.6 and 2.1 fits the resistivity measurements on the Fontainebleau sandstones. These two relationships can be combined to create a resistivity---P-wave velocity transform for this dataset. When we attempted to use CSEM data to limit the shallow and low-frequency acoustic impedance trend for seismic inversion, we found that appropriate elastic and resistivity models must be chosen in order to have a good prediction of acoustic impedance, given resistivity. These expressions can be calibrated using well data with particular emphasis to the overburden. If no well log data are available in the shallow section, using the CSEM-derived resistivity data and an adequate cross-property relation (for example, one based on soft-sand model and Archie's equation) can be a good approach to predict the initial low frequency shallow acoustic impedance model. Validation tests showed that using the background trend from CSEM data as a constraint in impedance inversion can give a better fit to the acoustic impedance. As part of our analysis of gas hydrate bearing sandstones, we found that normalized resistivity versus P-wave impedance templates can also be useful to predict reservoir properties, such as porosity and saturation for a gas-hydrate reservoir at well log scale. Porosity and saturation prediction of the hydrate-bearing layer from seismic data alone is highly dependent on its thickness and the properties of the overburden, and requires well-control data that can point to appropriate models and properties to use for the overburden. However, it would be interesting to test, using a resistivity model obtained from seismic data as the initial input, a CSEM inversion on a gas-hydrate-bearing sandstone.

Petroleum system and production characteristics of the Muddy (J) Sandstone (Lower Cretaceous) Wattenberg continuous gas field, Denver basin, Colorado

USGS Publications Warehouse

Higley, D.K.; Cox, D.O.; Weimer, R.J.

2003-01-01

Wattenberg field is a continuous-type gas accumulation. Estimated ultimate recovery from current wells is 1.27 tcf of gas from the Lower Cretaceous Muddy (J) Sandstone. Mean gas resources that have the potential to be added to these reserves in the next 30 yr are 1.09 tcf; this will be primarily through infill drilling to recover a greater percentage of gas in place and to drain areas that are isolated because of geologic compartmentalization. Greatest gas production from the Muddy (J) Sandstone in Wattenberg field occurs (1) from within the most permeable and thickest intervals of Fort Collins Member delta-front and nearshore-marine sandstones, (2) to a lesser extent from the Horsetooth Member valley-fill channel sandstones, (3) in association with a large thermal anomaly that is delineated by measured temperatures in wells and by vitrinite reflectance contours of 0.9% and greater, (4) in proximity to the bounding Mowry, Graneros, and Skull Creek shales that are the hydrocarbon source rocks and reservoir seals, and (5) between the Lafayette and Longmont right-lateral wrench fault zones (WFZs) with secondary faults that act as conduits in areas of the field. The axis of greatest gas production is north 25 to 35?? northeast, which parallels the basin axis. Recurrent movement along five right-lateral WFZs that crosscut Wattenberg field shifted the Denver basin axis to the northeast and influenced depositional and erosional patterns of the reservoir and seal intervals. Levels of thermal maturity within the Wattenberg field are anomalously high compared to other areas of the Denver basin. The Wattenberg field thermal anomaly may be due to upward movement of fluids along faults associated with probable igneous intrusions. Areas of anomalous high heat flow within the field correlate with an increased and variable gas-oil ratio.

Depostional systems, provenance, and sequence stratigraphy, Carter and [open quotes]Millerella[close quotes] sandstones of northeast Mississippi

DOE Office of Scientific and Technical Information (OSTI.GOV)

Cleaves, A.W. II

1993-09-01

The subsurface [open quotes]Millerella[close quotes] and Carter sandstones (middle Chesterian) of the Black Warrior basin represent the highest units of the thick Muldon clastics deltaic facies tract. Lowstand marine conditions during Carter deposition allowed for southeastwardly progradation of five distinct deltaic lobe complexes onto the stable northern shelf of the basin. With each of these lobes, both an [open quotes]A[close quotes] (upper) and a [open quotes]B[close quotes] (lower) reservoir unit can be identified. The [open quotes]B[close quotes] sandstone produces from delta-front sheet sands, channel-mouth bars, and possible bar fingers of river-dominated deltas. The more prolific [open quotes]A[close quotes] subdivision containsmore » reservoirs in upper delta-plain point bars, crevasse splays, and distributary channel fills. The most easterly of the lobes, preserved in the Bean's Ferry field of Itawamba County, comprises an amalgamated valley-fill facies that removed a maximum of 250 ft (76 m) of lower Bangor platform carbonates. In contrast, the [open quotes]Millerella[close quotes] sandstone is a series of unconnected pods that formed as marine-reworked sand bodies during a eustatic rise in sea level. The average detrital sand grain composition for four cores taken in Monroe County is 94.7% monocrystalline quartz, 2.9% polycrystalline quartz, 1.6% albite feldspar, 0.1% low-rank metamorphic rock fragments, 0.5 chert, and 0.2% muscovite. These data indicate that neither the Ozark uplift nor the Ouachita orogen could have acted as the principal source area for the Carter and [open quotes]Millerella[close quotes] sandstones. More likely, the sedimentary-igneous terrains along the northern margin of the Illinois basin served this function. A major eustatic lowstand brought this mineralogically mature sediment across the Illinois basin through incised valleys to the northern self of the Black Warrior basin.« less

Relocation of Groningen seismicity using refracted waves

NASA Astrophysics Data System (ADS)

Ruigrok, E.; Trampert, J.; Paulssen, H.; Dost, B.

2015-12-01

The Groningen gas field is a giant natural gas accumulation in the Northeast of the Netherlands. The gas is in a reservoir at a depth of about 3 km. The naturally-fractured gas-filled sandstone extends roughly 45 by 25 km laterally and 140 m vertically. Decades of production have led to significant compaction of the sandstone. The (differential) compaction is thought to have reactivated existing faults and being the main driver of induced seismicity. Precise earthquake location is difficult due to a complicated subsurface, and that is the likely reason, the current hypocentre estimates do not clearly correlate with the well-known fault network. The seismic velocity model down to reservoir depth is quite well known from extensive seismic surveys and borehole data. Most to date earthquake detections, however, were made with a sparse pre-2015 seismic network. For shallow seismicity (<5 km depth) horizontal source-receiver distances tend to be much larger than vertical distances. Consequently, preferred source-receiver travel paths are refractions over high-velocity layers below the reservoir. However, the seismic velocities of layers below the reservoir are poorly known. We estimated an effective velocity model of the main refracting layer below the reservoir and use this for relocating past seismicity. We took advantage of vertical-borehole recordings for estimating precise P-wave (refraction) onset times and used a tomographic approach to find the laterally varying velocity field of the refracting layer. This refracting layer is then added to the known velocity model, and the combined model is used to relocate the past seismicity. From the resulting relocations we assess which of the faults are being reactivated.

Attributes and origins of ancient submarine slides and filled embayments: examples from the Gulf Coast basin

USGS Publications Warehouse

Morton, Robert

1993-01-01

Submarine slides exhibit landward-dipping, wavy, mounded, and chaotic seismic reflections that are manifestations of slump blocks and other mass transport material. Composition of these internally derived slide deposits depends on the composition of the preexisting shelf margin. Embayment fill above the slide consists mostly of externally derived mudstones and sandstones deposited by various disorganized slope processes, as well as more organized submarine channel-levee systems. Thickest slope sandstones, which are potential hydrocarbon reservoirs, commonly occur above the basal slide mudstones where seismic reflections change from chaotic patterns to overlying wavy or subhorizontal reflections.

Exceptional marine sand bodies in the Paleozoic of Oklahoma

DOE Office of Scientific and Technical Information (OSTI.GOV)

Fritz, R.D.; Kuykendall, M.D.; Hooker, E.O.

Of the wide variety of sandstone reservoirs in Oklahoma, the most unusual types of sand bodies are present in the Atokan Spiro Sandstone, Devonian Misener Sandstone, and Morrowan lower Morrow Sandstone. The common factors are that upon correlation and mapping these units are channel-like (fluvial-deltaic) in geometry, but from petrographic evidence are quartz-rich shallow-marine units, with the exclusion of intraclastic and diagenetic constituents. Stratigraphic mapping of the Spiro Sandstone of the Arkoma basin indicates two types of sand bodies: channel and sheet. The marine channel-like deposits, 10-150 ft thick, probably were deposited on a paleosurface produced by a pre-Atokan unconformity.more » Examination of cores and outcrop indicate that both the channel and sheet Spiro sands contain shallow-marine fossils, limestones, peloidal chamosite, burrows, and bioturbation, all indicative of a shallow-marine setting. The Misener Sandstone of north-central Oklahoma ranges from 10 to 100 ft thick with sharp boundaries. It was deposited in pre-Frisco/Woodford eroded paleochannels. Core evidence for shallow-marine deposition is glauconite, phosphatic fossils and clasts, burrows, and bioturbation. These were probably deposited in an embayed, estuary-like environment. The lower Morrow Sandstone of the Anadarko basin is similar in geometry, except that the sand bodies are multistoried and multilateral and do not appear to be associated with a regional unconformity. The lower Morrow sandstones, usually 30-60 ft thick. commonly are elongated and deposited parallel to the shoreline. Deposition is inferred to be shallow-marine from marine fossils and glauconite.« less

The geology of a part of Acadia and the nature of the Acadian orogeny across Central and Eastern Maine

USGS Publications Warehouse

Tucker, R.D.; Osberg, P.H.; Berry, H.N.

2001-01-01

The zone of Acadian collision between the Medial New England and Composite Avalon terranes is well preserved in Maine. A transect from northwest (Rome) to southeast (Camden) crosses the eastern part of Medial New England comprising the Central Maine basin, Liberty-Orrington thrust sheet, and Fredericton trough, and the western part of Composite Avalon, including the Graham Lake, Clarry Hill, and Clam Cove thrust sheets. U-Pb geochronology of events before, during, and after the Acadian orogeny helps elucidate the nature and distribution of tectonostrati& graphic belts in this zone and the timing of some Acadian events in the Northern Appalachians. The Central Maine basin consists of sedimentary and volcanic rocks of Middle Ordovician (???470 to ???460 Ma) age overlain with probable conformity by latest Ordovician(?) through earliest Devonian marine rift and flysch sedimentary rocks; these are intruded by weakly to undeformed plutonic rocks of Early and Middle Devonian age (???399??378 Ma). The Fredericton trough consists of Early Silurian gray pelite and sandstone to earliest Late Silurian calcareous turbidite, deformed and variably metamorphosed prior to the emplacement of Late Silurian (???422 Ma) and Early to Late Devonian (???418 to ???368 Ma) plutons. The Liberty-Orrington thrust sheet consists of Cambrian(?)-Ordovician (>???474 to ???469 Ma and younger) clastic sedimentary and volcanic rocks intruded by highly deformed Late Silurian (???424 to ???422 Ma) and Devonian (???418 to ???389 Ma) plutons, possibly metamorphosed in Late Silurian time (prior to ???417 Ma), and metamorphosed to amphibolite facies in Early to Middle Devonian time (???400 to ???381 Ma). The Graham Lake thrust sheet contains possible Precambrian rocks, Cambrian sedimentary rocks with a volcanic unit dated at ???503 Ma, and Ordovician rocks with possible Caradocian Old World fossils, metamor& phosed and deformed in Silurian time and intruded by mildly to undeformed Late Silurian (???421 Ma) and Late Devonian (???371 to ???368 Ma) plutons. The Clarry Hill thrust sheet consists of poorly studied, highly metamorphosed Cambrian(?) rocks. The Clam Cove thrust sheet contains highly deformed Precambrian limestone, shale, sandstone, and conglomerate, metamorphosed to epidote amphibolite facies and intruded by a mildly deformed pluton dated at ???421 Ma. Metamorphism, deformation, and voluminous intrusive igneous activity of Silu& rian age are common to both the most southeastern parts of Medial New England and the thrust sheets of Composite Avalon. In contrast to Medial New England, the thrust sheets of Composite Avalon show only modest effects of Devonian deformation and metamorphism. Regional stratigraphic relations, paleontologic findings, and U-Pb geochronology suggest that the Graham Lake, Clarry Hill, and Clam Cove thrust sheets are far-traveled allochthons that were widely separated from Medial New England in the Silurian.

Patrick Draw field, Wyoming - 1 seismic expression of subtle strat trap in Upper Cretaceous Almond

USGS Publications Warehouse

Ryder, Robert T.; Lee, Myung W.; Agena, Warren F.; Anderson, Robert C.

1990-01-01

The east flank of the Rock Springs uplift and the adjacent Wamsutter arch contain several large hydrocarbon accumulations. Among these accumulations are Patrick Draw field, which produces oil and gas from a stratigraphic trap in the Upper Cretaceous Almond formation, and Table Rock field, a faulted anticlinal trap that produces gas from multiple Tertiary, Mesozoic, and Paleozoic reservoirs. The principal petroleum reservoir in Patrick Draw field is a sandstone at the top of the Almond formation. This sandstone attains a maximum thickness of 35ft and piches out westward into relatively impervious silt-stone and shale that constitute the trapping facies. The objective of this investigation is to determine whether or not the stratigraphic trap at Patrick Draw can be detected on a 12 fold, common depth point seismic profile acquired by Forest Oil Corp. and its partners. The seismic line is 18.5 miles long and crosses Patrick Draw and Table Rock fields.

The tectonic evolution of western Central Iran seen through detrital white mica

NASA Astrophysics Data System (ADS)

Kargaranbafghi, Fariba; Neubauer, Franz; Genser, Johann

2015-05-01

A first order survey of 40Ar/39Ar dating of detrital white mica from Jurassic to Pliocene sandstones has been carried out in order to reveal the tectonic evolution of blocks in Central Iran. The Central Iran block was believed to represent a stable Precambrian block. Our results indicate that: (1) Only a very small proportion of Precambrian but abundant Paleozoic and Mesozoic detrital white mica indicate the Phanerozoic, mostly Mesozoic age of metamorphic crust exposed in Central Iran. The oldest but scarce detrital white mica grains have ages ranging from 524 to 826 Ma heralding a Late Precambrian and Cambrian crystalline basement or cannibalism from older clastic successions. (2) Jurassic and Cretaceous sandstones from the west and east of the Chapedony fault yield different age spectra, with a dominance of Variscan ages (ca. 308-385 Ma) in the Biabanak unit west of the Chapedony fault compared to coeval sandstones from the block east of the Chapedony fault, where Variscan ages are subordinate and Cimmerian ages predominate. The micas from the Biabanak unit are most likely derived from the Variscan accretionary complex exposed in the Anarak-Jandaq areas further northwest. This result underlines the importance of a major block boundary identified as the Chapedony fault, which is in extension of a fault previously proposed. (3) Two stages of Cimmerian events are visible in our data set from Cretaceous and Paleogene sandstones, a cluster around 170 Ma and at ca. 205 Ma. These clusters suggest a two-stage Cimmerian evolution of the largely amphibolite-grade metamorphic Posht-e-Badam and Boneh Shurow complexes. (4) The youngest micas in Paleogene conglomerates have an age of ca. 100 Ma and are most likely derived from the base of the Posht-e-Badam complex. No record of the uplifted Eocene Chapedony metamorphic core complex has been found in Eocene and Pliocene clastic rocks.

The IRETHERM Project: How Can We Characterize Geothermal Reservoirs in Ireland using Magnetotelluric Surveying?

NASA Astrophysics Data System (ADS)

Delhaye, R. P.; Jones, A. G.; Rath, V.; Brown, C.; Reay, D.

2014-12-01

We present results from two geophysical investigations of the north of Ireland, one of a concealed sedimentary basin and the other of an area of pre- to mid-Cambrian metasedimentary material with local microseismicity in Donegal. Magnetotelluric data have been acquired over each area as part of the IRETHERM Project in order to assess potential low-enthalpy geothermal resources. In addition, airborne frequency-domain EM response data have been used to assist in the definition of near-surface electrical structure and constraint of magnetotelluric modeling. The Rathlin Basin in Northern Ireland was identified as a potential geothermal resource due both an elevated geothermal gradient (observed in two deep boreholes) and favorable hydraulic properties in thick successions of Permian and Triassic sandstones (measured from core samples). Prior seismic experiments failed to fully image the sediments beneath the overlying flood basalt. A new experiment applying the magnetotelluric method has had more success, as the MT signal is not dissipated by the crystalline overburden. MT data were acquired at 69 sites across the north-eastern portion of the onshore Rathlin Basin and on nearby Rathlin Island in order to image the thickness, depth, and lateral continuity of the target sediments. Analyses and modeling of the data have determined a resistivity model that maps the variation in thickness of the sediment fill and the truncation of the sediments against the structurally-controlling Tow Valley Fault. Further testing of the model sensitivity to variations of the thickness of the Sherwood Sandstone Group within the sediment fill has also been performed, as the overlying sediments have lower porosities and permeabilities from core sampling. Microseismicity in a metasedimentary area of northern Donegal suggests that secondary porosity distributions along fracture planes may have been augmented, leading to elevated electrical conductivity. MT data were acquired over the epicenter and surrounding of a M2.2 earthquake that occurred on 26/01/2012, with both audio-MT and broadband MT data acquired at 59 sites, and solely AMT data at the remaining 29 sites. Forward and inverse modeling of the data have been performed to search for fine conductive structures within the bedrock, as well as to model the general subsurface structure.

Recovery Act: Understanding the Impact of CO 2 Injection on the Subsurface Microbial Community in an Illinois Basin CCS Reservoir: Integrated Student Training in Geoscience and Geomicrobiology

DOE Office of Scientific and Technical Information (OSTI.GOV)

Fouke, Bruce

An integrated research and teaching program was developed to provide cross--disciplinary training opportunities in the emerging field of carbon capture and storage (CCS) for geobiology students attending the University of Illinois Urbana-­Champaign (UIUC). Students from across the UIUC campus participated, including those from the departments of Geology, Microbiology, Biochemistry, Civil and Environmental Engineering, Animal Sciences and the Institute for Genomic Biology. The project took advantage of the unique opportunity provided by the drilling and sampling of the large-­scale Phase III CCS demonstration Illinois Basin - Decatur Project (IBDP) in the central Illinois Basin at nearby Decatur, Illinois. The IBPD ismore » under the direction of the Illinois State Geological Survey (ISGS, located on the UIUC campus) and the Midwest Geological Sequestration Consortium (MGSC). The research component of this project focused on the subsurface sampling and identification of microbes inhabiting the subsurface Cambrian-­age Mt. Simon Sandstone. In addition to formation water collected from the injection and monitoring wells, sidewall rock cores were collected and analyzed to characterize the cements and diagenetic features of the host Mt. Simon Sandstone. This established a dynamic geobiological framework, as well as a comparative baseline, for future studies of how CO 2 injection might affect the deep microbial biosphere at other CCS sites. Three manuscripts have been prepared as a result of these activities, which are now being finalized for submission to top-­tier international peer-­reviewed research journals. The training component of this project was structured to ensure that a broad group of UIUC students, faculty and staff gained insight into CCS issues. An essential part of this training was that the UIUC faculty mentored and involved undergraduate and graduate students, as well as postdocs and research scientists, at all stages of the project in order to develop CCS-­focused classroom and field courses, as well as seminars. This program provided an excellent opportunity for participants to develop the background necessary to establish longer-­term research in CCS-­related geology and microbial ecology. Further, the program provided an ongoing dynamic platform to foster long-term collaboration with the regional ISGS and MGSC sequestration partnership, while offering hands-­on, applied learning experiences.« less

Stress-dependent permeability evolution in sandstones with anisotropic physical properties

NASA Astrophysics Data System (ADS)

Metz, V.; David, C.; Louis, L.; Rodriguez Rey, A.; Ruiz de Argandona, V. G.

2003-04-01

Fluid flow in reservoir rocks is strongly dependent on stress path and rock microstructure which may present a significant anisotropy. We present recent experimental data on the evolution of permeability with applied stress for three sandstones tested under triaxial conditions in the low confining pressure range (<10 MPa). Samples with diameter 40 mm and length 80 mm were cored in three orthogonal directions in blocks retrieved from quarries. One coring direction was perpendicular to the bedding plane whereas the other directions were arbitrarily chosen within the bedding plane. The selected rocks are the Bentheim sandstone (BNT), a quartz-rich cretaceous sandstone from Germany with 24% porosity, and two different varieties of a same jurassic formation in Northern Spain, the La Marina sandstone. The Yellow La Marina sandstone (YLM) with porosity 28% has a low cohesion and is the weathered form of the well-consolidated Grey La Marina sandstone (GLM) with porosity 17%. When loaded up to the failure stress, the more porous sandstones (BNT, YLM) exhibited a monotonic decrease of permeability even when the rock was dilating at deviatoric stresses close to the failure stress. On the other hand the permeability of the less porous sandstone (GLM) increased during the dilating phase. These results are in agreement with previous studies. In addition we observed that all three sandstones are anisotropic with respect to several physical properties including permeability. We systematically found a lower permeability in the direction perpendicular to the bedding plane, but the ratio of "vertical" to "horizontal" permeability varies from one sandstone to the other. The permeability anisotropy is compared to the anisotropy of electrical conductivity, acoustic velocity, capillary imbibition and elastic moduli: in general good correlations are found for all the properties. For the Bentheim sandstone, a microstructural study on thin sections revealed that the rock anisotropy is due to the anisotropy of intergranular pores which statistically are found to be elongated within the bedding plane. This result is in agreement with the prediction of Kachanov's model for the anisotropy of acoustic velocity in Bentheim sandstone.

Experimental Investigation on Dilation Mechanisms of Land-Facies Karamay Oil Sand Reservoirs under Water Injection

NASA Astrophysics Data System (ADS)

Lin, Botao; Jin, Yan; Pang, Huiwen; Cerato, Amy B.

2016-04-01

The success of steam-assisted gravity drainage (SAGD) is strongly dependent on the formation of a homogeneous and highly permeable zone in the land-facies Karamay oil sand reservoirs. To accomplish this, hydraulic fracturing is applied through controlled water injection to a pair of horizontal wells to create a dilation zone between the dual wells. The mechanical response of the reservoirs during this injection process, however, has remained unclear for the land-facies oil sand that has a loosely packed structure. This research conducted triaxial, permeability and scanning electron microscopy (SEM) tests on the field-collected oil sand samples. The tests evaluated the influences of the field temperature, confining stress and injection pressure on the dilation mechanisms as shear dilation and tensile parting during injection. To account for petrophysical heterogeneity, five reservoir rocks including regular oil sand, mud-rich oil sand, bitumen-rich oil sand, mudstone and sandstone were investigated. It was found that the permeability evolution in the oil sand samples subjected to shear dilation closely followed the porosity and microcrack evolutions in the shear bands. In contrast, the mudstone and sandstone samples developed distinct shear planes, which formed preferred permeation paths. Tensile parting expanded the pore space and increased the permeability of all the samples in various degrees. Based on this analysis, it is concluded that the range of injection propagation in the pay zone determines the overall quality of hydraulic fracturing, while the injection pressure must be carefully controlled. A region in a reservoir has little dilation upon injection if it remains unsaturated. Moreover, a cooling of the injected water can strengthen the dilation potential of a reservoir. Finally, it is suggested that the numerical modeling of water injection in the Karamay oil sand reservoirs must take into account the volumetric plastic strain in hydrostatic loading.

Three-dimensional geologic model of the Arbuckle-Simpson aquifer, south-central Oklahoma

USGS Publications Warehouse

Faith, Jason R.; Blome, Charles D.; Pantea, Michael P.; Puckette, James O.; Halihan, Todd; Osborn, Noel; Christenson, Scott; Pack, Skip

2010-01-01

The Arbuckle-Simpson aquifer of south-central Oklahoma encompasses more than 850 square kilometers and is the principal water resource for south-central Oklahoma. Rock units comprising the aquifer are characterized by limestone, dolomite, and sandstones assigned to two lower Paleozoic units: the Arbuckle and Simpson Groups. Also considered to be part of the aquifer is the underlying Cambrian-age Timbered Hills Group that contains limestone and sandstone. The highly faulted and fractured nature of the Arbuckle-Simpson units and the variable thickness (600 to 2,750 meters) increases the complexity in determining the subsurface geologic framework of this aquifer. A three-dimensional EarthVision (Trademark) geologic framework model was constructed to quantify the geometric relationships of the rock units of the Arbuckle-Simpson aquifer in the Hunton anticline area. This 3-D EarthVision (Trademark) geologic framework model incorporates 54 faults and four modeled units: basement, Arbuckle-Timbered Hills Group, Simpson Group, and post-Simpson. Primary data used to define the model's 54 faults and four modeled surfaces were obtained from geophysical logs, cores, and cuttings from 126 water and petroleum wells. The 3-D framework model both depicts the volumetric extent of the aquifer and provides the stratigraphic layer thickness and elevation data used to construct a MODFLOW version 2000 regional groundwater-flow model.

Geology and structural evolution of the Muruntau gold deposit, Kyzylkum desert, Uzbekistan

USGS Publications Warehouse

Drew, L.J.; Berger, B.R.; Kurbanov, N.K.

1996-01-01

The Muruntau gold deposit in the Kyzylkum desert of Uzbekistan is the largest single deposit (??? 1100 tonnes of gold) of the class of low-sulfide syndeformation/synigenous gold deposits formed in the brittle/ductile transition zone of the crust within transpressional shear zones. Hosted by the Cambrian to Ordovician Besopan Suite, the ores were deposited in pre-existing thrust-fault- and metamorphism-related permeabilities and in synmineralization dilational zones created in a large fault-related fold. The Besopan Suite is a 5,000-m-thick sequence of turbiditic siltstones, shales and sandstones. The ore is primarily localized at the base of the Besopan-3 unit, which is a 2,000-m-thick series of carbonaceous shales, siltstones, sandstones and cherts. Initial gold deposition took place within the Sangruntau-Tamdytau shear zone, which was developed along the stratigraphic contact between the Besopan-3 and Besopan-4 units. During the mineralization process, folding of the Besopan Suite and a left-step adjustment in the Sangruntau-Tamdytau shear zone were caused by two concurrent events: (1) the activation of the left-lateral Muruntau-Daugyztau shear zone that developed at nearly a 90?? angle to the preceding shear zone and (2) the intrusion of granitoid plutons. These structural events also resulted in the refocusing of hydrothermal fluid flow into new zones of permeability.

Deposition model of a Miocene barred wave- and storm-dominated shoreface and shelf, southeastern Malay basin, offshore west Malaysia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ramli, N.

1986-01-01

The J sandstone is an important hydrocarbon-bearing reservoir in the southeastern part of the Malay basin. The lower and upper members of the J sandstone are composed of shoreface and offshore sediments. The shoreface sequence contains depositional structures characteristic of a barred wave- and storm-dominated shoreface. Each shoreface sequence is laterally associated with a series of stacked offshore bars. Offshore bars can be subdivided into proximal and distal types. Two types of proximal offshore bars have been identified: (1) proximal bars formed largely above fair-weather wave base (inner proximal bars), and (2) proximal bars formed below fair-weather wave base (outermore » proximal bars). The inner proximal bars are closely associated with the shoreface sequence and are similar to the middle and lower shoreface. The presence of poorly sorted, polymodal, very fine to very coarse-grained sandstone beneath well-sorted crestal sandstones of inner proximal bars suggests that these offshore bars may have been deposited rapidly by storms. The crests of the inner proximal offshore bars were subsequently reworked by fair-weather processes, and the crests of the outer proximal and distal offshore bars were reworked by waning storm currents and oscillatory waves. Thick marine shales overlying offshore bars contain isolated sheet sandstones. Each sheet sandstone exhibits features that may be characteristic of distal storm shelf deposits. 15 figures, 2 tables.« less

ANALYSIS OF OIL-BEARING CRETACEOUS SANDSTONE HYDROCARBON RESERVOIRS, EXCLUSIVE OF THE DAKOTA SANDSTONE, ON THE JICARILLA APACHE INDIAN RESERVATION, NEW MEXICO

DOE Office of Scientific and Technical Information (OSTI.GOV)

Jennie Ridgley

2000-01-21

An additional 450 wells were added to the structural database; there are now 2550 wells in the database with corrected tops on the Juana Lopez, base of the Bridge Creek Limestone, and datum. This completes the structural data base compilation. Fifteen oil and five gas fields from the Mancos-ElVado interval were evaluated with respect to the newly defined sequence stratigraphic model for this interval. The five gas fields are located away from the structural margins of the deep part of the San Juan Basin. All the fields have characteristics of basin-centered gas and can be considered as continuous gas accumulationsmore » as recently defined by the U.S. Geological Survey. Oil production occurs in thinly interbedded sandstone and shale or in discrete sandstone bodies. Production is both from transgressive and regressive strata as redefined in this study. Oil production is both stratigraphically and structurally controlled with production occurring along the Chaco slope or in steeply west-dipping rocks along the east margin of the basin. The ElVado Sandstone of subsurface usage is redefined to encompass a narrower interval; it appears to be more time correlative with the Dalton Sandstone. Thus, it was deposited as part of a regressive sequence, in contrast to the underlying rock units which were deposited during transgression.« less

Iron Isotopes in Spherical Hematite and Goethite Concretions from the Navajo Sandstone (Utah, USA): A Prospective Study for "Martian Blueberries"

NASA Astrophysics Data System (ADS)

Busigny, V.; Dauphas, N.

2006-03-01

Iron isotopes of terrestrial hematite and goethite concretions provide clues on fluid transport, reservoir sizes, redox variations and biotic versus abiotic processes. This opens several avenues of research for future work on Martian blueberries.

Application of magnetic techniques to lateral hydrocarbon migration - Lower Tertiary reservoir systems, UK North Sea

NASA Astrophysics Data System (ADS)

Badejo, S. A.; Muxworthy, A. R.; Fraser, A.

2017-12-01

Pyrolysis experiments show that magnetic minerals can be produced inorganically during oil formation in the `oil-kitchen'. Here we try to identify a magnetic proxy that can be used to trace hydrocarbon migration pathways by determining the morphology, abundance, mineralogy and size of the magnetic minerals present in reservoirs. We address this by examining the Tay formation in the Western Central Graben in the North Sea. The Tertiary sandstones are undeformed and laterally continuous in the form of an east-west trending channel, facilitating long distance updip migration of oil and gas to the west. We have collected 179 samples from 20 oil-stained wells and 15 samples from three dry wells from the British Geological Survey Core Repository. Samples were selected based on geological observations (water-wet sandstone, oil-stained sandstone, siltstones and shale). The magnetic properties of the samples were determined using room-temperature measurements on a Vibrating Sample Magnetometer (VSM), low-temperature (0-300K) measurements on a Magnetic Property Measurement System (MPMS) and high-temperature (300-973K) measurements on a Kappabridge susceptibility meter. We identified magnetite, pyrrhotite, pyrite and siderite in the samples. An increasing presence of ferrimagnetic iron sulphides is noticed along the known hydrocarbon migration pathway. Our initial results suggest mineralogy coupled with changes in grain size are possible proxies for hydrocarbon migration.

Impact of fluid injection velocity on CO2 saturation and pore pressure in porous sandstone

NASA Astrophysics Data System (ADS)

Kitamura, Keigo; Honda, Hiroyuki; Takaki, Shinnosuke; Imasato, Mitsunori; Mitani, Yasuhiro

2017-04-01

The elucidation of CO2 behavior in sandstone is an essential issue to understand the fate of injecting CO2 in reservoirs. Injected CO2 invades pore spaces and replaces with resident brine and forms complex two-phase flow with brine. It is considered that this complex CO2 flow arises CO2 saturation (SCO_2)and pore fluid pressure(Pp) and makes various types of CO2 distribution pattern in pore space. The estimation of SCO_2 in the reservoir is one of important task in CCS projects. Fluid pressure (Pp) is also important to estimate the integrity of CO2 reservoir and overlying cap rocks. Generally, elastic waves are used to monitor the changes of SCO_2. Previous experimental and theoretical studies indicated that SCO_2 and Pp are controlled by the fluid velocity (flow rate) of invaded phase. In this study, we conducted the CO2 injection test for Berea sandstone (φ=18.1{%}) under deep CO2 reservoir conditions (confining pressure: 20MPa; temperature: 40 rC). We try to estimate the changes of SCO_2 and Pp with changing CO2 injection rate (FR) from 10 to 5000 μ l/min for Berea sandstone. P-wave velocities (Vp) are also measured during CO2 injection test and used to investigate the relationships between SCO2 and these geophysical parameters. We set three Vp-measurement channels (ch.1, ch2 and ch.3 from the bottom) monitor the CO2 behavior. The result shows step-wise SCO_2 changes with increasing FR from 9 to 25 {%} in low-FR condition (10-500 μ l/min). Vp also shows step wise change from ch1 to ch.3. The lowermost channel (ch.1) indicates that Vp-reduction stops around 4{%} at 10μ m/min condition. However, ch.3 changes slightly from 4{%} at 10 μ l/min to 5{%} at 100 μ l/min. On the other hand, differential Pp (Δ P) dose not shows obvious changes from 10kPa to 30kPa. Over 1000 μ l/min, SCO_2 increases from 35 to 47 {%}. Vp of all channels show slight reductions and Vp-reductions reach constant values as 8{%}, 6{%} and 8{%}, respectively at 5000{}μ l/min. On the other hand, Δ P shows rapid increasing from 50kPa to 500 kPa. It suggests a drastic change of CO2 behavior with injection rate. CO2 flows gently and enlarges SCO_2up to 25 {%} under low FR conditions without arisen Δ P (

Using sequence stratigraphic approaches in a highly tectonic area: Case study - Nubia (A) sandstone in southwestern Gulf of Suez, Egypt

NASA Astrophysics Data System (ADS)

Attia, Ibrahem; Helal, Iman; El Dakhakhny, Alaa; Aly, Said A.

2017-12-01

West Esh El Mallaha area is located west of the Hurghada shoreline. It pertains to the southwestern province of the Gulf of Suez. Nubia (A) sandstone is one of the prolific reservoirs in the western side along the Gulf of Suez area. To enhance further oil production and to develop this reservoir, it is important to gain a clear understanding of the reservoir in terms of its depositional origin. In west Esh El Mallaha area, the understanding of the depositional setting of Nubia (A) is relatively hard due to the limited number of cores. A comprehensive workflow which integrates all geological datasets (electrical logs pattern, the high resolution biostratigraphic analysis, and previous studies) which has been performed for the Nubia (A), enables to recognize different patterns of electrical logs, which are used to define the sequence stratigraphy and systems tracts for Nubia (A). The Lower Nubia (A) is characterized by fining-upward profile and well-developed coarsening-straight profile interpreted as a braided - fluvial facies (lowstand system tract). On the other hand, the upper Nubia (A) is characterized by fining-upward, coarsening-upward, and bell profile interpreted as meandering fluvial to fluvio-dominated delta (transgressive system tract). This study is an approach to build a reliable geological model, and give wide view to evaluate and develop the reservoir in the drilled areas and predict sand distribution in the undrilled areas despite the limited number of cores.

Anatomy of a lower Mississippian oil reservoir, West Virginia, United States

DOE Office of Scientific and Technical Information (OSTI.GOV)

Patchen, D.; Hohn, M.E.; McDowell, R.

1993-09-01

Several lines of evidence indicate that the oil reservoir in Granny Creek field is compartmentalized due to internal heterogeneities: an analysis of initial open flows vs. year completed and well location; mapping of initial open flows and cumulative production; and the nonuniform behavior of injection pressures and rates in waterflood patterns. The Big Injun sandstones includes an upper, coarse-grained, fluvial channel facies, and a lower, fine-grained, distributary mouthbar facies. The bar facies is the main reservoir, and can be subdivided into crest, distal, and proximal subfacies. Low original porosity and permeability in the poorly sorted channel facies was reduced furthermore » by quartz cementation. In contrast, chlorite coatings restricted quartz cementation and preserved porosity and permeability in the proximal bar subfacies. Small, low-amplitude folds plunge northeastward on the flank of the main syncline in which the fields is located. These minor structural highs seem to match areas of high initial open flows and cumulative production. High production also occurs where the distal and marine-influenced, proximal mouth-bar subfacies pinch out against at least a few feet of the relatively impremeable channel facies. Lower production is associated with (1) thin areas of proximal mouth-bar subfacies; (2) a change from marine to fluvial dominance of the bar facies, which is accompanied by a reduction in porosity and permeability; and (3) loss of the less permeable channel facies above the porous reservoir sandstone, due to downcutting by regional erosion that produced a post-Big Injun unconformity.« less

The Noble Gas Record of Gas-Water Phase Interaction in the Tight-Gas-Sand Reservoirs of the Rocky Mountains

NASA Astrophysics Data System (ADS)

Ballentine, C. J.; Zhou, Z.; Harris, N. B.

2015-12-01

The mass of hydrocarbons that have migrated through tight-gas-sandstone systems before the permeability reduces to trap the hydrocarbon gases provides critical information in the hydrocarbon potential analysis of a basin. The noble gas content (Ne, Ar, Kr, Xe) of the groundwater has a unique isotopic and elemental composition. As gas migrates through the water column, the groundwater-derived noble gases partition into the hydrocarbon phase. Determination of the noble gases in the produced hydrocarbon phase then provides a record of the type of interaction (simple phase equilibrium or open system Rayleigh fractionation). The tight-gas-sand reservoirs of the Rocky Mountains represent one of the most significant gas resources in the United States. The producing reservoirs are generally developed in low permeability (averaging <0.1mD) Upper Cretaceous fluvial to marginal marine sandstones and commonly form isolated overpressured reservoir bodies encased in even lower permeability muddy sediments. We present noble gas data from producing fields in the Greater Green River Basin, Wyoming; the the Piceance Basin, Colorado; and in the Uinta Basin, Utah. The data is consistent from all three basins. We show how in each basin the noble gases record open system gas migration through a water column at maximum basin burial. The data within an open system model indicates that the gas now in-place represents the last ~10% of hydrocarbon gas to have passed through the water column, most likely prior to permeability closedown.

Isotopic and geochemical characterization of fossil brines of the Cambrian Mt. Simon Sandstone and Ironton-Galesville Formation from the Illinois Basin, USA

NASA Astrophysics Data System (ADS)

Labotka, Dana M.; Panno, Samuel V.; Locke, Randall A.; Freiburg, Jared T.

2015-09-01

Geochemical and isotopic characteristics of deep-seated saline groundwater provide valuable insight into the origin and evolving composition, water-rock interaction, and mixing potential of fossil brines. Such information may yield insight into intra- and interbasinal brine movement and relationships between brine evolution and regional groundwater flow systems. This investigation reports on the δ18O and δD composition and activity values, 87Sr/86Sr ratios and Sr concentrations, and major ion concentrations of the Cambrian-hosted brines of the Mt. Simon Sandstone and Ironton-Galesville Formation and discusses the evolution of these brines as they relate to other intracontinental brines. Brines in the Illinois Basin are dominated by Na-Ca-Cl-type chemistry. The Mt. Simon and overlying Ironton-Galesville brines exhibit total dissolved solids concentrations of ∼195,000 mg/L and ∼66,270 mg/L, respectively. The δD of brine composition of the Mt. Simon ranges from -34‰ to -22‰ (V-SMOW), and the Ironton-Galesville is ∼-53.2‰ (V-SMOW). The δ18O composition of the Mt. Simon brine ranges from -5.0‰ to -2.8‰ (V-SMOW), and the Ironton-Galesville brine is ∼-6.9‰ (V-SMOW). The 87Sr/86Sr values in the Mt. Simon brine range from 0.7110 to 0.7116. The less radiogenic Ironton-Galesville brine has an average 87Sr/86Sr value of 0.7107. Evaluation of δ18O and δD composition and activities and 87Sr/86Sr ratios suggests that the Mt. Simon brine is likely connate seawater and recirculating deep-seated brines that have been diluted with meteoric water and influenced by the dissolution of evaporites with a minimal halite contribution based on Cl/Br ratios. The Ironton-Galesville brine is also likely originally connate seawater that mixed with other brines and meteoric waters, including possibly Pleistocene glacial recharge. The Ca-excess vs. Na-deficiency comparison with the Basinal Fluid Line suggests the Mt. Simon and Ironton-Galesville brines have been influenced by the effects of albitization and plot very close to the Basinal Fluid Line. These Cambrian-hosted brines appear to have a different albitization history than other regional basin brines and a strong component of seawater. The Ironton-Galesville brine appears more geochemically associated with other Illinois Basin brines than the Mt. Simon brine which appears more geochemically conservative. Comparisons with other extrabasinal North American brines suggest that the Michigan basin brines are geochemically most similar to the Mt. Simon brines with the exception of the influence from carbonates in the Michigan Basin. Analyses of 87Sr/86Sr values in the Mt. Simon brine suggest that brine Sr has isotopically equilibrated with clay minerals in the Lower Mt. Simon and underlying bedrock formations and not with whole rock suggesting the influence of recirculating brines from the crystalline basement. Overall, the geochemistry of these Cambrian-hosted brines suggests an evolution from original seawater-like compositions. This investigation shows that intracratonic basins do not behave as closed systems but can be strongly affected by water-rock interaction and regional groundwater flow systems that circulate deep crystalline basement brines and brines from nearby basins.

Faulted shoreline and tidal deposits in the Moenkopi Formation of the Grassy Trail Creek field, Utah

DOE Office of Scientific and Technical Information (OSTI.GOV)

Allison, M.L.; Lutz, S.J.

1991-06-01

The Grassy Trail Creek field produces 40{degrees} API oil and minor gas from shallow marine sandstones of the Triassic Moenkopi Formation on the north-plunging nose of the San Rafael swell in central Utah. Production is controlled by a combination of stratigraphic variations and minor north-south-trending faults. Although fracture permeability enhances production of the reservoir, some faults act as barriers to fluid migration, segmenting the area into productive and dry fault blocks. Horizontal drilling techniques developed in this field in the early 1980s resulted in significantly better production. Log analyses indicate the main reservoir is a complex stack of this thinmore » tidal channel sandstones. Isochore maps of the A and B zones indicate thickened meanders that form localized reservoir pods that are vertically offset. The distribution of isochore thicks appears to represent deposition along a northwest-southeast-trending shoreline fed by sediments from the northeast. There is potential for field extensions in similar deposits along this paleoshoreline. The Moenkopi Formation, long thought to be self-sourcing, may contain oil generated in Precambrian sediments equivalent to the Late Proterozoic Chuar Group. Presence of this older oil would have required migration from Precambrian sedimentary rocks surrounding the San Rafael swell.« less

Thermal and pressure histories of the Malay Basin, offshore Malaysia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Yusoff, W.I.; Swarbrick, R.E.

1994-07-01

The Malay Basin is a Neogene intracratonic basin characterized by high heat flow and rapid sedimentation; moderate to high overpressure is common in deeper reservoirs. Thermal conductivity and temperature data from 55 wells have been used to reassess the areal and vertical heat-flow distribution within the basin. Anomalously high temperatures have been observed in some sandstone intervals above the overpressured reservoir section. A narrow to rather abrupt pressure transition zone could be recognized. All hydrocarbon-filled reservoirs seemed to be associated with high heat flow (i.e., about 90 mW/m[sup 2]). Overpressure in some wells is approaching critical fracture pressure (i.e., 0.85more » psi/ft. pressure gradient) in the region. In the central part of the basin, the overpressured sections are found within the shallower (<2000 m) hydrocarbon-bearing units. Selective studies of the temporal development of the pore pressure indicated that overpressure development is associated with episodes of rapid sedimentation. A preliminary fluid flow model supported by pressure modeling is proposed whereby hot fluids are currently being expelled from deeper overpressured sandstone and mudrocks through a fractured seal induced by overpressure. The latter is caused by relatively rapid burial since late Tertiary times. Hydrocarbon migration may have been aided by this fluid movement.« less

Differentiating pedogenesis from diagenesis in early terrestrial paleoweathering surfaces formed on granitic composition parent materials

USGS Publications Warehouse

Driese, S.G.; Medaris, L.G.; Ren, M.; Runkel, Anthony C.; Langford, R.P.

2007-01-01

Unconformable surfaces separating Precambrian crystalline basement and overlying Proterozoic to Cambrian sedimentary rocks provide an exceptional opportunity to examine the role of primitive soil ecosystems in weathering and resultant formation of saprolite (weathered rock retaining rock structure) and regolith (weathered rock without rock structure), but many appear to have been affected by burial diagenesis and hydrothermal fluid flow, leading some researchers to discount their suitability for such studies. We examine one modern weathering profile (Cecil series), four Cambrian paleoweathering profiles from the North American craton (Squaw Creek, Franklin Mountains, Core SQ-8, and Core 4), one Neoproterozoic profile (Sheigra), and one late Paleoproterozoic profile (Baraboo), to test the hypothesis that these paleoweathering profiles do provide evidence of primitive terrestrial weathering despite their diagenetic and hydrothermal overprinting, especially additions of potassium. We employ an integrated approach using (1) detailed thin-section investigations to identify characteristic pedogenic features associated with saprolitization and formation of well-drained regoliths, (2) electron microprobe analysis to identify specific weathered and new mineral phases, and (3) geochemical mass balance techniques to characterize volume changes during weathering and elemental gains and losses of major and minor elements relative to the inferred parent materials. There is strong pedogenic evidence of paleoweathering, such as clay illuviation, sepic-plasmic fabrics, redoximorphic features, and dissolution and alteration of feldspars and mafic minerals to kaolinite, gibbsite, and Fe oxides, as well as geochemical evidence, such as whole-rock losses of Na, Ca, Mg, Si, Sr, Fe, and Mn greater than in modern profiles. Evidence of diagenesis includes net additions of K, Ba, and Rb determined through geochemical mass balance, K-feldspar overgrowths in overlying sandstone sections, and K-feldspars with reaction rims in weathered basement. The sub-Cambrian paleoweathering profiles formed on granite are remarkably similar to modern weathering profiles formed on granite, in spite of overprinting by potassium diagenesis. ?? 2007 by The University of Chicago. All rights reserved.

Simulation of the mulltizones clastic reservoir: A case study of Upper Qishn Clastic Member, Masila Basin-Yemen

NASA Astrophysics Data System (ADS)

Khamis, Mohamed; Marta, Ebrahim Bin; Al Natifi, Ali; Fattah, Khaled Abdel; Lashin, Aref

2017-06-01

The Upper Qishn Clastic Member is one of the main oil-bearing reservoirs that are located at Masila Basin-Yemen. It produces oil from many zones with different reservoir properties. The aim of this study is to simulate and model the Qishn sandstone reservoir to provide more understanding of its properties. The available, core plugs, petrophysical, PVT, pressure and production datasets, as well as the seismic structural and geologic information, are all integrated and used in the simulation process. Eclipse simulator was used as a powerful tool for reservoir modeling. A simplified approach based on a pseudo steady-state productivity index and a material balance relationship between the aquifer pressure and the cumulative influx, is applied. The petrophysical properties of the Qishn sandstone reservoir are mainly investigated based on the well logging and core plug analyses. Three reservoir zones of good hydrocarbon potentiality are indicated and named from above to below as S1A, S1C and S2. Among of these zones, the S1A zone attains the best petrophysical and reservoir quality properties. It has an average hydrocarbon saturation of more than 65%, high effective porosity up to 20% and good permeability record (66 mD). The reservoir structure is represented by faulted anticline at the middle of the study with a down going decrease in geometry from S1A zone to S2 zone. It is limited by NE-SW and E-W bounding faults, with a weak aquifer connection from the east. The analysis of pressure and PVT data has revealed that the reservoir fluid type is dead oil with very low gas liquid ratio (GLR). The simulation results indicate heterogeneous reservoir associated with weak aquifer, supported by high initial water saturation and high water cut. Initial oil in place is estimated to be around 628 MM BBL, however, the oil recovery during the period of production is very low (<10%) because of the high water cut due to the fractures associated with many faults. Hence, secondary and tertiary methods are needed to enhance the oil recovery. Water flooding is recommended as the first step of oil recovery enhancement by changing some of high water cut wells to injectors.

Sedimentological and Stratigraphic Controls on Natural Fracture Distribution in Wajid Group, SW Saudi Arabia

NASA Astrophysics Data System (ADS)

Benaafi, Mohammed; Hariri, Mustafa; Abdullatif, Osman; Makkawi, Mohammed; Korvin, Gabor

2016-04-01

The Cambro-Permian Wajid Group, SW Saudi Arabia, is the main groundwater aquifer in Wadi Al-Dawasir and Najran areas. In addition, it has a reservoir potentiality for oil and natural gas in Rub' Al-Khali Basin. Wajid Group divided into four formations, ascending Dibsiyah, Sanamah, Khussyayan and Juwayl. They are mainly sandstone and exposed in an area extend from Wadi Al-Dawasir southward to Najran city and deposited within fluvial, shallow marine and glacial environments. This study aims to investigate the sedimentological and stratigraphic controls on the distribution of natural fractures within Wajid Group outcrops. A scanline sampling method was used to study the natural fracture network within Wajid Group outcrops, where the natural fractures were measured and characterized in 12 locations. Four regional natural fracture sets were observed with mean strikes of 050o, 075o, 345o, and 320o. Seven lithofacies characterized the Wajid Group at these locations and include fine-grained sandstone, coarse to pebbly sandstone, cross-bedded sandstone, massive sandstone, bioturbated sandstone, conglomerate sandstone, and conglomerate lithofacies. We found that the fine-grained and small scale cross-bedded sandstones lithofacies are characterized by high fracture intensity. In contrast, the coarse-grained sandstone and conglomerate lithofacies have low fracture intensity. Therefore, the relative fracture intensity and spacing of natural fractures within Wajid Group in the subsurface can be predicted by using the lithofacies and their depositional environments. In terms of stratigraphy, we found that the bed thickness and the stratigraphic architecture are the main controls on fractures intensity. The outcomes of this study can help to understand and predict the natural fracture distribution within the subsurface fractured sandstone hosting groundwater and hydrocarbon in Wajid and Rub' Al-Khali Basins. Hence, the finding of this study might help to explore and develop the groundwater and hydrocarbon resources in the subsurface.

Diagenesis and fracture development in the Bakken Formation, Williston Basin; implications for reservoir quality in the middle member

USGS Publications Warehouse

Pitman, Janet K.; Price, Leigh C.; LeFever, Julie A.

2001-01-01

The middle member of the Bakken Formation is an attractive petroleum exploration target in the deeper part of the Williston Basin because it is favorably positioned with respect to source and seal units. Progressive rates of burial and minor uplift and erosion of this member led to a stable thermal regime and, consequently, minor variations in diagenesis across much of the basin. The simple diagenetic history recorded in sandstones and siltstones in the middle member can, in part, be attributed to the closed, low-permeability nature of the Bakken petroleum system during most of its burial history. Most diagenesis ceased in the middle member when oil entered the sandstones and siltstones in the Late Cretaceous. Most oil in the Bakken Formation resides in open, horizontal fractures in the middle member. Core analysis reveals that sandstones and siltstones associated with thick mature shales typically have a greater density of fractures than sandstones and siltstones associated with thin mature shales. Fractures were caused by superlithostatic pressures that formed in response to increased fluid volumes in the source rocks during hydrocarbon generation

The effect of organic acids on wettability of sandstone and carbonate rocks

DOE Office of Scientific and Technical Information (OSTI.GOV)

Mwangi, Paulina; Brady, Patrick V.; Radonjic, Mileva

This paper examines the role of crude oil’s organic acid surface active compounds (SAC) in determining the reservoir wettability over a range of salinities and temperatures. To isolate the effects of individual SACs, this project used model oil mixtures of pure decane and single SACs to represent the oleic phase. Due to the large number of experiments in this study, we used wettability measurement method by the modified flotation technique (MFT) to produce fast, reliable, and quantitative results. The results showed that oil wetting by decane increased with temperature for carbonate rocks. Sandstones oil wetting showed little temperature dependency. Themore » presence of long-chained acids in decane increased oil wetting in sandstone and carbonate rocks as salinity was lowered, while the short-chained acid increased water wetting under the same conditions. The effect of organic acids on wettability was slightly enhanced with increasing temperature for all rock types.« less

The effect of organic acids on wettability of sandstone and carbonate rocks

DOE PAGES

Mwangi, Paulina; Brady, Patrick V.; Radonjic, Mileva; ...

2018-02-21

This paper examines the role of crude oil’s organic acid surface active compounds (SAC) in determining the reservoir wettability over a range of salinities and temperatures. To isolate the effects of individual SACs, this project used model oil mixtures of pure decane and single SACs to represent the oleic phase. Due to the large number of experiments in this study, we used wettability measurement method by the modified flotation technique (MFT) to produce fast, reliable, and quantitative results. The results showed that oil wetting by decane increased with temperature for carbonate rocks. Sandstones oil wetting showed little temperature dependency. Themore » presence of long-chained acids in decane increased oil wetting in sandstone and carbonate rocks as salinity was lowered, while the short-chained acid increased water wetting under the same conditions. The effect of organic acids on wettability was slightly enhanced with increasing temperature for all rock types.« less

Volcanic settings and their reservoir potential: An outcrop analog study on the Miocene Tepoztlán Formation, Central Mexico

NASA Astrophysics Data System (ADS)

Lenhardt, Nils; Götz, Annette E.

2011-07-01

The reservoir potential of volcanic and associated sedimentary rocks is less documented in regard to groundwater resources, and oil and gas storage compared to siliciclastic and carbonate systems. Outcrop analog studies within a volcanic setting enable to identify spatio-temporal architectural elements and geometric features of different rock units and their petrophysical properties such as porosity and permeability, which are important information for reservoir characterization. Despite the wide distribution of volcanic rocks in Mexico, their reservoir potential has been little studied in the past. In the Valley of Mexico, situated 4000 m above the Neogene volcanic rocks, groundwater is a matter of major importance as more than 20 million people and 42% of the industrial capacity of the Mexican nation depend on it for most of their water supply. Here, we present porosity and permeability data of 108 rock samples representing five different lithofacies types of the Miocene Tepoztlán Formation. This 800 m thick formation mainly consists of pyroclastic rocks, mass flow and fluvial deposits and is part of the southern Transmexican Volcanic Belt, cropping out south of the Valley of Mexico and within the two states of Morelos and Mexico State. Porosities range from 1.4% to 56.7%; average porosity is 24.8%. Generally, permeabilities are low to median (0.2-933.3 mD) with an average permeability of 88.5 mD. The lavas are characterized by the highest porosity values followed by tuffs, conglomerates, sandstones and tuffaceous breccias. On the contrary, the highest permeabilities can be found in the conglomerates, followed by tuffs, tuffaceous breccias, sandstones and lavas. The knowledge of these petrophysical rock properties provides important information on the reservoir potential of volcanic settings to be integrated to 3D subsurface models.

Secondary oil recovery from selected Carter sandstone oilfields--Black Warrior Basin, Alabama. Final report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Anderson, J.C.

1995-02-01

Producibility problems, such as low reservoir pressure and reservoir heterogeneity, have severely limited oil production from the Central Bluff and North Fairview fields. Specific objectives for this project were: To successfully apply detailed geologic and engineering studies with conventional waterflood technologies to these fields in an effort to increase the ultimate economic recovery of oil from Carter sandstone fields; To extensively model, test and evaluate these technologies; thereby, developing a sound methodology for their use and optimization; and To team with Advanced Resources International and the US DOE to assimilate and transfer the information and results gathered from this studymore » to other oil companies to encourage the widespread use of these technologies. At Central Bluff, water injection facilities were constructed and water injection into one well began in January 1993. Oil response from the waterflood has been observed at both producing wells. One of the producing wells has experienced early water breakthrough and a concomitant drop in secondary oil rate. A reservoir modeling study was initiated to help develop an appropriate operating strategy for Central Bluff. For the North Fairview unit waterflood, a previously abandoned well was converted for water injection which began in late June 1993. The reservoir is being re-pressurized, and unit water production has remained nil since flood start indicating the possible formation of an oil bank. A reservoir simulation to characterize the Carter sand at North Fairview was undertaken and the modeling results were used to forecast field performance. The project was terminated due to unfavorable economics. The factors contributing to this decision were premature water breakthrough at Central Bluff, delayed flood response at North Fairview and stalled negotiations at the South Bluff site.« less

Post waterflood CO{sub 2} miscible flood in light oil, fluvial-dominated deltaic reservoir. FY 1993 annual report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Davis, D.W.

1995-03-01

The project is a Class 1 DOE-sponsored field demonstration project of a CO{sub 2} miscible flood project at the Port Neches Field in Orange County, Texas. The project will determine the recovery efficiency of CO{sub 2} flooding a waterflooded and a partial waterdrive sandstone reservoir at a depth of 5,800. The project will also evaluate the use of a horizontal CO{sub 2} injection well placed at the original oil-water contact of the waterflooded reservoir. A PC-based reservoir screening model will be developed by Texaco`s research lab in Houston and Louisiana State University will assist in the development of a databasemore » of fluvial-dominated deltaic reservoirs where CO{sub 2} flooding may be applicable. This technology will be transferred throughout the oil industry through a series of technical papers and industry open forums.« less

Principales caractéristiques des réservoirs du Sud-Ouest tunisien

NASA Astrophysics Data System (ADS)

Chalbaoui, Moncef; Ben Dhia, Hamed

2004-10-01

A study of the form and characteristics of the reservoirs and aquifers of southwestern Tunisia has been carried out from 62 petroleum explorations and hydrogeologic wells and structural maps. The evolution of basins can be deduced from the tectonic history. The Jurassic reservoirs are represented by the Upper Nara carbonates. The petrophysical characteristics and the fracturation affecting the Nara carbonates reveal the existence of very good reservoirs. Several reservoirs have also been identified in the Lower Cretaceous. These reservoirs are made of sandy levels, interbedded with shale, carbonates and dolomites. In addition, petroleum and hydrogeologic studies have revealed that potential aquifers may occur in two provinces (near the Chott Basin and east-west faults). Most of the geological formations in the South West of Tunisia are composed of sand, sandstone and limestone, with the existence of real aquifers. To cite this article: M. Chalbaoui, H. Ben Dhia, C. R. Geoscience 336 (2004).

Ranking of Texas reservoirs for application of carbon dioxide miscible displacement

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ham, J

Of the 431 reservoirs screened, 211 projected revenue that exceeded cost, ie, were profitable. Only the top 154 reservoirs, however, showed a profit greater than 30%. The top 10 reservoirs predicted a profit of at least 80%. Six of the top ten were Gulf Coast sandstones. The reservoirs are representative of the most productive discoveries in Texas; they account for about 72% of the recorded 52 billion barrels oil production in the State. Preliminary evaluation in this study implied that potential production from CO{sub 2}-EOR could be as much as 4 billion barrels. In order to enhance the chances ofmore » achieving this, DOE should consider a targeted outreach program to the specific independent operators controlling the leases. Development of ownership/technical potential maps and an outreach program should be initiated to aid this identification.« less

The origin of decoupled carbonate and organic carbon isotope signatures in the early Cambrian (ca. 542-520 Ma) Yangtze platform

NASA Astrophysics Data System (ADS)

Jiang, Ganqing; Wang, Xinqiang; Shi, Xiaoying; Xiao, Shuhai; Zhang, Shihong; Dong, Jin

2012-02-01

The early Cambrian (ca. 542-520 Ma) strata in South China record two prominent negative carbonate carbon isotope (δ13Ccarb) excursions of early Nemakit-Daldynian (N-D) and early Tommotian ages. Across each of these excursions, carbonate and organic carbon isotopes (δ13Ccarb and δ13Corg) are strongly decoupled. Regional correlation across a shelf-to-basin transect shows lateral heterogeneity of δ13Corg during the early-middle N-D but more homogenized δ13Corg values across the basin during the late N-D and Tommotian. The temporal and lateral variations in δ13Corg suggest that decoupled δ13Ccarb and δ13Corg across the N-D δ13Ccarb excursion were possibly caused by diagenetic alteration of organic matter and/or amplification of detrital organic carbon isotope signature in low-TOC carbonates. In contrast, decoupled δ13Ccarb and δ13Corg of the upper N-D and Tommotian were likely resulted from chemoautotrophic-methanotrophic biomass contribution to TOC in organic-rich black shale and carbonates. The decoupled δ13Ccarb-δ13Corg pattern from the lower N-D strata (ca. 542 Ma) shows striking similarities with those from the basal (ca. 635 Ma) and upper (ca. 551 Ma) Doushantuo Formation. In all three cases, decoupled δ13Ccarb-δ13Corg are seen in organic-poor carbonates (TOC ≤ 0.1‰) and coupled δ13Ccarb-δ13Corg occur in organic-rich black shale and carbonates at the end of the negative δ13Ccarb excursion. These similarities suggest that the shift from decoupled to coupled δ13Ccarb-δ13Corg has no causal link with the terminal oxidation of a large oceanic DOC reservoir. Given the pervasive anoxia/euxinia in Ediacaran-early Cambrian oceans, local DOC-rich environments may have been common, but a large oceanic DOC reservoir capable of buffering the δ13C of marine organic matter requires independent evidence.

Kitty field, Campbell County, Wyoming

DOE Office of Scientific and Technical Information (OSTI.GOV)

Clark, C.R.

1970-09-01

Statistical data, a table of cumulative production, a production graph, and several maps and cross sections make up this report. This is a stratigraphic trap oil field with facies and permeability barriers within the Cretaceous Muddy Sandstone reservoir. The field produces from 2 sandstones with an average pay thickness of 28 ft. Cumulative production through the first 3 mo. of 1970 is 6,757,207 bbl of oil and 11,684,884 Mcf of gas from 127 wells and from proved productive area of 13,600 acres. Ultimate primary recovery reserves are estimated to be 23,000,000 bbl of oil and 50,000,000 Mcf gas.

Duration of mineralization and fluid-flow history of the Upper Mississippi Valley zinc-lead district

USGS Publications Warehouse

Rowan, E.L.; Goldhaber, M.B.

1995-01-01

Studies of fluid inclusions in sphalerite and biomarkers from the Upper Mississippi Valley zinc district show homogenization temperatures to be primarily between 90 and 150??C, yet show relatively low levels of thermal maturity. Numerical calculations are used to simulate fluid and heat flow through fracture-controlled ore zones and heat transfer to the adjacent rocks. Combining a best-fit path through fluid-inclusion data with measured thermal alteration of biomarkers, the time interval during which mineralizing fluids circulated through the Upper Mississippi Valley district was calculated to be on the order of 200 ka. Cambrian and Ordovician aquifers underlying the district, principally the St. Peter and Mt. Simon Sandstones, were the source of the mineralizing fluid. The duration of mineralization thus reflects the fluid-flow history of these regional aquifers. -from Authors

Physical properties of sidewall cores from Decatur, Illinois

USGS Publications Warehouse

Morrow, Carolyn A.; Kaven, Joern; Moore, Diane E.; Lockner, David A.

2017-10-18

To better assess the reservoir conditions influencing the induced seismicity hazard near a carbon dioxide sequestration demonstration site in Decatur, Ill., core samples from three deep drill holes were tested to determine a suite of physical properties including bulk density, porosity, permeability, Young’s modulus, Poisson’s ratio, and failure strength. Representative samples of the shale cap rock, the sandstone reservoir, and the Precambrian basement were selected for comparison. Physical properties were strongly dependent on lithology. Bulk density was inversely related to porosity, with the cap rock and basement samples being both least porous (

Local and Global Impacts of Carbon Capture and Storage Combined with Enhanced Oil Recovery in Four Depleted Oil Fields, Kern County, California

NASA Astrophysics Data System (ADS)

Gillespie, J.; Jordan, P. D.; Goodell, J. A.; Harrington, K.; Jameson, S.

2015-12-01

Depleted oil reservoirs are attractive targets for geologic carbon storage (GCS) because they possess proven trapping mechanisms and large amounts of data pertaining to production and reservoir geometry. In addition, CO2 enhanced oil recovery (EOR) can improve recovery of the remaining oil at recovery factors of 6 to 20% of original oil in place in appropriate reservoirs. CO2 EOR increases the attractiveness of depleted oil and gas reservoirs as a starting point for CCS because the CO2 becomes a commodity that can be purchased by field operators for EOR purposes thereby offsetting the costs of CO2 capture at the power plant. In California, Kern County contains the largest oil reservoirs and produces 76% of California's oil. Most of the production at depths suitable for CCS combined with CO2 EOR comes from three reservoirs: the Vedder and Temblor formations and the Stevens Sandstone of the Monterey Formation. These formations were evaluated for GCS and CO2 EOR potential at the North and South Coles Levee (Stevens Sandstone), Greeley (Vedder) and McKittrick (Temblor) fields. CO2 EOR could be expected to produce an additional 150 million bbls of oil. The total storage space created by pre- and post-EOR fluid production for all three reservoirs is approximately 104 million metric tons (MMT). Large fixed sources in California produce 156 MMT/yr of CO2, and sources in Kern County produce 26 MMT/yr (WESTCARB, 2012). Therefore, the fields could store about four years of local large fixed source emissions and about two thirds of statewide emissions. However, from a global perspective, burning the additional oil produced by CO2 EOR would generate an additional 65 MMT of CO2 if not captured. This would result in a net reduction of greenhouse gas of only 39 MMT rather than the full 104 MMT. If the water produced along with the oil recovered during CO2 EOR operations is not reinjected into the reservoir, the storage space could be much higher.

First account on the sedimentological, geochemical and petrophysical record of the Messinian Salinity Crisis in the subsurface of onshore Nile Delta, Egypt.

NASA Astrophysics Data System (ADS)

Leila, Mahmoud; Moscariello, Andrea

2016-04-01

The giant Cenozoic Nile Delta system in the extreme northern part of Egypt occupies the southeastern part of the Eastern Mediterranean Basin and represents the most prolific gas province in Egypt with estimates more than 62 tcf of proven reserves (Niazi and Dahi, 2004). Despite the importance of the Messinian sediments in the Nile Delta hosting excellent petroleum reservoirs and seals (Dolson et al., 2001), they are still poorly studied. A multidisciplinary sedimentological, geochemical and petrophysical study is being carried out to unravel the depositional environment and tectonic setting before, during and after the important Messinian Salinity Crisis (MSC) period in the Eastern Mediterranean, and how this affected the eastern part of the onshore Nile Delta. The Lower Messinian Qawasim Formation consists of high to low-density turbiditic sandstones displaying several vertical stacked patterns of coarsening and fining upwards trends reflecting different pulses of sedimentation suggesting a sedimentation in a submarine fan developed at the base of shelf slope. The deeply incised valley infill, dating the Upper Messinian consists of the Abu Madi Formation made of lowstand braided and meandering fluvial sandstone interbedded with fine-grained floodplain sandstones and siltstones. The base of this unit is erosional and contains large mud clasts embedded in a fine-grained matrix. The Upper Miocene lowstand fluvial sandstones are capped by estuarine fine-grained cross laminated sandstones, siltstones/mudstones followed by an open marine mudstones of the Early Pliocene Kafr El-Sheikh Formation representing the end of the MSC and the subsequent transgression episode after the re-establishment of the connection between the Mediterranean and the Atlantic Ocean. Both the Qawasim and Abu Madi Formations display similar geochemical fingerprints from the clastic components. Recycled Cretaceous and Eocene sedimentary and granodioritic to intermediate igneous rocks located in the Red Sea hills are considered to be the protolithites for the Miocene clastic rock. The depositional environment and diagenetic alterations enormously influenced the resulting composition and reservoir quality of the Miocene sandstones. Within the fluvial environmental conditions, early mechanical clay infiltration occurred that completely modified the original texture and porosity of the fluvial sandstones. In this unit the frequent transformation of feldspars into authigenic kaolinite, likely enhanced by favourable climatic conditions, also occurred. In general, the fluvial sandstones were subjected to more intense weathering than the turbiditic sandstones resulting in higher alteration indices (CIA and PIA). The sedimentological and geochemical data suggest that both depositional environments developed at the transition between the Lower Messinian and Early Pliocene, occurred in a passive margin setting likely at the edge of a shelf scarp, where the drastic drop in sea level resulted in the incision of a deep valley subsequently filled up during the Zanclean (?) transgression. References Niazi, M., Dahi, M., 2004. Unexplored giant sandstone features in ultra- deepwater, West Mediterranean, Egypt. In: American Association of Petroleum Geologists International Conference: October 24- 27, 2004; Cancun, Mexico. Dolson, J., Shann, M., Matbouly, S., Harwood, C., Rashed, R., Hammouda, H., 2001. The Petroleum Potential of Egypt, AAPG Memoir 74: 453- 482.

The Collyhurst Sandstone as a secondary storage unit for CCS in the East Irish Sea Basin (UK)

NASA Astrophysics Data System (ADS)

Gamboa, D.; Williams, J. D. O.; Kirk, K.; Gent, C. M. A.; Bentham, M.; Schofield, D. I.

2016-12-01

Carbon Capture and Storage (CCS) is key technology for low-carbon energy and industry. The UK hosts a large CO2 storage potential offshore with an estimated capacity of 78 Gt. The East Irish Sea Basin (EISB) is the key area for CCS in the western UK, with a CO2 storage potential of 1.7 Gt in hydrocarbon fields and in saline aquifers within the Triassic Sherwood Sandstone Formation. However, this theoretical storage capacity does not consider the secondary storage potential in the lower Permian Collyhurst Sandstone Formation. 3D seismic data were used to characterise the Collyhurst Sandstone Formation in the EISB. On the southern basin domain, numerous fault-bound blocks limit the lateral continuity of the sandstone strata, while on the northern domain the sandstones are intersected by less faults. The caprock for the Collyhurst sandstones is variable. The Manchester Marls predominate in the south, transitioning to the St. Bees evaporites towards the north. The evaporites in the EISB cause overburden faults to terminate or detach along Upper Permian strata, limiting the deformation of the underlying reservoir units. Five main storage closures have been identified in the Permian strata. In the southern and central area these are predominantly fault bounded, occurring at depths over 1000m. Despite the higher Collyhurst sandstone thickness in the southern IESB, the dolomitic nature of the caprock constitutes a storage risk in this area. Closures in the northern area are deeper (around 2000-2500m) and wider, reaching areas of 34Km2, and are overlain by evaporitic caprocks. The larger Collyhurst closures to the north underlie large Triassic fields with high storage potential. The spatial overlap favours storage plans including secondary storage units in the EISB. The results of this work also expand the understanding of prospective areas for CO2 sequestration in the East Irish Sea Basin in locations where the primary Sherwood Sandstone Formation is either too shallow, discontinuous or eroded.

Stratigraphic and structural distribution of reservoirs in Romania

DOE Office of Scientific and Technical Information (OSTI.GOV)

Stefanescu, M.O.

1991-08-01

In Romania, there are reservoirs at different levels of the whole Cambrian-Pliocene interval, but only some of these levels have the favorable structural conditions to accumulate hydrocarbons in commercial quantities. These levels are the Devonian, Triassic, Middle Jurassic, Lower Cretaceous (locally including the uppermost Jurassic), Eocene, Oligocene-lower Miocene, middle and upper Miocene, and Pliocene. The productive reservoirs are represented either by carbonate rocks (in Devonian, Middle Triassic and uppermost Jurassic-Lower Cretaceous) or by detrital rocks (in Lower and Upper Triassic, Middle Jurassic, Eocene, Oligocene, Miocene, and Pliocene). From the structural point of view, the Romanian territory is characterized by themore » coexistence both of platforms (East European, Scythian, and Moesian platforms) and of the strongly tectonized orogenes (North Dobrogea and Carpathian orogenes). Each importance crust shortening was followed by the accumulation of post-tectonic covers, some of them being folded during subsequently tectonic movements. The youngest post-tectonic cover is common both for the platforms (foreland) and Carpathian orogene, representing the Carpathian foredeep. Producing reservoirs are present in the East European and Moesian platforms, in the outer Carpathian units (Tarcau and Marginal folds nappes) and in certain post-tectonic covers which fill the Carpathian foredeep and the Transylvanian and Pannonian basins. In the platforms, hydrocarbons accumulated both in calcareous and detrital reservoirs, whereas in the Carpathian units and in their reservoirs, whereas in the Carpathian units and in their post-tectonic covers, hydrocarbons accumulated only in detrital reservoirs.« less

Significance of detrital zircons in upper Devonian ocean-basin strata of the Sonora allochthon and Lower Permian synorogenic strata of the Mina Mexico foredeep, central Sonora, Mexico

USGS Publications Warehouse

Poole, F.G.; Gehrels, G.E.; Stewart, John H.

2008-01-01

U-Pb isotopic dating of detrital zircons from a conglomeratic barite sandstone in the Sonora allochthon and a calciclastic sandstone in the Mina Mexico foredeep of the Minas de Barita area reveals two main age groups in the Upper Devonian part of the Los Pozos Formation, 1.73-1.65 Ga and 1.44-1.42 Ga; and three main age groups in the Lower Permian part of the Mina Mexico Formation, 1.93-1.91 Ga, 1.45-1.42 Ga, and 1.1-1.0 Ga. Small numbers of zircons with ages of 2.72-2.65 Ga, 1.30-1.24 Ga, ca. 2.46 Ga, ca. 1.83 Ga, and ca. 0.53 Ga are also present in the Los Pozos sandstone. Detrital zircons ranging in age from 1.73 to 1.65 Ga are considered to have been derived from the Yavapai, Mojave, and Mazatzal Provinces and their transition zones of the southwestern United States and northwestern Mexico. The 1.45-1.30 Ga detrital zircons were probably derived from scattered granite bodies within the Mojave and Mazatzal basement rocks in the southwestern United States and northwestern Mexico, and possibly from the Southern and Eastern Granite-Rhyolite Provinces of the southern United States. The 1.24-1.0 Ga detrital zircons are believed to have been derived from the Grenville (Llano) Province to the east and northeast or from Grenvilleage intrusions or anatectites to the north. Several detrital zircon ages ranging from 2.72 to 1.91 Ga were probably derived originally from the Archean Wyoming Province and Early Paleoproterozoic rocks of the Lake Superior region. These older detrital zircons most likely have been recycled one or more times into the Paleozoic sandstones of central Sonora. The 0.53 Ga zircon is believed to have been derived from a Lower Cambrian granitoid or meta-morphic rock northeast of central Sonora, possibly in New Mexico and Colorado, or Oklahoma. Detrital zircon geochronology suggests that most of the detritus in both samples was derived from Laurentia to the north, whereas some detritus in the Permian synorogenic foredeep sequence was derived from the evolving accretionary wedge to the south. Compositional and sedimentological differences between the continental-rise Los Pozos conglomeratic barite sandstone and the foredeep Mina Mexico calciclastic sandstone imply different depositional and tectonic settings. ?? 2008 The Geological Society of America.

Petrophysical characterization of first ever drilled core samples from an active CO2 storage site, the German Ketzin Pilot Site - Comparison with long term experiments

NASA Astrophysics Data System (ADS)

Zemke, Kornelia; Liebscher, Axel

2014-05-01

Petrophysical properties like porosity and permeability are key parameters for a safe long-term storage of CO2 but also for the injection operation itself. These parameters may change during and/or after the CO2 injection due to geochemical reactions in the reservoir system that are triggered by the injected CO2. Here we present petrophysical data of first ever drilled cores from a newly drilled well at the active CO2 storage site - the Ketzin pilot site in the Federal State of Brandenburg, Germany. By comparison with pre-injection baseline data from core samples recovered prior to injection, the new samples provide the unique opportunity to evaluate the impact of CO2 on pore size related properties of reservoir and cap rocks at a real injection site under in-situ reservoir conditions. After injection of 61 000 tons CO2, an additional well was drilled and new rock cores were recovered. In total 100 core samples from the reservoir and the overlaying caprock were investigated by NMR relaxation. Permeability of 20 core samples was estimated by nitrogen and porosity by helium pycnometry. The determined data are comparable between pre-injection and post-injection core samples. The lower part of the reservoir sandstone is unaffected by the injected CO2. The upper part of the reservoir sandstone shows consistently slightly lower NMR porosity and permeability values in the post-injection samples when compared to the pre-injection data. This upper sandstone part is above the fluid level and CO2 present as a free gas phase and a possible residual gas saturation of the cores distorted the NMR results. The potash-containing drilling fluid can also influence these results: NMR investigation of twin samples from inner and outer parts of the cores show a reduced fraction of larger pores for the outer core samples together with lower porosities and T2 times. The drill mud penetration depth can be controlled by the added fluorescent tracer. Due to the heterogeneous character of the Stuttgart Formation it is difficult to estimate definite CO2 induced changes from petrophysical measurements. The observed changes are only minor. Several batch experiments on Ketzin samples drilled prior injection confirm the results from investigation of the in-situ rock cores. Core samples of the pre-injection wells were exposed to CO2 and brine in autoclaves over various time periods. Samples were characterized prior to and after the experiments by NMR and Mercury Injection Porosimetry (MIP). The results are consistent with the logging data and show only minor change. Unfortunately, also in these experiments observed mineralogical and petrophysical changes were within the natural heterogeneity of the Ketzin reservoir and precluded unequivocal conclusions. However, given the only minor differences between post-injection well and pre-injection well, it is reasonable to assume that the potential dissolution-precipitation processes appear to have no severe consequences on reservoir and cap rock integrity or on the injection behaviour. This is also in line with the continuously recorded injection operation parameter. These do not point to any changes in reservoir injectivity.|

Development of deformation band clusters in porous quartz sandstones - Contribution from microstructural analysis and numerical modeling

NASA Astrophysics Data System (ADS)

Philit, S.; Soliva, R.; Chemenda, A. I.

2017-12-01

Because sandstones form good reservoirs for hydrocarbon, water or C02 storage, the understanding of the deformation processes in sandstones is major. The deformation band clusters result from the localization of the deformation in porous sandstones under the form of gathered low-permeability cataclastic deformation bands. It has recently been shown that this localization is favored in extensional tectonics. The clusters measure tens to hundreds of meters in extent and propagate vertically as long as the sandstone is clean. Because the clusters can form several kilometers long networks, they are likely to hamper fluid flow during reservoir exploitation. Yet, the processes of band accumulation linked to the evolution of the clusters to a potential faulting are poorly understood. An integrated study coupling a microscopic analysis of the deformed granular material in clusters from 7 sites in the world and distinct element numerical modeling permits to propose a model for cluster growth. Our microscopic analysis reveals that the clusters display varying degree of cataclasis, with the most important degrees in the bands. This cataclasis is accompanied by porosity reduction (more reduced in thrust Andersonian regime), and increased Particle Size Distribution. This testifies of an important packing and implies an increased number of particle coordination. During deformation, the grain shape is both smoothened and roughened; the averaged values of the roundness and circularity indicate a rapid roughening of the clasts at the first stages of deformation followed by a slight smoothening. The roughening of the clasts in densely packed material induces high friction and strengthens the material. High residual porosity at some band edges suggests a local dilatant behavior of sheared material. Our distinct element numerical models and other particle models in the literature confirm this observation. The development of force chains with low particle coordination at these locations would weaken the stress resistance at the contact points. Hence, the cluster growth would be promoted by the successive localization of bands the edges of preexisting bands. Faulting could occur at any stage of the cluster development, probably favored along interfaces of minimized strength with smooth geometry.

Publications - PIR 2015-7 | Alaska Division of Geological & Geophysical

Science.gov Websites

content DGGS PIR 2015-7 Publication Details Title: Oil-stained sandstone in the Middle Jurassic lower information. Quadrangle(s): Iliamna Bibliographic Reference Wartes, M.A., and Herriott, T.M., 2015, Oil Jurassic; Oil Seeps; Oil and Gas; Paveloff Siltstone Member; Petroleum; Petrology; Provenance; Reservoir

Chapter 1: An overview of the petroleum geology of the Arctic

USGS Publications Warehouse

Spencer, A.M.; Embry, A.F.; Gautier, D.L.; Stoupakova, A.V.; Sorensen, K.

2011-01-01

Nine main petroleum provinces containing recoverable resources totalling 61 Bbbl liquids + 269 Bbbloe of gas are known in the Arctic. The three best known major provinces are: West Siberia-South Kara, Arctic Alaska and Timan-Pechora. They have been sourced principally from, respectively, Upper Jurassic, Triassic and Devonian marine source rocks and their hydrocarbons are reservoired principally in Cretaceous sandstones, Triassic sandstones and Palaeozoic carbonates. The remaining six provinces except for the Upper Cretaceous-Palaeogene petroleum system in the Mackenzie Delta have predominantly Mesozoic sources and Jurassic reservoirs. There are discoveries in 15% of the total area of sedimentary basins (c. 8 ?? 106 km2), dry wells in 10% of the area, seismic but no wells in 50% and no seismic in 25%. The United States Geological Survey estimate yet-to-find resources to total 90 Bbbl liquids + 279 Bbbloe gas, with four regions - South Kara Sea, Alaska, East Barents Sea, East Greenland - dominating. Russian estimates of South Kara Sea and East Barents Sea are equally positive. The large potential reflects primarily the large undrilled areas, thick basins and widespread source rocks. ?? 2011 The Geological Society of London.

Assessing spatial uncertainty in reservoir characterization for carbon sequestration planning using public well-log data: A case study

USGS Publications Warehouse

Venteris, E.R.; Carter, K.M.

2009-01-01

Mapping and characterization of potential geologic reservoirs are key components in planning carbon dioxide (CO2) injection projects. The geometry of target and confining layers is vital to ensure that the injected CO2 remains in a supercritical state and is confined to the target layer. Also, maps of injection volume (porosity) are necessary to estimate sequestration capacity at undrilled locations. Our study uses publicly filed geophysical logs and geostatistical modeling methods to investigate the reliability of spatial prediction for oil and gas plays in the Medina Group (sandstone and shale facies) in northwestern Pennsylvania. Specifically, the modeling focused on two targets: the Grimsby Formation and Whirlpool Sandstone. For each layer, thousands of data points were available to model structure and thickness but only hundreds were available to support volumetric modeling because of the rarity of density-porosity logs in the public records. Geostatistical analysis based on this data resulted in accurate structure models, less accurate isopach models, and inconsistent models of pore volume. Of the two layers studied, only the Whirlpool Sandstone data provided for a useful spatial model of pore volume. Where reliable models for spatial prediction are absent, the best predictor available for unsampled locations is the mean value of the data, and potential sequestration sites should be planned as close as possible to existing wells with volumetric data. ?? 2009. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved.

Paragenesis and reservoir quality within a shallow combination trap: Central West Virginia

DOE Office of Scientific and Technical Information (OSTI.GOV)

Bell, D.A.; Siegrist, H.G. Jr.; Buurman, J.D.

1993-12-01

Sandstone character and reservoir quality of the Lower Mississippian Pocono Big Injun sandstone were examined in Granny Creek-Stockly field, Clay County, West Virginia. Sixty-three samples from 6 wells were analyzed using transmitted light, x-ray diffraction, and scanning electron microscopy techniques. The Pocono Big Injun formation is divided into four [open quotes]sands[close quotes] (Injun 1 through 4) based on composition and hydrocarbon productivity. The Injun 1 sand is a fine-grained, carbonate-cemented litharenite below the oil-producing zone. The oil-productive Injun 2 and 3 sands are well sorted, fine-grained litharenites which contain more authigenic and allogenic clay minerals than adjacent sands. These sandsmore » have produced more than 3.4 million bbl of oil from the Granny Creek part of the field since 1925. The Injun 4 sand is generally a coarse-grained sublitharenite with marginal gas production limited to the uppermost section of the sand. The paragenetic sequence consists of (1) minor quartz overgrowths, (2) illite and chlorite grain coatings, (3) quartz overgrowths, (4) early carbonate, (5) kaolinite, (6) calcite, (7) dolomite, and (8) pyrite. Porosity and permeability were not preserved once paragenesis progressed past the kaolinite stage. Porosity and permeability are variably preserved when steps in the paragenetic sequence are absent within the Pocono Group. Where any porosity is identified within the Pocono sandstones, primary porosity is dominant. However, secondary porosity and microporosity in clay-rich intervals are also important.« less

DOE Office of Scientific and Technical Information (OSTI.GOV)

Oldham, D.W.

Commercial quantities of gas have been produced from shallow sandstone reservoirs of the Fort Union Formation (Paleocene) in the Powder River Basin of Wyoming. The two largest accumulations discovered to date, Oedekoven and Chan pools, were drilled on prospects which invoked differential compaction as a mechanism for gas entrapment and prospect delineation. Gas is believed to have accumulated in localized structural highs early in the burial history of lenticular sands. Structural relief is due to the compaction contrast between sand and stratigraphically-equivalent fine-grained sediments. A shallow Fort Union gas play was based on reports of shallow gas shows, the occurrencemore » of thick coals which could have served as sources for bacterial gas, and the presence of lenticular sandstones which may have promoted the development of compaction structures early in the burial process, to which bacterial gas migrated. Five geologic elements related to compactional trap development were used to rank prospects. Drilling of the Oedekoven prospect, which possessed all prospect elements, led to the discovery of the Oedekoven Fort Union gas pool at a depth of 340 ft (104 m). The uncemented, very fine grained, well-sorted {open_quotes}Canyon sand{close_quotes} pay has extremely high intergranular porosity. Low drilling and completion costs associated with shallow, high-permeability reservoirs, an abundance of subsurface control with which to delineate prospects, and existing gas-gathering systems make Fort Union sandstones attractive primary targets in shallow exploration efforts as well as secondary objectives in deeper drilling programs.« less

Geologic framework of oil and gas genesis in main sedimentary basins from Romania Oprea Dicea

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ionescu, N.; Morariu, C.D.

1991-03-01

Oil and gas fields located in Moldavic nappes are encompassed in Oligocene and lower Miocene formations, mostly in the marginal folds nappe, where Kliwa Sandstone sequences have high porosity, and in the Black Sea Plateau. The origin of the hydrocarbon accumulations from the Carpathian foredeep seems to be connected to the Oligocene-lower Miocene bituminous formations of the marginal folds and sub-Carpathian nappes. In the Gethic depression, the hydrocarbon accumulations originate in Oligocene and Miocene source rocks and host in structural, stratigraphical, and lithological traps. The accumulations connected with tectonic lines that outline the areal extension of the Oligocene, Miocene, andmore » Pliocene formations are in the underthrusted Moesian platform. The hydrocarbon accumulations related to the Carpathian foreland represent about 40% of all known accumulations in Romania. Most of them are located in the Moesian platform. In this unit, the oil and gas fields present a vertical distribution at different stratigraphic levels, from paleozoic to Neogene, and in all types of reservoirs, suggesting multicycles of oleogenesis, migration, accumulation, and sealing conditions. The hydrocarbon deposits known so far on the Black Sea continental plateau are confined in the Albian, Cenomanian, Turonian-Senonian, and Eocene formations. The traps are of complex type structural, lithologic, and stratigraphic. The reservoirs are sandstones, calcareous sandstones, limestones, and sands. The hydrocarbon source rocks are pelitic and siltic Oligocene formations. Other older source rocks are probably Cretaceous.« less

Spatial Persistence of Macropores and Authigenic Clays in a Reservoir Sandstone: Implications for Enhanced Oil Recovery and CO2 Storage

NASA Astrophysics Data System (ADS)

Dewers, T. A.

2015-12-01

Multiphase flow in clay-rich sandstone reservoirs is important to enhanced oil recovery (EOR) and the geologic storage of CO2. Understanding geologic controls on pore structure allows for better identification of lithofacies that can contain, storage, and/or transmit hydrocarbons and CO2, and may result in better designs for EOR-CO2 storage. We examine three-dimensional pore structure and connectivity of sandstone samples from the Farnsworth Unit, Texas, the site of a combined EOR-CO2 storage project by the Southwest Regional Partnership on Carbon Sequestration (SWP). We employ a unique set of methods, including: robotic serial polishing and reflected-light imaging for digital pore-structure reconstruction; electron microscopy; laser scanning confocal microscopy; mercury intrusion-extrusion porosimetry; and relative permeability and capillary pressure measurements using CO2 and synthetic formation fluid. Our results link pore size distributions, topology of porosity and clay-rich phases, and spatial persistence of connected flow paths to multiphase flow behavior. The authors gratefully acknowledge the U.S. Department of Energy's National Energy Technology Laboratory for sponsoring this project through the SWP under Award No. DE-FC26-05NT42591. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000.

Field-trip guide to the geology of the Lexington Reservoir and Loma Prieta areas in the Santa Cruz Mountains, Santa Clara and Santa Cruz counties, California

USGS Publications Warehouse

Stoffer, Philip W.; Messina, Paula

2002-01-01

This guide contains a road log and five stop descriptions for a field trip in the southern Santa Cruz Mountains. The trip officially begins at the boat dock parking area on Alma Bridge Road near the dam of Lexington Reservoir. Stop 1 involves a walk up the Limekiln Trail to examine a large landslide in serpentinite that frequently takes out the trail. Stop 2 is at Miller Point picnic area along the shore of the reservoir where exposures of massive, fractured graywacke sandstone are capped with terrace gravel deposits. Stop 3 is along Highland Way in the Santa Cruz Mountains where large landslides have occasionally force the closure of the road. Stop 4A-C are several closely spaced outcrop areas along Loma Prieta Avenue and Summit-Mt. Madonna Road in the Loma Prieta summit area. A walk to scenic vista points provide opportunity to discuss the evolution of regional landscape along the crest of the Sierra Azul. In addition, a variety of rock types are exposed in the Stop 4 area along a series of road cuts, including Cretaceous age conglomerate, turbidites (consisting of interbedded sandstone and shale), and fossiliferous mudstone. Stop 5 involves returning to the boat dock parking area to examine geology and the placement of the Lexington Dam in the Los Gatos Creek canyon.

Mapping Petroluem Migration Pathways Using Magnetics and Seismic Interpretations

NASA Astrophysics Data System (ADS)

Abubakar, R.; Muxworthy, A. R.; Sephton, M. A.; Fraser, A.; Heslop, D.; Paterson, G. A.; Southern, P.

2015-12-01

We report the formation of magnetic minerals in petroleum reservoirs. Eleven wells from Wessex Basin in Dorset, southern England, were sampled from the British Geological Core Store, across the main reservoir unit; Bridport Sandstone and the overlying Inferior Oolite. Sampling was carried out based on visible evidence of oil stain and a high magnetic susceptibility reading. The samples were chemically extracted to determine which were naturally stained with hydrocarbon and which were not. Magnetic analysis was carried out on all the samples: this including hysteresis analysis at low temperatures (5-15K) and room temperature, and low-temperature thermogmagentic analysis. The results indicated a trend based on the migration of hydrocarbons; from the source area, to the reservoir through the carrier beds.

Well log and 2D seismic data character of the Wilcox Group in south-central Louisiana

USGS Publications Warehouse

Enomoto, Catherine B.

2014-01-01

The Wilcox Group is productive in updip areas of Texas and Louisiana from fluvial, deltaic, and near-shore marine shelf sandstones. The reported presence of porous sandstones at 29,000 feet within the Wilcox Group containing about 200 feet of gas in the Davy Jones 1 discovery well in the offshore Louisiana South Marsh Island area illustrates a sand-rich system developed during the Paleocene and early Eocene. This study describes some of the well log and reflection seismic data characteristics of the slope and basin-floor reservoirs with gas-discovery potential that may be in the area between the producing trend onshore Louisiana and the offshore discovery.

investigating the use of geophysical techniques to detect hydrocarbon seeps

NASA Astrophysics Data System (ADS)

Somwe, Vincent Tambwe

In the Cement oil field, seeps occur in the Hydrocarbon Induced Diagenetic Aureole (HIDA).This 14 square km diagenetic alteration region is mainly characterized by the: (1) secondary carbonate minerals deposition that tends to form ridges throughout the oil field; (2) disseminated pyrite in the vicinity of the fault zones; (3) uranium occurrence and the change in color pattern from red to bleached red sandstone. Generally the HIDA of the Cement oil field is subdivided into four zones: (1) carbonate cemented sandstone zone (zone 1), (2) altered sandstone zone (zone 2), (3) sulfide zone (zone 3) and (4) unaltered sandstone zone (zone 4). This study investigated the use of geophysical techniques to detect alteration zones over the Cement oil field. Magnetic and electromagnetic data were acquired at 5 m interval using the geometric G858 magnetometer and the Geonics EM-31 respectively. Both total magnetic intensity and bulk conductivity were found to decrease across boundaries between unaltered and altered sandstones. Boundaries between sulfide and carbonate zones, which in most cases were located in fault zones, were found to be characterized by higher magnetic and bulk conductivity readings. The contrast between the background and the highest positive peak was found to be in the range of 0.5-10% for total magnetic intensity and 258-450% for bulk conductivity respectively; suggesting that the detection of hydrocarbon seeps would be more effective with EM techniques. The study suggests that geophysical techniques can be used to delineate contact between the different alteration zones especially where metallic minerals such as pyrite are precipitated. The occurrence of carbonate cemented sandstone in the Cement oil field can be used as a pathfinder for hydrocarbon reservoir. The change in color in the altered sandstone zone can still be useful in the hydrocarbon exploration.

Micro-mechanics of hydro-mechanical coupled processes during hydraulic fracturing in sandstone

NASA Astrophysics Data System (ADS)

Caulk, R.; Tomac, I.

2017-12-01

This contribution presents micro-mechanical study of hydraulic fracture initiation and propagation in sandstone. The Discrete Element Method (DEM) Yade software is used as a tool to model fully coupled hydro-mechanical behavior of the saturated sandstone under pressures typical for deep geo-reservoirs. Heterogeneity of sandstone strength tensile and shear parameters are introduced using statistical representation of cathodoluminiscence (CL) sandstone rock images. Weibull distribution of statistical parameter values was determined as a best match of the CL scans of sandstone grains and cement between grains. Results of hydraulic fracturing stimulation from the well bore indicate significant difference between models with the bond strengths informed from CL scans and uniform homogeneous representation of sandstone parameters. Micro-mechanical insight reveals formed hydraulic fracture typical for mode I or tensile cracking in both cases. However, the shear micro-cracks are abundant in the CL informed model while they are absent in the standard model with uniform strength distribution. Most of the mode II cracks, or shear micro-cracks, are not part of the main hydraulic fracture and occur in the near-tip and near-fracture areas. The position and occurrence of the shear micro-cracks is characterized as secondary effect which dissipates the hydraulic fracturing energy. Additionally, the shear micro-crack locations qualitatively resemble acoustic emission cloud of shear cracks frequently observed in hydraulic fracturing, and sometimes interpreted as re-activation of existing fractures. Clearly, our model does not contain pre-existing cracks and has continuous nature prior to fracturing. This observation is novel and interesting and is quantified in the paper. The shear particle contact forces field reveals significant relaxation compared to the model with uniform strength distribution.

A subtle diagenetic trap in the Cretaceous Glauconite Sandstone of Southwest Alberta

USGS Publications Warehouse

Meshri, I.D.; Comer, J.B.

1990-01-01

Despite the long history of research which documents many studies involving extensive diagenesis, there are a few examples of a fully documented diagenetic trap. In the context of this paper, a trap is a hydrocarbon-bearing reservoir with a seal; because a reservoir without a seal acts as a carrier bed. The difficulty in the proper documentation of diagenetic traps is often due to the lack of: (a) extensive field records on the perforation and production histories, which assist in providing the depth of separation between hydrocarbon production and non-hydrocarbon or water production; and (b) the simultaneous availability of core data from these intervals, which could be studied for the extent and nature of diagenesis. This paper provides documentation for the existence of a diagenetic trap, based on perforation depths, production histories and petrologic data from the cored intervals, in the context of the geologic and stratigraphic setting. Cores from 15 wells and SP logs from 45 wells were carefully correlated and the data on perforated intervals was also acquired. Extensive petrographic work on the collected cores led to the elucidation of a diagenetic trap that separates water overlying and updip from gas downdip. Amoco's Berrymore-Lobstick-Bigoray fields, located near the northeastern edge of the Alberta Basin, are prolific gas producers. The gas is produced from reservoir rock consisting of delta platform deposits formed by coalescing distributary mouth bars. The overlying rock unit is composed of younger distributary channels; although it has a good reservoir quality, it contains and produces water only. The total thickness of the upper, water-bearing and lower gas-bearing sandstone is about 40 ft. The diagenetic seal is composed of a zone 2 to 6 ft thick, located at the base of distributary channels. This zone is cemented with 20-30% ankerite cement, which formed the gas migration and is also relatively early compared to other cements formed in the water zone. In addition to this barrier to vertical flow, a barrier to lateral flow is formed by the merging of the upper sandstone containing 14% kaolinite and the lower sandstone containing 20% siderite. The measured core permeabilities in these zones vary from 0.0002 to 0.001 milli-darcies. This spatial configuration of diagenetic cements causing porous and non-porous zones is a result of the process of geochemical self-organization. The spatial and temporal patterns of diagenesis are a complex result of coupling of natural processes involving fluid flow, fluid composition, mineral composition and mineral dissolution rates under the conditions of varying pressure and temperature in the subsurface. ?? 1990.

Geologic characterization and carbon storage resource estimates for the knox group, Illinois Basin, Illinois, Indiana and Kentucky

DOE Office of Scientific and Technical Information (OSTI.GOV)

Harris, David; Ellett, Kevin; Rupp, John

Research documented in this report includes (1) refinement and standardization of regional stratigraphy across the 3-state study area in Illinois, Indiana, and Kentucky, (2) detailed core description and sedimentological interpretion of Knox cores from five wells in western Kentucky, and (3) a detailed calculation of carbon storage volumetrics for the Knox using three different methodologies. Seven regional cross sections document Knox formation distribution and thickness. Uniform stratigraphic nomenclature for all three states helps to resolve state-to-state differences that previously made it difficult to evaluate the Knox on a basin-wide scale. Correlations have also refined the interpretation of an important sandstonemore » reservoir interval in southern Indiana and western Kentucky. This sandstone, a CO2 injection zone in the KGS 1 Blan well, is correlated with the New Richmond Sandstone of Illinois. This sandstone is over 350 ft (107 m) thick in parts of southern Indiana. It has excellent porosity and permeability at sufficient depths, and provides an additional sequestration target in the Knox. The New Richmond sandstone interval has higher predictability than vuggy and fractured carbonates, and will be easier to model and monitor CO2 movement after injection.« less

New Ediacara fossils preserved in marine limestone and their ecological implications

PubMed Central

Chen, Zhe; Zhou, Chuanming; Xiao, Shuhai; Wang, Wei; Guan, Chengguo; Hua, Hong; Yuan, Xunlai

2014-01-01

Ediacara fossils are central to our understanding of animal evolution on the eve of the Cambrian explosion, because some of them likely represent stem-group marine animals. However, some of the iconic Ediacara fossils have also been interpreted as terrestrial lichens or microbial colonies. Our ability to test these hypotheses is limited by a taphonomic bias that most Ediacara fossils are preserved in sandstones and siltstones. Here we report several iconic Ediacara fossils and an annulated tubular fossil (reconstructed as an erect epibenthic organism with uniserial arranged modular units), from marine limestone of the 551–541 Ma Dengying Formation in South China. These fossils significantly expand the ecological ranges of several key Ediacara taxa and support that they are marine organisms rather than terrestrial lichens or microbial colonies. Their close association with abundant bilaterian burrows also indicates that they could tolerate and may have survived moderate levels of bioturbation. PMID:24566959

New Ediacara fossils preserved in marine limestone and their ecological implications.

PubMed

Chen, Zhe; Zhou, Chuanming; Xiao, Shuhai; Wang, Wei; Guan, Chengguo; Hua, Hong; Yuan, Xunlai

2014-02-25

Ediacara fossils are central to our understanding of animal evolution on the eve of the Cambrian explosion, because some of them likely represent stem-group marine animals. However, some of the iconic Ediacara fossils have also been interpreted as terrestrial lichens or microbial colonies. Our ability to test these hypotheses is limited by a taphonomic bias that most Ediacara fossils are preserved in sandstones and siltstones. Here we report several iconic Ediacara fossils and an annulated tubular fossil (reconstructed as an erect epibenthic organism with uniserial arranged modular units), from marine limestone of the 551-541 Ma Dengying Formation in South China. These fossils significantly expand the ecological ranges of several key Ediacara taxa and support that they are marine organisms rather than terrestrial lichens or microbial colonies. Their close association with abundant bilaterian burrows also indicates that they could tolerate and may have survived moderate levels of bioturbation.

Spatial pattern of groundwater arsenic occurrence and association with bedrock geology in greater augusta, maine

USGS Publications Warehouse

Yang, Q.; Jung, H.B.; Culbertson, C.W.; Marvinney, R.G.; Loiselle, M.C.; Locke, D.B.; Cheek, H.; Thibodeau, H.; Zheng, Yen

2009-01-01

In New England, groundwater arsenic occurrence has been linked to bedrock geology on regional scales. To ascertain and quantify this linkage at intermediate (100-101 km) scales, 790 groundwater samples from fractured bedrock aquifers in the greater Augusta, Maine area are analyzed, and 31% of the sampled wells have arsenic concentrations >10 ??g/L. The probability of [As] exceeding 10 ??g/L mapped by indicator kriging is highest in Silurian pelite-sandstone and pelite-limestone units (???40%). This probability differs significantly (p < 0.001) from those in the Silurian - Ordovician sandstone (24%), the Devonian granite (15%), and the Ordovician - Cambrian volcanic rocks (9%). The spatial pattern of groundwater arsenic distribution resembles the bedrock map. Thus, bedrock geology is associated with arsenic occurrence in fractured bedrock aquifers of the study area at intermediate scales relevant to water resources planning. The arsenic exceedance rate for each rock unit is considered robust because low, medium, and high arsenic occurrences in four cluster areas (3-20 km2) with a low sampling density of 1-6 wells per km2 are comparable to those with a greater density of 5-42 wells per km2. About 12,000 people (21% of the population) in the greater Augusta area (???1135 km2) are at risk of exposure to >10 ??g/L arsenic in groundwater. ?? 2009 American Chemical Society.

Spatial Pattern of Groundwater Arsenic Occurrence and Association with Bedrock Geology in Greater Augusta, Maine, USA

PubMed Central

Yang, Qiang; Jung, Hun Bok; Culbertson, Charles W.; Marvinney, Robert G.; Loiselle, Marc C.; Locke, Daniel B.; Cheek, Heidi; Thibodeau, Hilary; Zheng, Yan

2009-01-01

In New England, groundwater arsenic occurrence has been linked to bedrock geology on regional scales. To ascertain and quantify this linkage at intermediate (100-101 km) scales, 790 groundwater samples from fractured bedrock aquifers in the greater Augusta, Maine area are analyzed. 31% of the sampled wells have arsenic >10 μg/L. The probability of [As] exceeding 10 μg/L mapped by indicator kriging is highest in Silurian pelite-sandstone and pelite-limestone units (~40%). This probability differs significantly (p<0.001) from those in the Silurian-Ordovician sandstone (24%), the Devonian granite (15%) and the Ordovician-Cambrian volcanic rocks (9%). The spatial pattern of groundwater arsenic distribution resembles the bedrock map. Thus, bedrock geology is associated with arsenic occurrence in fractured bedrock aquifers of the study area at intermediate scales relevant to water resources planning. The arsenic exceedance rate for each rock unit is considered robust because low, medium and high arsenic occurrences in 4 cluster areas (3-20 km2) with a low sampling density of 1-6 wells per km2 are comparable to those with a greater density of 5-42 wells per km2. About 12,000 people (21% of the population) in the greater Augusta area (~1135 km2) are at risk of exposure to >10 μg/L arsenic in groundwater. PMID:19475939

Spatial pattern of groundwater arsenic occurrence and association with bedrock geology in greater Augusta, Maine.

PubMed

Yang, Qiang; Jung, Hun Bok; Culbertson, Charles W; Marvinney, Robert G; Loiselle, Marc C; Locke, Daniel B; Cheek, Heidi; Thibodeau, Hilary; Zheng, Yan

2009-04-15

In New England, groundwater arsenic occurrence has been linked to bedrock geology on regional scales. To ascertain and quantify this linkage at intermediate (10(0)-10(1) km) scales, 790 groundwater samples from fractured bedrock aquifers in the greater Augusta, Maine area are analyzed, and 31% of the sampled wells have arsenic concentrations >10 microg/L. The probability of [As] exceeding 10 microg/L mapped by indicator kriging is highest in Silurian pelite-sandstone and pelite-limestone units (approximately 40%). This probability differs significantly (p < 0.001) from those in the Silurian-Ordovician sandstone (24%),the Devonian granite (15%), and the Ordovician-Cambrian volcanic rocks (9%). The spatial pattern of groundwater arsenic distribution resembles the bedrock map. Thus, bedrock geology is associated with arsenic occurrence in fractured bedrock aquifers of the study area at intermediate scales relevant to water resources planning. The arsenic exceedance rate for each rock unit is considered robust because low, medium, and high arsenic occurrences in four cluster areas (3-20 km2) with a low sampling density of 1-6 wells per km2 are comparable to those with a greater density of 5-42 wells per km2. About 12,000 people (21% of the population) in the greater Augusta area (approximately 1135 km2) are at risk of exposure to >10 microg/L arsenic in groundwater.

Sands of West Gondwana: An archive of secular magmatism and plate interactions — A case study from the Cambro-Ordovician section of the Tassili Ouan Ahaggar (Algerian Sahara) using U-Pb-LA-ICP-MS detrital zircon ages

NASA Astrophysics Data System (ADS)

Linnemann, Ulf; Ouzegane, Khadidja; Drareni, Amar; Hofmann, Mandy; Becker, Sindy; Gärtner, Andreas; Sagawe, Anja

2011-04-01

Enormous masses of highly mature quartz sands were deposited in Western Gondwana during the Cambrian-Ordovician time, and provide a wide range of information concerning magmatic events through time, provenance, paleoclimate, and basin history. We present a provenance study based on 630 U-Pb (LA-ICP-MS) ages of detrital zircon from the latest Cambrian to Ordovician siliciclastic rocks of the Tassili Ouan Ahaggar basin situated in the Algerian Sahara. Most authors suggest local sources only for the sandstones. Instead, we demonstrate that the detritus is derived from different cratons and terranes which contributed to the deposition of a Cambrian-Ordovician overstep sequence covering western and northern Africa. Most zircon ages (61.0%) fall in the range of ~ 540 to 740 Ma and are interpreted to have been derived from Pan-African orogenic belts such as the Trans-Saharan Belt of NW Africa and previously from the Brazila belt of South America. Other potential sources for this zircon population are terranes of Cadomian affinity situated marginal to West Africa. The second-largest zircon population (20.2%) is 2.0 to 2.2 Ga, and is attributed to sources in the West African craton, such as the Birimian basement and the Eburnean orogenic belt, with possible partial input from the Amazonian craton. A zircon population of 7.1% yields Mesoproterozoic and early Paleoproterozoic ages in the range of ~ 1.3 to ~ 1.8 Ga and was probably derived from source rocks outside of the West African basement, the Tuareg shield and other adjoining areas. The Amazonian craton is a potential source region. A population of 6.7% of all zircon ages scatter from ~ 750 Ma to ~ 980 Ma and may reflect input from latest stages of the formation of Rodinia and its subsequent dispersal. A smaller population (3.2%) of zircon ages lie between ~ 2.3 and 2.65 Ga, and may be derived from late Paleoproterozoic to early Archaean rocks from the West African craton and possibly from Amazonia. Less than 1% of all zircons are Meso- to Paleoarchaean ones and provide evidence for the input of very old cratonic basement, most likely from cratonic inliers of the West African craton (Leonian, Liberian). Because of the potential input of detrital zircon from the Amazonian craton, which is reflected in the Mesoproterozoic and late Paleoproterozoic grains, we speculate that some of the Paleoproterozoic to Neoarchean (2.0 Ga to 2.6 Ga) zircons were also derived from Amazonia. Due to the total lack of 1.0-1.2 Ga old zircon, our data set excludes all crustal domains situated in the Arabian-Nubian shield and the East African belt, as well as the Sunsás belt of Amazonia ("Sunsás-Grenvillian") as potential sediment sources. Sedimentation in the Tassili Ouan Ahaggar basin started in uppermost Cambrian to Ordovician time due to the opening of the Rheic Ocean. This event led to subsidence related to the rift and drift of Avalonia and related terranes from the northwestern Gondwanan margin. The basal Early Tassili quartzite has detrital zircon populations that suggest a local provenance either from West African or from a related terrane in the Tuareg shield. A dramatic change occurs in the deltaic to shallow marine strata of the Lower Ordovician Ajjers Formation and in the overlying marine sandstones of the Middle Ordovician d'In Azaoua Formation. Our data for both formations indicate the Pan-African orogen, and very likely Cadomian terranes as the main source for the detritus. During this time, the region was affected by rift tectonics due to the opening of the Rheic Ocean and therefore amenable to erosion at rift shoulders and escarpments. Our data also indicate that glacial erosion in Upper Ordovician (Hirnantian) time must have affected larger areas of old cratonic surfaces as the populations of Paleoproterozoic to Archaean zircons are significantly higher than in other age clusters. Large parts of highly mature sands of the Cambro-Ordovician section in the Tassili Ouan Ahaggar basin were derived from a peneplain in the interior of Gondwana, that formed during Cambrian times. This peneplain was formed under warm-humid climate on a vegetation-free land surface and in an extreme corrosive environment that was influenced by high atmospheric pCO 2 caused by Pan-African and Avalonian-Cadomian volcanism, volcanic activity related to the opening of the Iapetus, and Late Cambrian-Early Ordovician rift volcanism as well.

Delta 37Cl and Characterisation of Petroleum-gas Reservoirs

NASA Astrophysics Data System (ADS)

Woulé Ebongué, V.; Jendrzejewski, N.; Walgenwitz, F.; Pineau, F.; Javoy, M.

2003-04-01

The geochemical characterisation of formation waters from oil/gas fields is used to detect fluid-flow barriers in reservoirs and to reconstruct the system dynamic. During the progression of the reservoir filling, the aquifer waters are pushed by hydrocarbons toward the reservoir bottom and their compositions evolve due to several parameters such as water-rock interactions, mixing with oil-associated waters, physical processes etc. The chemical and isotopic evolution of these waters is recorded in irreducible waters that have been progressively "fossilised" in the oil/gas column. Residual salts precipitated from these waters were recovered. Chloride being the most important dissolved anion in these waters and not involved in diagenetic reactions, its investigation should give insights into the different transport or mixing processes taking place in the sedimentary basin and point out to the formation waters origins. The first aim of our study was to test the Cl-RSA technique (Chlorine Residual Salts Analysis) based on the well-established Sr-RSA technique. The main studied area is a turbiditic sandstone reservoir located in the Lower Congo basin in Angola. Present-day aquifer waters, irreducible waters from sandstone and shale layers as well as drilling mud and salt dome samples were analysed. Formation waters (aquifer and irreducible trapped in shale) show an overall increase of chlorinity with depth. Their δ37Cl values range from -1.11 ppm to +2.30 ppm ± 0.05 ppm/ SMOC. Most Cl-RSA data as well as the δ37Cl obtained on a set of water samples (from different aquifers in the same area) are lower than -0.13 ppm with lower δ37Cl values at shallower depths. In a δ37Cl versus chlorinity diagram, they are distributed along a large range of chlorinity: 21 to 139 g/l, in two distinct groups. (1) Irreducible waters from one of the wells display a positive correlation between chlorinity and the δ37Cl values. (2) In contrary, the majority of δ37Cl measured on aquifers and on residual salts from a second well are anti-correlated with chlorinity. The preliminary determinations of δ37Cl values of sandstone irreducible waters seem to match the values obtained on irreducible waters trapped in the shale porosity. δ37Cl values and chlorinities are used to identify the contributions of physico-chemical processes such as ion filtration, diffusion or mixing. The chronology of the events and their relative importance are discussed.

Parcperdue Geopressure -- Geothermal Project: Appendix E

DOE Office of Scientific and Technical Information (OSTI.GOV)

Sweezy, L.R.

1981-10-05

The mechanical and transport properties and characteristics of rock samples obtained from DOW-DOE L.R. SWEEZY NO. 1 TEST WELL at the Parcperdue Geopressure/Geothermal Site have been investigated in the laboratory. Elastic moduli, compressibility, uniaxial compaction coefficient, strength, creep parameters, permeability, acoustic velocities (all at reservoir conditions) and changes in these quantities induced by simulated reservoir production have been obtained from tests on several sandstone and shale samples from different depths. Most important results are that the compaction coefficients are approximately an order of magnitude lower than those generally accepted for the reservoir sand in the Gulf Coast area and thatmore » the creep behavior is significant. Geologic characterization includes lithological description, SEM micrographs and mercury intrusion tests to obtain pore distributions. Petrographic analysis shows that approximately half of the total sand interval has excellent reservoir potential and that most of the effective porosity in the Cib Jeff Sand is formed by secondary porosity development.« less

Results of the multiwell experiment in situ stresses, natural fractures, and other geological controls on reservoirs

NASA Astrophysics Data System (ADS)

Lorenz, John C.; Warpinski, Norman R.; Teufel, Lawrence W.; Branagan, Paul T.; Sattler, Allan R.; Northrop, David A.

Hundreds of millions of cubic meters of natural gas are locked up in low-permeability, natural gas reservoirs. The Multiwell Experiment (MWX) was designed to characterize such reservoirs, typical of much of the western United States, and to assess and develop a technology for the production of this unconventional resource. Flow-rate tests of the MWX reservoirs indicate a system permeability that is several orders of magnitude higher than laboratory permeability measurements made on matrix-rock sandstones. This enhanced permeability is caused by natural fractures. The single set of fractures present in the reservoirs provides a significant permeability anisotropy that is aligned with the maximum in situ horizontal stress. Hydraulic fractures therefore form parallel to the natural fractures and are consequently an inefficient mechanism for stimulation. Successful stimulation may be possible by perturbing the local stress field with a large hydraulic fracture in one well so that a second hydraulic fracture in an offset well propagates transverse to the natural fracture permeability trend.

Overview of the potential and identified petroleum source rocks of the Appalachian basin, eastern United States: Chapter G.13 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Coleman, James L.; Ryder, Robert T.; Milici, Robert C.; Brown, Stephen; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

The Appalachian basin is the oldest and longest producing commercially viable petroleum-producing basin in the United States. Source rocks for reservoirs within the basin are located throughout the entire stratigraphic succession and extend geographically over much of the foreland basin and fold-and-thrust belt that make up the Appalachian basin. Major source rock intervals occur in Ordovician, Devonian, and Pennsylvanian strata with minor source rock intervals present in Cambrian, Silurian, and Mississippian strata.

Giant calcite concretions in aeolian dune sandstones; sedimentological and architectural controls on diagenetic heterogeneity, mid-Cretaceous Iberian Desert System, Spain

NASA Astrophysics Data System (ADS)

Arribas, Maria Eugenia; Rodríguez-López, Juan Pedro; Meléndez, Nieves; Soria, Ana Rosa; de Boer, Poppe L.

2012-01-01

Aeolian dune sandstones of the Iberian erg system (Cretaceous, Spain) host giant calcite concretions that constitute heterogeneities of diagenetic origin within a potential aeolian reservoir. The giant calcite concretions developed in large-scale aeolian dune foresets, at the transition between aeolian dune toeset and damp interdune elements, and in medium-scale superimposed aeolian dune sets. The chemical composition of the giant concretions is very homogeneous. They formed during early burial by low Mg-calcite precipitation from meteoric pore waters. Carbonate components with yellow/orange luminescence form the nuclei of the poikilotopic calcite cement. These cements postdate earlier diagenetic features, characterized by early mechanical compaction, Fe-oxide cements and clay rims around windblown quartz grains resulting from the redistribution of aeolian dust over the grain surfaces. The intergranular volume (IGV) in friable aeolian sandstone ranges from 7.3 to 15.3%, whereas in cemented aeolian sandstone it is 18.6 to 25.3%. The giant-calcite concretions developed during early diagenesis under the influence of meteoric waters associated with the groundwater flow of the desert basin, although local (e.g. activity of fluid flow through extensional faults) and/or other regional controls (e.g. variations of the phreatic level associated with a variable water influx to the erg system and varying sea level) could have favoured the local development of giant-calcite concretions. The spatial distribution pattern of carbonate grains and the main bounding surfaces determined the spatial distribution of the concretions. In particular, the geometry of the giant calcite concretions is closely associated with main bounding aeolian surfaces. Thus, interdune, superimposition and reactivation surfaces exerted a control on the concretion geometries ranging from flat and tabular ones (e.g. bounded by interdunes) to wedge-shaped concretions at the dune foresets (e.g. bounded by superimposition and reactivation surfaces) determining the spatial distribution of the heterogeneities of diagenetic origin in the aeolian reservoir.

Mineral displacement and -dissolution processes and their relevance to rock porosity and permeability in Rotliegend sandstones of the Altmark natural gas field (central Germany) - results from CO2 laboratory batch experiments

NASA Astrophysics Data System (ADS)

Pudlo, Dieter; Enzmann, Frieder; Heister, Katja; Werner, Lars; Ganzer, Leonhard; Reitenbach, Viktor; Henkel, Steven; Albrecht, Daniel; Gaupp, Reinhard

2014-05-01

The Rotliegend reservoir sandstones of the Altmark area (central Germany) comprise the second largest natural gas field of Europe. These sandstones were deposited on a playa-like continental platform with braided river systems, ephemeral lakes and aeolian dunes under semi-arid conditions. Some of the pristine, red coloured deposits suffered intensive late diagenetic alteration and are now preserved as bleached, high porous and permeable sandstones. To evaluate the relevance of distinct fluids and their fluid-rock alteration reactions on such bleaching processes we performed laboratory static batch experiments on the Altmark sandstones. These 4-6 week lasting runs were conducted with CO2 saturated synthetic brines under typical Altmark reservoir conditions (p= 20 MPa, T= 125°C). Thereby mineralogical, petrophysical and (hydro- and geo-) chemical rock features were maintained prior and after the experiments. Chemical data proved the dissolution of carbonate and sulphate minerals during the runs, whereas the variation in abundance of further elements was within the detection limit of analytical accuracy. However, FE-SEM investigations on used, evaporated brines reveal the presence of illite and chlorite minerals within a matrix of Ca-, Si-, Fe, Al-, Na- and S components (carbonate, anhydrite, albite and Fe-(hydr-) oxides ?). By porosity and relative permeability measurements an increase in both rock features was observed after the runs, indicating that mineral dissolution and/or (clay) fine migration/detachment occurred during the experiments. Mineral dissolution, especially of pore-filling cements (e.g. carbonate-, sulphate minerals) is also deduced by BET analysis, in determining the specific surface of the sandstones. The size of these reactive surfaces increased after the experiments, suggesting that after the dissolution of pore-filling cements, formerly armoured grain rimming clay cutans were exposed to potential migrating fluids. These findings are also supported by µ-CT investigations. Here, the achieved 3D modelling data indicate an increase in reactive surface areas exposed to the pore space (which is in accord to the BET observations), as well as an enhancement in rock porosity and permeability after the runs. Moreover, these simulations showed that a remarkable mass (mineral) transfer was induced by the experiments, which led to a displacement of the porosity and permeability distribution in the sandstones and therefore a change in the fluid flow characteristics within the rocks - a parameter most important for every fluid-rock process. These observations are quite astonishing because they suggest that not only fluid velocity (e.g. during fluid flow experiments) might detach and transport grain rimming (clay) minerals, but also that physico-chemical reactions may enforce the release of such solids, even during almost static p-/T-/Xfluid conditions, as used in our experiments.

Calibrating rates of early Cambrian evolution

NASA Technical Reports Server (NTRS)

Bowring, Samuel A.; Grotzinger, John P.; Isachsen, Clark E.; Knoll, Andrew H.; Pelechaty, Shane M.; Kolosov, Peter

1993-01-01

An explosive episode of biological diversification occurred near the beginning of the Cambrian period. Evolutionary rates in the Cambrian have been difficult to quantify accurately because of a lack of high-precision ages. Currently, uranium-lead zircon geochronology is the most powerful method for dating rocks of Cambrian age. Uranium-lead zircon data from lower Cambrian rocks located in northeast Siberia indicate that the Cambrian period began about 544 million years ago and that its oldest (Manykaian) stage lasted no less than 10 million years. Other data indicate that the Tommotian and Atdabanian stages together lasted only 5 to 10 million years. The resulting compression of Early Cambrian time accentuates the rapidity of both the faunal diversification and subsequent Cambrian turnover.

Collision of the Tacheng block with the Mayile-Barleik-Tangbale accretionary complex in Western Junggar, NW China: Implication for Early-Middle Paleozoic architecture of the western Altaids

NASA Astrophysics Data System (ADS)

Zhang, Ji'en; Xiao, Wenjiao; Luo, Jun; Chen, Yichao; Windley, Brian F.; Song, Dongfang; Han, Chunming; Safonova, Inna

2018-06-01

Western Junggar in NW China, located to the southeast of the Boshchekul-Chingiz (BC) Range and to the north of the Chu-Balkhash-Yili microcontinent (CBY), played a key role in the architectural development of the western Altaids. However, the mutual tectonic relationships have been poorly constrained. In this paper, we present detailed mapping, field structural geology, and geochemical data from the Barleik-Mayile-Tangbale Complex (BMTC) in Western Junggar. The Complex is divisible into Zones I, II and III, which are mainly composed of Cambrian-Silurian rocks. Zone I contains pillow lava, siliceous shale, chert, coral-bearing limestone, sandstone and purple mudstone. Zone II consists of basaltic lava, siliceous shale, chert, sandstone and mudstone. Zone III is characterized by basalt, chert, sandstone and mudstone. These rocks represent imbricated ocean plate stratigraphy, which have been either tectonically juxtaposed by thrusting or form a mélange with a block-in-matrix structure. All these relationships suggest that the BMTC is an Early-Middle Paleozoic accretionary complex in the eastern extension of the BC Range. These Early Paleozoic oceanic rocks were thrust onto Silurian sediments forming imbricate thrust stacks that are unconformably overlain by Devonian limestone, conglomerate and sandstone containing fossils of brachiopoda, crinoidea, bryozoa, and plant stems and leaves. The tectonic vergence of overturned folds in cherts, drag-related curved cleavages and σ-type structures on the main thrust surface suggests top-to-the-NW transport. Moreover, the positive εNd(t) values of volcanic rocks from the Tacan-1 drill-core, and the positive εHf(t) values and post-Cambrian ages of detrital zircons from Silurian and Devonian strata to the south of the Tacheng block indicate that its basement is a depleted and juvenile lithosphere. And there was a radial outward transition from coral-bearing shallow marine (shelf) to deep ocean (pelagic) environments, and from OIB/E-MORB to N-MORB lava geochemistry away from the Tacheng block. Comparisons with published data suggest that these positive isotopic values, stratigraphic, structural and geochemical relationships can be best understood as an analogue of the relationships between the Ontong Java oceanic plateau and the Pacific oceanic crust. Therefore we propose that the basement of the Tacheng block was an Early Paleozoic oceanic plateau. The southern part of the Tacheng block was an accretionary complex and the northern part was an oceanic basin in the Early Paleozoic, the configuration of which is similar to that of the present Ontong Java oceanic plateau situated on the Pacific oceanic crust, and its accretion into the Solomon accretionary complex. The presence of Ordovician SSZ-type ophiolites, early Paleozoic blueschist and Silurian SSZ-type intrusions in the BMTC, and Early-Middle Paleozoic continental arc-related intrusive rocks in the northern margin of the CBY provide further corroboration of a former subduction zone between the southern West Junggar and the northern margin of the CBY. Furthermore, consideration of the fact that the Kokchetav-North Tianshan range was collaged to the southern margin of the CBY in the Ordovician-Devonian indicates that both ranges were amalgamated synchronously with the CBY constructing the Early-Middle Paleozoic architecture of western Altaids.

DOE Office of Scientific and Technical Information (OSTI.GOV)

Hartshorn, K.G.

The Castilla and Chichimene NE fields, operated by Chevron, are located in the southern Llanos basin of Colombia. The Castilla field, with an estimated 2.3 billion BBLS OOIP, produces heavy 14{prime} API oil, while the Chichimene NE field with an estimated 480 MMBBLS OOIP, produces a lighter 20{prime} API oil. Production is from multiple sandstone reservoirs of the Tertiary San Fernando and the Cretaceous Guadalupe Formations, and from massive non-marine sands of the Cretaceous Une Formation. Early problems with water coning and high water cuts led to detailed geologic study and engineering simulation to determine the most effective methods ofmore » reservoir management. The fresh nature of the connate water made evaluation more complicated, but results of RST (Reservoir Saturation Tool) logging runs on producing wells support the conclusions of the simulation studies regarding the potential for vertical drainage of the reservoir. As a result, the massive sands of the Une Formation can be perforated in the upper portion of the reservoir only, still enabling effective drainage of the lower reservoir while reducing water production and coning problems.« less

Zircon U-Pb ages and Hf isotopic compositions indicate multiple sources for Grenvillian detrital zircon deposited in western Laurentia

NASA Astrophysics Data System (ADS)

Howard, Amanda L.; Farmer, G. Lang; Amato, Jeffrey M.; Fedo, Christopher M.

2015-12-01

Combined U-Pb ages and Hf isotopic data from 1.0 Ga to 1.3 Ga (Grenvillian) detrital zircon in Neoproterozoic and Cambrian siliciclastic sedimentary rocks in southwest North America, and from igneous zircon in potential Mesoproterozoic source rocks, are used to better assess the provenance of detrital zircon potentially transported across Laurentia in major river systems originating in the Grenville orogenic highlands. High-precision hafnium isotopic analyses of individual ∼1.1 Ga detrital zircon from Neoproterozoic siliciclastic sedimentary rocks in Sonora, northern Mexico, reveal that these zircons have low εHf (0) (-22 to -26) and were most likely derived from ∼1.1 Ga granitic rocks embedded in local Mojave Province Paleoproterozoic crust. In contrast, Grenvillian detrital zircons in Cambrian sedimentary rocks in Sonora, the Great Basin, and the Mojave Desert, have generally higher εHf (0) (-15 to -21) as demonstrated both by high precision solution-based, and by lower precision laser ablation, ICPMS data and were likely derived from more distal sources further to the east/southeast in Laurentia. Comparison to new and existing zircon U-Pb geochronology and Hf isotopic data from Grenvillian crystalline rocks from the Appalachian Mountains, central and west Texas, and from Paleoproterozoic terranes throughout southwest North America reveals that zircon in Cambrian sandstones need not entirely represent detritus transported across the continent from Grenville province rocks in the vicinity of the present-day southern Appalachian Mountains. Instead, these zircons could have been derived from more proximal, high εHf (0), ∼1.1 Ga, crystalline rocks such as those exposed today in the Llano Uplift in central Texas and in the Franklin Mountains of west Texas. Regardless of the exact source(s) of the Grenvillian detrital zircon, new and existing whole-rock Nd isotopic data from Neoproterozoic to Cambrian siliciclastic sedimentary rocks in the Mojave Desert demonstrate that the occurrences of higher εHf (0), Grenvillian detrital zircons are decoupled from the sources of the bulk of the sedimentary detritus in which the zircons are entrained. The Cambrian Wood Canyon Formation and the underlying ;off craton; Neoproterozoic Johnnie Formation and Stirling Quartzite all contain higher εHf (0), Grenvillian detrital zircon, in some cases as the dominant detrital zircon population. However, only portions of the Wood Canyon Formation have whole rock Nd isotopic compositions consistent with a bulk sediment source in ∼1.1 Ga sources rocks. Whole rock Nd isotopic compositions of the remaining portions of this unit, and all of the Johnnie Formation and Stirling Quartzite, require bulk sediment sources principally in Paleoproterozoic continental crust. We consider the observed decoupling in the sources of Grenvillian detrital zircon and bulk sediment in the Wood Canyon Formation and underlying siliciclastic sediments as a demonstration that detrital zircon U-Pb and Hf isotopic data alone can provide an incomplete picture of the source of sediments that comprise a given siliciclastic stratigraphic unit.

Water quality in the vicinity of Mosquito Creek Lake, Trumbull County, Ohio, in relation to the chemistry of locally occurring oil, natural gas, and brine

USGS Publications Warehouse

Barton, G.J.; Burruss, R.C.; Ryder, R.T.

1998-01-01

Environmental samples collected in the Mosquito Creek Lake area were used to characterize water quality in relation to the chemistry of locally occurring oil, natural gas, and brine and to establish baseline water quality. Mosquito Creek Lake (a manmade reservoir) and the shallow bedrock aquifers near the lake are major sources of potable water in central Trumbull County. The city of Warren relies on the lake as a sole source of potable water. Some of the lake bottom may be in direct hydraulic connection with the underlying aquifers. The city of Cortland, along the southeastern shore of the lake, relies on the Cussewago Sandstone aquifer as a sole source of potable water. This aquifer subcrops beneath the glacio-fluvial sediments that underlie the lake. Nearly all residential homes around the lake, with the exception of homes in the city of Cortland, rely on domestic supply wells as a source of potable water.Oil and natural gas exploration and production have been ongoing in the Mosquito Creek Lakearea since the discovery of the historic Mecca Oil Pool in the Mississippian Berea and Cussewago Sandstones in 1860. Since the late 1970' s, the major drilling objective and zone of production is the Lower Silurian Clinton sandstone. The oil and natural gas resources of the Mosquito Creek Lake area, including reservoir pressure, production history, and engineering and abandonment practices are described in this report.The chemical and isotopic characteristics of the historic Mecca oil and natural gas are very different than those of the Clinton sandstone oil and natural gas. Gas chromatograms show that Mecca oil samples are extensively altered by biodegradation, whereas Clinton sandstone oils are not. Extensive alteration of Mecca oil is consistent with their occurrence at very shallow depths (less than 100 ft below land surface) where microbial activity can affect their composition. Also, the carbon-isotope composition of dissolved methane gas from Berea and Cussewago Sandstone water samples indicates that the gas is microbially generated, whereas the Clinton sandstone gases are thermogenically generated.Methane gas, in addition to crude oil, occurs naturally in the shallow Berea and Cussewago Sandstone aquifers in the Mosquito Creek Lake area and concentrations of dissolved methane are significant in the city of Cortland public-supply wells and in the domestic-supply wells near the southern shore of the lake. Water associated with oil and gas in the Clinton sandstone is a brine with high concentrations of chloride. Water from the Berea and Cussewago Sandstones, however, is fresh and potable. The contrasting geochemical characteristics are important for addressing water-quality issues that relate to oil and natural gas development in the Mosquito Creek area.A reexamination of the geologic framework and results of a subsurface-gas survey show that crude oil in the historic Mecca Oil Pool probably does not seep into Mosquito Creek Lake. Environmental samples show no evidence of any measurable release of oil, gas, or brine from the deeper Clinton sandstone oil and gas wells to the shallow aquifers, the lake, or lake tributaries. Brine is not associated with the hydrocarbons in the shallow Berea-Cussewago aquifer system and therefore cannot be a source of brine contamination. A mixing diagram constructed for dissolved bromide and chloride in surface water and water-supply wells shows no demonstrable mixing of these water resources with brine from the Clinton sandstone. There is some notable salinity in surface waters; however, the water is bromide poor, and a mixing diagram indicates that some local ground waters are influenced by halite solutions, presumably derived from leaching of road salt or from septic effluent.

Estimate of ground water in storage in the Great Lakes basin, United States, 2006

USGS Publications Warehouse

Coon, William F.; Sheets, Rodney A.

2006-01-01

Hydrogeologic data from Regional Aquifer System Analyses (RASA) studies by the U.S. Geological Survey in the Great Lakes Basin, United States, during 1978-95, were compiled and used to estimate the total volume of water that is stored in the many aquifers of the basin. These studies focused on six regional aquifer systems: the Cambrian-Ordovician aquifer system in Wisconsin, Illinois, and Indiana; the Silurian- Devonian aquifers in Wisconsin, Michigan, Illinois, Indiana, and Ohio; the surficial aquifer system (aquifers of alluvial and glacial origin) found throughout the Great Lakes Basin; and the Pennsylvanian sandstone and carbonate-rock aquifers and the Mississippian sandstone aquifer in Michigan. Except for the surficial aquifers, all of these aquifer systems are capable of yielding substantial quantities of water and are not small aquifers with only local importance. Individual surficial aquifers, although small in comparison to the bedrock aquifers, collectively represent large potential sources of ground water and therefore have been treated as a regional system. Summation of ground-water volumes in the many regional aquifers of the basin indicates that about 1,340 cubic miles of water is in storage; of this, about 984 cubic miles is considered freshwater (that is, water with dissolved-solids concentration less than 1,000 mg/L). These volumes should not be interpreted as available in their entirety to meet water-supply needs; complete dewatering of any aquifer is environmentally undesirable. The amount of water that is considered available on the basis of water quality and environmental, economic, and legal constraints has not been determined. The effect of heavy pumping in the Chicago, Ill., and Milwaukee, Wis., areas, which has caused the regional ground-water divide in the Cambrian-Ordovician aquifer system to shift westward, has been included in the above estimates. This shift in the ground-water divide has increased the amount of water in storage in the deep-bedrock aquifers of the Great Lakes Basin by about 36 cubic miles; however, this water is removed by wells and, after use, is mostly discharged to the Mississippi River Basin rather than to the Great Lakes Basin. The corresponding decrease in ground-water storage that has resulted from lowering of the potentiometric surface due to this heavy pumping (0.059 cubic miles) is negligible compared to the total estimated storage.

Real rock-microfluidic flow cell: A test bed for real-time in situ analysis of flow, transport, and reaction in a subsurface reactive transport environment.

PubMed

Singh, Rajveer; Sivaguru, Mayandi; Fried, Glenn A; Fouke, Bruce W; Sanford, Robert A; Carrera, Martin; Werth, Charles J

2017-09-01

Physical, chemical, and biological interactions between groundwater and sedimentary rock directly control the fundamental subsurface properties such as porosity, permeability, and flow. This is true for a variety of subsurface scenarios, ranging from shallow groundwater aquifers to deeply buried hydrocarbon reservoirs. Microfluidic flow cells are now commonly being used to study these processes at the pore scale in simplified pore structures meant to mimic subsurface reservoirs. However, these micromodels are typically fabricated from glass, silicon, or polydimethylsiloxane (PDMS), and are therefore incapable of replicating the geochemical reactivity and complex three-dimensional pore networks present in subsurface lithologies. To address these limitations, we developed a new microfluidic experimental test bed, herein called the Real Rock-Microfluidic Flow Cell (RR-MFC). A porous 500μm-thick real rock sample of the Clair Group sandstone from a subsurface hydrocarbon reservoir of the North Sea was prepared and mounted inside a PDMS microfluidic channel, creating a dynamic flow-through experimental platform for real-time tracking of subsurface reactive transport. Transmitted and reflected microscopy, cathodoluminescence microscopy, Raman spectroscopy, and confocal laser microscopy techniques were used to (1) determine the mineralogy, geochemistry, and pore networks within the sandstone inserted in the RR-MFC, (2) analyze non-reactive tracer breakthrough in two- and (depth-limited) three-dimensions, and (3) characterize multiphase flow. The RR-MFC is the first microfluidic experimental platform that allows direct visualization of flow and transport in the pore space of a real subsurface reservoir rock sample, and holds potential to advance our understandings of reactive transport and other subsurface processes relevant to pollutant transport and cleanup in groundwater, as well as energy recovery. Copyright © 2017 Elsevier B.V. All rights reserved.

The effects of steam injection in a sandstone reservoir (Etchegoin Formation), Buena Vista field, California

DOE Office of Scientific and Technical Information (OSTI.GOV)

Grant, C.W.; Reed, A.A.

1991-03-01

At Buena Vista field, California, 120 ft of post-steamflood core, spanning the middle Pliocene Wilhelm Member of the Etchegoin Formation, was taken to assess the influence of stratigraphy on light-oil steamflood (LOSF) processes and to determine what steam-rock reactions occurred and how these affected reservoir properties. High-quality steam (600F (300C)) had been injected ({approximately}1,700 psi) into mixed tidal flat and estuarine facies in an injector well located 55 ft from the cored well. Over a period of 20 months, steam rapidly channeled through a thin ({approximately}7 ft), relatively permeable (1-1,000 md), flaser-bedded sandstone unit. Conductive heating above this permeable unitmore » produced, in the vicinity of the cored well, a 35-ft steam-swept zone (oil saturation = 0), overlain by a 29-ft steam-affected zone in which oil saturation had been reduced to 13%, far below the presteam saturation of 30%. Steam-induced alteration ('artificial diagenesis') of the clay-rich reservoir rock was recognized using SEM, petrography, and X-ray diffraction. Salient dissolution effects were the complete to partial removal of siliceous microfossils, Fe-dolomite, volcanic rock fragments, and labile heavy minerals. The artificial diagenetic effects are first encountered in the basal 6 ft of the 29-ft steam-affected zone. Based on the distribution of the authigenic phases, the authors conclude that the reactions took place, or were at least initiated, in the steam condensate bank ahead of the advancing steam front. Although these changes presumably reduced permeability, the steamflood process was effective in reducing oil saturation to zero in the steam-contacted portion of the reservoir.« less

The Effect of Hydrous Supercritical Carbon Dioxide on the Mohr Coulomb Failure Envelope in Boise Sandstone

NASA Astrophysics Data System (ADS)

Choens, R. C., II; Dewers, T. A.; Ilgen, A.; Espinoza, N.; Aman, M.

2016-12-01

Experimental rock deformation was used to quantify the relationship between supercritical carbon dioxide (scCO2), water vapor, and failure strength in an analog for Tertiary sandstone saline formation reservoirs. Storing large volumes of carbon dioxide in depleted petroleum reservoirs and deep saline aquifers over geologic time is an important tool in mitigating effects of climate change. Carbon dioxide is injected as a supercritical phase, where it forms a buoyant plume. At brine-plume interfaces, scCO2 dissolves over time into the brine, lowering pH and perturbing the local chemical environment. Previous work has shown that the resulting geochemical changes at mineral-fluid interfaces can alter rock mechanical properties, generally causing a decrease in strength. Additionally, water from the native brine can dissolve into the scCO2 plume where it is present as humidity. This study investigates the effect of hydrous scCO2 and CO2-saturated brine on shear failure of Boise sandstone. Samples are held in a hydrostatic pressure vessel at 2250 PSI confining pressure (PC) and 70 C, and scCO2 at specific humidity is circulated through the core for 24 hours at 2000 PSI and 70 C. Experiments are conducted at relative humidity levels of 0, 14, 28, 42, 56, 70, 84, 98, and 100% relative humidity. After the scCO2 core flood is finished, triaxial compression experiments are conducted on the samples at room temperature and an axial strain rate of 10-5 sec-1. Experiments are conducted at 500, 1000, and 1500 PSI PC. The results demonstrate that water present as humidity in scCO2 can reduce failure strength and lower slopes of the Mohr-Coulomb failure envelope. These effects increase with increasing humidity, as dry scCO2 does not affect rock strength, and may be influenced by capillary condensation of water films from humid scCO2. The reductions in failure strength seen in this study could be important in predicting reservoir response to injection, reservoir caprock integrity, and borehole stability of injection wells. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Department of Energy's National Security Administration under contract DE-AC04-94AL85000. SAND2016-7552A

Calibrating rates of early Cambrian evolution.

PubMed

Bowring, S A; Grotzinger, J P; Isachsen, C E; Knoll, A H; Pelechaty, S M; Kolosov, P

1993-09-03

An explosive episode of biological diversification occurred near the beginning of the Cambrian period. Evolutionary rates in the Cambrian have been difficult to quantify accurately because of a lack of high-precision ages. Currently, uranium-lead zircon geochronology is the most powerful method for dating rocks of Cambrian age. Uranium-lead zircon data from lower Cambrian rocks located in northeast Siberia indicate that the Cambrian period began at approximately 544 million years ago and that its oldest (Manykaian) stage lasted no less than 10 million years. Other data indicate that the Tommotian and Atdabanian stages together lasted only 5 to 10 million years. The resulting compression of Early Cambrian time accentuates the rapidity of both the faunal diversification and subsequent Cambrian turnover.

Understanding of the carbon dioxide sequestration in extremely low-permeability saline aquifers in the Ordos Basin

NASA Astrophysics Data System (ADS)

Zhang, K.; Xie, J.; Hu, L.; Wang, Y.; Chen, M.

2014-12-01

A full-chain CCS demonstration project was started in 2010 by capturing and injecting around 100,000 tons of CO2 per annum into extremely low-permeability sandstone formations in the northeastern Ordos basin, Inner Mongonia, China. It is the first demonstration project in China for the purpose of public interests by sequestrating in the deep saline aquifers massive amount of CO2 captured from a coal liquefaction company. The injection takes place in overall five brine-bearing geological units that are composed of four sandstones and one carbonate, which are interbedded with various mudstone caprocks. A single vertical well was drilled to the depth of 2826m. Injection screens are opened to more than 20 thin aquifers distributed between the depth 1690m-2453m with a total of 88 m injecting thickness. The permeability for all the storage formations is less 10 md and porosity is in the range of 1-12%. Hydraulic fracturing and formation acidizing were conducted at 10 layers for reservoir improvement. Up to present, total injection of CO2 is about 280,000 tons. Injection pressure drops from around 8.5 MP at the beginning to less than 5MP at present and most CO2 goes to shallowest injection formation at the depth interval 1690-1699 m, which has not been conducted any reservoir improvement. We intend to understand the improving injectivity of such low permeability reservoirs with numerical simulations. The modeling results reasonably describe the spreading of the CO2 plume. After 3 years of injection of CO2, the maximum migrating distance of CO2 plume is about 500 m and the pore pressure build-up is slightly less than 15 MPa. The major storage reservoir at the depth interval 1690-1699 m contributes over 80% of the storage capacity of the entire reservoir system.

An assessment on CO2 geosequestration in deep saline formations in the Taihsi Basin, central Taiwan

NASA Astrophysics Data System (ADS)

Cai, Mo-Si; Lin, Andrew T.; Fan, Jhen-Huei

2015-04-01

Geological storage of carbon dioxide (CO2) is to inject and store a large amount of anthropogenic CO2 in deep and sealed porous rocks in order to mitigate the aggravated threat of global climate changes. Borehole and reflection seismic data are used to understand the spatial distribution of suitable CO2 reservoirs and cap rocks in the Taihsi Basin, central Taiwan, where the level of seismicity is low. The Taihsi Basin was a rift basin during the Paleocene to Eocene, followed by a phase of post-rift subsidence during late Oligocene to late Miocene. The loading of the Taiwan mountain belt since late Miocene has turned the Taihsi Basin into a peripheral foreland basin, with strata gently dipping toward the mountain belts in the east. The coastal plain in central Taiwan (Changhua and Yunlin Counties) and its adjacent offshore areas are close to major CO2 emission sources and no active geological structures are found in these areas, making the study area a favorable CO2 storage site. Spatial distribution of formation thickness and depth for CO2 reservoirs and cap rocks indicates three CO2 storage systems existed in the study area. They are: (1) late Miocene to Pliocene Nanchuang Formation and Kueichulin Formation (reservoirs)-Chinshui Shale (seals) system (hereafter abbreviated as NK-C system), (2) early to middle Miocene Shihti Formation and Peiliao Formation (reservoirs)-Talu Shale (seals) system (SP-T system), (3) early Miocene Mushan Formation (reservoirs)-Piling Shale (seals) system (M-P system). The NK-C system contains multiple layers of porous sandstones from Nanchuang and Kueichulin formations, with total thickness around 210-280 m. In the vicinity of the northern bank of the Jhuoshuei River, reservoir top reaches a depth around 1850 m, with 60 m thick seal formation, the Chinshui Shale. However, the Chinshui Shale becomes sand-prone in the Changhua coastal and nearshore areas due to facies changes. The SP-T system consists of two porous sandstone layers from the Peiliao Formation and the underlying Shihti Formation, with thickness spanning in the range of 30-60 m and 40-60 m, respectively. Reservoir top reaches a depth around 2200 m, with average 150 m thick seal formation, the Talu Shale, in the vicinity of the northern bank of the Jhuoshuei River. The M-P system contains multiple layers of porous sandstones from Mushan Formation, with total thickness around 150-300 m. In the vicinity of the northern bank of the Jhuoshuei River and the southern bank of the Wu River, reservoir top reaches a depth around 2700 m and over 3000 m respectively, with 80-150 m thick seal formation, the Piling Shale. However, Mushan Formation thins southwardly toward the Peikang High and is locally absent in the vicinity of the southern bank of the Jhuoshuei River. For the NK-C system, although it contains thick reservoirs the seal formation (i.e. the Chinshui Shale) becomes sand-prone due to facies changes, leading to a higher risk of sealing capability. For the SP-T and M-P systems, both reservoirs and seals are all thick enough to contain injected CO2, excluding a local area in the vicinity of southern bank of the Jhuoshuei River, where reservoir is absent for the M-P system. In addition, north of the study area and close to the Wu River, reservoirs for the M-P system reach a depth more than 3000 m, a depth too deep for storing CO2 economically. Our results indicate that the SP-T system is the most prominent option for CO2 geosequestration in terms of depths and formation thicknesses, with M-P and NK-C systems as alternative ones, respectively.

Observations on the geology and petroleum potential of the Cold Bay-False Pass area, Alaska Peninsula

USGS Publications Warehouse

McLean, Hugh James

1979-01-01

Upper Jurassic strata in the Black Hills area consist mainly of fossiliferous, tightly cemented, gently folded sandstone deposited in a shallow marine environment. Upper Cretaceous strata on Sanak Island are strongly deformed and show structural features of broken formations similar to those observed in the Franciscan assemblage of California. Rocks exposed on Sanak Island do not crop out on the peninsular mainland or on Unimak Island, and probably make up the acoustic and economic basement of nearby Sanak basin. Tertiary sedimentary rocks on the outermost part of the Alaska Peninsula consist of Oligocene, Miocene, and lower Pliocene volcaniclastic sandstone, siltstone, and conglomerate deposited in nonmarine and very shallow marine environments. Interbedded airfall and ash-flow tuff deposits indicate active volcanism during Oligocene time. Locally, Oligocene strata are intruded by quartz diorite plutons of probable Miocene age. Reservoir properties of Mesozoic and Tertiary rocks are generally poor due to alteration of chemically unstable volcanic rock fragments. Igneous intrusions have further reduced porosity and permeability by silicification of sandstone. Organic-rich source rocks for petroleum generation are not abundant in Neogene strata. Upper Jurassic rocks in the Black Hills area have total organic carbon contents of less than 0.5 percent. Deep sediment-filled basins on the Shumagin Shelf probably contain more source rocks than onshore correlatives, but reservoir quality is not likely to be better than in onshore outcrops. The absence of well-developed folds in most Tertiary rocks, both onshore and in nearby offshore basins, reduces the possibility of hydrocarbon entrapment in anticlines.

The effects of burial diagenesis on multiscale porosity in the St. Peter Sandstone: An imaging, small-angle, and ultra-small-angle neutron scattering analysis

DOE PAGES

Anovitz, Lawrence M.; Freiburg, Jared T.; Wasbrough, Matthew; ...

2017-11-06

To examine the effects of burial diagenesis on heirarchical pore structures in sandstone and compare those with the effects of overgrowth formation, we obtained samples of St. Peter Sandstone from drill cores obtained in the Illinois and Michigan Basins. The multiscale pore structure of rocks in sedimentary reservoirs and the mineralogy associated with those pores are critical factors for estimating reservoir properties, including fluid mass in place, permeability, and capillary pressures, as well as geochemical interactions between the rock and the fluid. The combination of small- and ultra-small-angle neutron scattering with backscattered electron or X ray-computed tomographic imaging, or both,more » provided a means by which pore structures were quantified at scales ranging from aproximately 1 nm to 1 cm—seven orders of magnitude. Larger scale (>10 µm) porosity showed the expected logarithmic decrease in porosity with depth, although there was significant variation in each sample group. However, small- and ultra-small-angle neutron scattering data showed that the proportion of small-scale porosity increased with depth. Porosity distributions were not continuous, but consisted of a series of log normal-like distributions at several distinct scales within these rocks. Fractal dimensions at larger scales decreased (surfaces smoothed) with increasing depth, and those at smaller scales increased (surfaces roughened) and pores become more isolated (higher lacunarity). Furthermore, data suggest that changes in pore-size distributions are controlled by both physical (compaction) and chemical effects (precipitation, cementation, dissolution).« less

The effects of burial diagenesis on multiscale porosity in the St. Peter Sandstone: An imaging, small-angle, and ultra-small-angle neutron scattering analysis

DOE Office of Scientific and Technical Information (OSTI.GOV)

Anovitz, Lawrence M.; Freiburg, Jared T.; Wasbrough, Matthew

To examine the effects of burial diagenesis on heirarchical pore structures in sandstone and compare those with the effects of overgrowth formation, we obtained samples of St. Peter Sandstone from drill cores obtained in the Illinois and Michigan Basins. The multiscale pore structure of rocks in sedimentary reservoirs and the mineralogy associated with those pores are critical factors for estimating reservoir properties, including fluid mass in place, permeability, and capillary pressures, as well as geochemical interactions between the rock and the fluid. The combination of small- and ultra-small-angle neutron scattering with backscattered electron or X ray-computed tomographic imaging, or both,more » provided a means by which pore structures were quantified at scales ranging from aproximately 1 nm to 1 cm—seven orders of magnitude. Larger scale (>10 µm) porosity showed the expected logarithmic decrease in porosity with depth, although there was significant variation in each sample group. However, small- and ultra-small-angle neutron scattering data showed that the proportion of small-scale porosity increased with depth. Porosity distributions were not continuous, but consisted of a series of log normal-like distributions at several distinct scales within these rocks. Fractal dimensions at larger scales decreased (surfaces smoothed) with increasing depth, and those at smaller scales increased (surfaces roughened) and pores become more isolated (higher lacunarity). Furthermore, data suggest that changes in pore-size distributions are controlled by both physical (compaction) and chemical effects (precipitation, cementation, dissolution).« less

Geology of the Aspen 15-minute quadrangle, Pitkin and Gunnison counties, Colorado

USGS Publications Warehouse

Bryant, Bruce

1979-01-01

The Aspen area, located 170 km southwest of Denver, Colo., lies at the intersection of the northeast-trending Colorado mineral belt and the west margin of the north-trending Sawatch uplift of Laramide age; it is within the southwest part of the northwest-trending late Paleozoic Eagle basin. Precambrian shales and graywackes, perhaps as old as 2 billion years (b.y.), were converted to sillimanite-bearing gneiss and muscovite-biotite schist 1.65-1.70 b.y. ago. They were deformed into northeast-plunging folds and were migmatized, and they were intruded by quartz diorite, porphyritic quartz monzonite, and granite. Muscovite-biotite quartz monzonite intruded this older Precambrian terrane about 1.45 b.y. ago and is the predominant Precambrian rock near Aspen. Uplift, some faulting, and much erosion occurred during the 900-million year (m.y.) interval between emplacement of the plutonic rocks and deposition of Upper Cambrian sediments. From Late Cambrian through Mississippian the region was part of a broad area alternately covered by shallow seas or occupied by low-lying land. Quartzite, dolomite, and limestone 200-320 m thick, comprising the Sawatch Quartzite and Peerless Formation (Cambrian), Manitou Dolomite (Ordovician), Chaffee Group (Mississippian(?) and Devonian), and Leadville Limestone (Mississippian) were deposited during this interval. After an hiatus during which soil formation and solution of the Leadville Limestone took place in the Late Mississippian, a thick sequence of marine and nonmarine clastic rocks was deposited in the newly developing Eagle basin during the late Paleozoic and early Mesozoic. Deposition of about 300 m of carbonaceous shale, limestone, dolomite, and minor siltstone and evaporite of the Belden Formation began in a shallow sea in Early and Middle Pennsylvanian time. Facies relations indicate that the northwest-trending Uncompahgre uplift southwest of Aspen, if present at that time, had very low relief. The overlying Middle Pennsylvanian Gothic Formation of Langenheim (1952) contains calcareous sandstone, siltstone, shale, limestone, and evaporite. Its clastic debris, significantly coarser than that in the Belden, signals the initial rise of the Uncompahgre uplift bordering the Eagle basin on the southwest; the Gothic here lacks the conglomerates and fossiliferous marine limestones found closer to the uplift. Red terrigenous clastic rocks and minor limestone and evaporite of the Maroon Formation as much as 3,200 m thick, deposited mainly in a fluvial flood-plain environment during the rest of the Pennsylvanian and the Early Permian, indicate withdrawal of the sea caused by further uplift of the Uncompahgre highland. Following an hiatus accompanied by local folding, the red conglomerate, sandstone, and siltstone of the State Bridge Formation (Late Permian and Early Triassic) was deposited in a fluvial-lacustrine environment adjacent to a much-expanded Uncompahgre uplift; a significant part of the State Bridge is material recycled from the Maroon Formation exposed to erosion on the flank of the uplift. The State Bridge, absent towards the south, becomes thicker and finer grained towards the north. The Chinle Formation (Late Triassic) rests with angular unconformity on the State Bridge Formation. The Chinle contains a basal discontinuous quartz-pebble conglomerate (Gartra Member) and is chiefly calcareous siltstone and limestone, with some beds of sandstone and conglomerate composed of fragments derived from the limestone beds. The Chinle was deposited on flood plains and in lakes by streams. Storms may have disrupted the sediments in the lakes producing the limestone pebble conglomerates. The lack of feldspar in the Chinle indicates that the nearby part of the Uncompahgre uplift was not a sediment source, or was covered by a deeply weathered feldspar-free mantle. The formation, absent towards the south, thickens toward the north. Thicknesses of the Maroon, State Bridge, and Ch

Geological studies of the COST nos. G-1 and G-2 wells, United States North Atlantic outer continental shelf

USGS Publications Warehouse

Scholle, Peter A.; Wenkam, Chiye R.

1982-01-01

The COST Nos. G-1 and G-2 wells (fig. 1) are the second and third deep stratigraphic test wells drilled in the North Atlantic Outer Continental Shelf of the United States. COST No. G-1 was drilled in the Georges Bank basin to a total depth of 16,071 ft (4,898 m). G-1 bottomed in phyllite, slate, and metaquartzite overlain by weakly metamorphosed dolomite, all of Cambrian age. From approximately 15,600 to 12,400 ft (4,755 to 3,780 m) the strata are Upper Triassic(?), Lower Jurassic(?), and Middle Jurassic, predominantly red shales, sandstones, and conglomerates. Thin, gray Middle Jurassic beds of shale, sandstone, limestone, and dolomite occur from 12,400 to 9,900 ft (3,780 to 3,018 m). From 9,900 to 1,030 ft (3,018 to 314 m) are coarse-grained unconsolidated sands and loosely cemented sandstones, with beds of gray shale, lignite, and coal. The microfossils indicate the rocks are Upper Jurassic from 10,100 ft (3,078 m) up to 5,400 ft (1,646 m) and Cretaceous from that depth to 1,030 ft (314 m). No younger or shallower rocks were recovered in the drilling at the COST No. G-1 site, but an Eocene limestone is inferred to be disconformable over Santonian strata. The Jurassic strata of the COST No. G-1 well were deposited in shallow marine, marginal marine, and nonmarine environments, which changed to a dominantly shallow marine but still nearshore environment in the Cretaceous. The COST No. G-2 well was drilled 42 statute miles {68 km) east of the G-1 site, still within the Georges Bank basin, to a depth of 21,874 ft (6,667 m). The bottom 40 ft (12 m) of salt and anhydrite is overlain by approximately 7,000 ft {2,134 m) of Upper Triassic{?), Lower Jurassic{?) and Middle Jurassic dolomite, limestone, and interbedded anhydrite from 21,830 to 13,615 ft (6,654 to 4,153 m). From 13,500 to 9,700 ft (4,115 to 2,957 m) are Middle Jurassic limestones with interbedded sandstone. From 9,700 to 4,000 ft (2,957 to 1,219 m) are Upper Jurassic and Cretaceous interbedded sandstones and limestones overlain by Upper Cretaceous unconsolidated sands, sandstones, and calcareous shales. Pliocene, Miocene, Eocene, and Paleocene strata are disconformable over Santonian rocks; uppermost Cretaceous rocks are missing at this site, as at G-1. The sedimentary rocks in the COST No. G-2 well were deposited in somewhat deeper water, farther away from sources of terrigenous material than those at G-l, but still in marginal marine to shallow marine environments. Data from geophysical logs and examination of conventional cores, wellcuttings, and sidewall cores show that below 10,000 ft {3,048 m), the strata in both wells have moderate porosities {< 20 percent) and low to moderate permeabilities {< 100 mD) and are thus considered adequate to poor reservoir rocks. Above 10,000 ft (3,000 m) the porosities range from 16 to 39 percent, and the permeabilities are highly variable, ranging from 0.01 to 7,100 mD. Measurements of vitrinite reflectance, color alteration of visible organic matter, and various organic geochemical properties suggest that the Tertiary and Cretaceous strata of the COST Nos. G-1 and G-2 are not prospective for oil and gas. These sediments have not been buried deeply enough for hydrocarbon generation, and the kerogen and extractable organic matter in them are thermally immature. However, the Jurassic rocks at the G-1 site do contain small amounts of thermally mature gas-prone kerogens. The Jurassic rocks at COST No. G-2 are also gas-prone and are slightly richer in organic carbon and total extractable hydrocarbons than the G-1 rocks, but both sites have only poor to fair oil and gas source-rock potential.

Measuring and predicting reservoir heterogeneity in complex deposystems. Annual report, September 20, 1990--September 20, 1991

DOE Office of Scientific and Technical Information (OSTI.GOV)

Donaldson, A.; Shumaker, R.; Laughrey, C.

1992-08-01

The Lower Mississippian Big Injun sandstone, a major oil producer in the western half of West Virginia, consists of several sandstones that overstep each west. Examination of cores and thin sections has led to preliminary interpretations of depositional environments for the Big Injun. These include distributary-mouth bars with associated distal, bar crest and back bar environments in a marine-deltaic system; and channel, point bar and chute environments in a fluvial system. Overall, the Big Injun is a medium-grained sublitharenite in which initially high porosity has been modified by compaction and diagenesis. Chlorite grain coatings helped to preserve original porosity, whereasmore » illite promoted pressure solution during compaction, resulting in a loss of porosity. Diagenetic effects within specific environments are being evaluated to determine if environmental interpretations can be used to predict porosity preservation. Core plugs taken from cores in Granny Creek field were analyzed for porosity and horizontal and vertical permeability. Directional permeability was negligible, but permeability does correlate with depth. Changes in permeability with depth can be related to subdivisions of the Big Injun determined from density logs. Permeability also correlated with porosity, but porosity values derived from both cores and logs show no significant correlation trend at present. A layered reservoir model is being developed to evaluate the effect of these vertical heterogeneities. Initial attempts to characterize the heterogeneity of the Big Injun reservoir in Granny Creek field used a number of direct and indirect methods.« less

Measuring and predicting reservoir heterogeneity in complex deposystems

DOE Office of Scientific and Technical Information (OSTI.GOV)

Donaldson, A.; Shumaker, R.; Laughrey, C.

1992-08-01

The Lower Mississippian Big Injun sandstone, a major oil producer in the western half of West Virginia, consists of several sandstones that overstep each west. Examination of cores and thin sections has led to preliminary interpretations of depositional environments for the Big Injun. These include distributary-mouth bars with associated distal, bar crest and back bar environments in a marine-deltaic system; and channel, point bar and chute environments in a fluvial system. Overall, the Big Injun is a medium-grained sublitharenite in which initially high porosity has been modified by compaction and diagenesis. Chlorite grain coatings helped to preserve original porosity, whereasmore » illite promoted pressure solution during compaction, resulting in a loss of porosity. Diagenetic effects within specific environments are being evaluated to determine if environmental interpretations can be used to predict porosity preservation. Core plugs taken from cores in Granny Creek field were analyzed for porosity and horizontal and vertical permeability. Directional permeability was negligible, but permeability does correlate with depth. Changes in permeability with depth can be related to subdivisions of the Big Injun determined from density logs. Permeability also correlated with porosity, but porosity values derived from both cores and logs show no significant correlation trend at present. A layered reservoir model is being developed to evaluate the effect of these vertical heterogeneities. Initial attempts to characterize the heterogeneity of the Big Injun reservoir in Granny Creek field used a number of direct and indirect methods.« less

Pinedale unit MHF experiments. Final report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Not Available

1976-10-01

Three MHF experiments have been performed in a tight reservoir in the Northern Green River Basin at depths between 8,000 and 12,000 feet. A total of 894,190 gallons of fluid and 2,715,000 pounds of sand were pumped in three stages in two wells with the limited entry technique. Fluid viscosities were designed to give propped lengths of 1,000 to 1,500 feet and proppant sand beds having heights greater than 50 percent of the thickness of each sandstone fractured. The experiments included laboratory research to design limited entry with perforations through one and two strings of casing. Field data analysis tomore » determine fracture gradients and extent of perforation erosion has been complicated by a dependence of friction pressure in tubular goods upon sand concentration and by an apparent large variation in minimum principal in-situ stress between sandstones simultaneously fractured with the limited entry technique. A high proppant concentration was used to assure that production would be limited to reservoir characteristics, rather than fracture conductivity. Comparison was made with results of prior hydraulic fractures propped with a partial monolayer. Resulting production capacity to date has been only about one-fifth that projected in the National Gas Survey report. Evaluation of the resulting production capability and the cost of the hydraulic fracture treatmnet indicates that the stimulation technique employed is not commercially feasible at this time for the reservoir conditions tested. 10 fig, 6 tables.« less

Permeability-porosity data sets for sandstones

USGS Publications Warehouse

Nelson, P.H.

2004-01-01

Due to the variable nature of permeability-porosity relations, core should be obtained and permeability (k) and porosity (??) should be determined on core plugs in the laboratory for the formation of interest. A catalog of k versus (??) data sets is now available on the Web. Examples from the catalog are considered to illustrate some aspects of k versus ?? dependencies in siliciclastic reservoirs.

Late Jurassic – early Cretaceous inversion of rift structures, and linkage of petroleum system elements across post-rift unconformity, U.S. Chukchi Shelf, arctic Alaska

USGS Publications Warehouse

Houseknecht, David W.; Connors, Christopher D.

2015-01-01

Oil-prone source rocks, reservoir-quality sandstone, migration pathways, and structural closure are linked intimately across the Jurassic unconformity, which reflects inversion. Thus, all these key petroleum systems elements were in place when Triassic source rocks entered the oil generation window during Cretaceous–Cenozoic stratigraphic burial.

Lisburne Group (Mississippian and Pennsylvanian), potential major hydrocarbon objective of Arctic Slope, Alaska

USGS Publications Warehouse

Bird, Kenneth J.; Jordan, Clifton F.

1977-01-01

The Lisburne Group, a thick carbonate-rock unit of Mississippian and Pennsylvanian age, is one of the most widespread potential reservoir-rock units in northern Alaska. A comprehensive review of the Lisburne in the subsurface of the eastern Arctic Slope indicates attractive reservoir characteristics in a favorable source and migration setting where numerous trapping mechanisms appear to be available. Evaluation of this group as a potential exploration objective is particularly timely because of impending offshore sales in the Beaufort Sea and current exploration programs under way in the Prudhoe Bay area and the Naval Petroleum Reserve. Dolomite and sandstone have been identified as reservoir rocks. Oolitic grainstone is a common rock type, but observations indicate little reservoir potential owing to complete void filling by calcite cement. The most important reservoir rock as judged by thickness, areal extent, and predictability is microsucrosic (10 to 30µ) dolomite of intertidal to supratidal origin. It is present throughout the Lisburne and is most abundant near the middle of the sequence. Northward it decreases in thickness from 1,000 ft (300 m) to less than 100 ft (30 m). Porosity of the dolomite as determined in selected wells averages between 10 and 15% and attains a maximum of slightly more than 25%. Net thickness of reservoir rocks (i.e., rocks with greater than 5% porosity) ranges in these wells from 40 to 390 ft (40 to 120 m). Oil shows are common, and drill-stem tests have yielded as much as 1,600 bbl/day of oil and 22 MMcf/day of gas in the Lisburne pool of the Prudhoe Bay field and as much as 2,057 bbl/day of salt water outside the field area. The occurrence of dolomite over such a large area makes its presence in the offshore Beaufort Sea and adjacent Naval Petroleum Reserve 4 fairly certain. The presence of sandstone as thick as 140 ft (40 m) in the middle and upper part of the Lisburne in two coastal wells suggests that larger areas of sandstone may be found on the north in offshore areas. Shows of oil and gas and a saltwater flow of 1,470 bbl/day have been recorded from this sandstone facies. Shales of Permian and Cretaceous ages unconformably overlie the Lisburne, providing adequate sealing beds above potential reservoirs. Impermeable limestone (completely cemented grainstone) and thin beds of shale may serve as seals within the Lisburne, but the possibility of fractures in these units may negate their sealing capability. The most favorable source rock for Lisburne hydrocarbons appears to be Cretaceous shale that unconformably overlies the Lisburne east of Prudhoe Bay. This shale is reported to be a rich source rock and is the most likely source for the entire Prudhoe Bay field. A source within the Lisburne or within the underlying Kayak Shale is postulated for oil shows in the southernmost Lisburne wells. This postulated source may be in a more basinal facies of the Lisburne and may be similar to dark shale in the upper Lisburne in thrust slices to dark shale in the upper Lisburne in thrust slices in the Brooks Range. Coal in the underlying Endicott Group is a possible source for dry gas. At present, much of this coal probably is in a gas-generating regime downdip from the Prudhoe Bay field. Stratigraphic traps involving the Lisburne Group may have resulted from widespread Permian and Cretaceous unconformities. Structural traps related to normal faulting may be present along the trend of the Barrow arch, and faulted anticlines are numerous in the foothills of the Brooks Range. Combination traps are possible along the trend of the Barrow arch.

Composition of natural gas and crude oil produced from 14 wells in the Lower Silurian "Clinton" Sandstone and Medina Group Sandstones, northeastern Ohio and northwestern Pennsylvania: Chapter G.6 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Burruss, Robert A.; Ryder, Robert T.; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

The geochemical processes that control the distribution of hydrocarbons in the regional accumulation of natural gas and crude oil in reservoirs of Early Silurian age in the central Appalachian basin are not well understood. Gas and oil samples from 14 wells along a down-dip transect through the accumulation in northeastern Ohio and northwestern Pennsylvania were analyzed for molecular and stable isotopic compositions to look for evidence of hydrocarbon source, thermal maturation, migration, and alteration parameters. The correlation of carbon and hydrogen stable isotopic composition of methane with thermal maturation indicates that the deepest gases are more thermally mature than independent estimates of thermal maturity of the reservoir horizon based on the conodont alteration index. This correlation indicates that the natural gas charge in the deepest parts of the regional accumulation sampled in this study originated in deeper parts of the Appalachian basin and migrated into place. Other processes, including mixing and late-stage alteration of hydrocarbons, may also impact the observed compositions of natural gases and crude oils.

Hydrostratigraphic characterization of intergranular and secondary porosity in part of the Cambrian sandstone aquifer system of the cratonic interior of North America: Improving predictability of hydrogeologic properties

USGS Publications Warehouse

Runkel, Anthony C.; Tipping, R.G.; Alexander, E.C.; Alexander, S.C.

2006-01-01

The Upper Cambrian interval of strata in the cratonic interior of North America has a long history of inconsistent hydrogeologic classification and a reputation for marked and unpredictable variability in hydraulic properties. We employed a hydrostratigraphic approach that requires hydraulic data to be interpreted within the context of a detailed characterization of the distribution of porosity and permeability to arrive at a better understanding of these rocks. As a first step, we constructed a framework of hydrostratigraphic attributes that is a depiction of the spatial distribution of both rock matrix and secondary porosity, independent of hydraulic data such as pumping-test results. The locations of hundreds of borehole geophysical logs and laboratory measurements of rock sample matrix porosity and permeability were mapped on detailed (mostly 1:100,000 or greater), conventional, lithostratigraphic maps. Stratigraphic cross-sections, based on hundreds of natural gamma logs and thousands of water-well records, have provided a markedly improved depiction of the regional distribution of rock matrix hydrostratigraphic components. Borehole, core and outcrop observations of secondary porosity were also tied to detailed stratigraphic sections and interpolated regionally. As a second step, we compiled and conducted a large number of hydraulic tests (e.g., packer tests and borehole flowmeter logs) and analyzed thousands of specific capacity tests (converted to hydraulic conductivity). Interpretation of these data within the context of the hydrostratigraphic attributes allowed us to produce a new hydrogeologic characterization for this stratigraphic interval and gain important insights into geologic controls on hydraulic variability. There are a number of assumptions in herent in most previous hydrogeologic investigations of these strata, such as equivalency of lithostratigraphic and hydrogeologic units and the dominance of intergranular flow in sandstone, that are not consistent with our results. A particularly important outcome of our study is recognition of regionally extensive bedding-plane fracture clusters. Such exceptionally high hydraulic conductivity features dominate the hydraulics of aquifers and confining units in these siliciclastic-dominated strata, including within intervals consisting largely of friable sandstone with high intergranular conductivity. Furthermore, our results provide some measure of fracture predictability, by correlating their abundance and hydraulic importance to specific stratigraphic positions and particular depths of burial beneath younger bedrock. A discrete, consistent stratigraphic interval of fine-grained siliciclastic beds also is apparently resistant to the development of vertically interconnected fractures, making the location of this regionally extensive confining unit predictable. Our more rigorous approach of interpreting typical hydraulic tests as well as relatively new techniques of borehole flowmeter logging, within the context of a hydrostratigraphic framework, results in improved definition of individual aquifers and confining units. It also enables quantification of their hydraulic properties, which leads to improved prediction of groundwater flow paths and time-of-travel. ?? 2005 Elsevier B.V. All rights reserved.

Structural evolution and petroleum productivity of the Baltic basin

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ulmishek, G.F.

The Baltic basin is an oval depression located in the western part of the Russian craton; it occupies the eastern Baltic Sea and adjacent onshore areas. The basin contains more than 5,000 m of sedimentary rocks ranging from latest Proterozoic to Tertiary in age. These rocks consist of four tectonostratigraphic sequences deposited during major tectonic episodes of basin evolution. Principal unconformities separate the sequences. The basin is underlain by a rift probably filled with Upper Proterozoic rocks. Vendian and Lower Cambrian rocks (Baikalian sequence) form two northeast-trending depressions. The principal stage of the basin development was during deposition of amore » thick Middle Cambrian-Lower Devonian (Caledonian) sequence. This stage was terminated by the most intense deformations in the basin history. The Middle Devonian-Carboniferous (Hercynian) and Permian-Tertiary (Kimmerian-Alpine) tectonic and depositional cycles only slightly modified the basin geometry and left intact the main structural framework of underlying rocks. The petroleum productivity of the basin is related to the Caledonian tectonostratigraphic sequence that contains both source rocks and reservoirs. However, maturation of source rocks, migration of oil, and formation of fields took place mostly during deposition of the Hercynian sequence.« less

Use of relational databases to evaluate regional petroleum accumulation, groundwater flow, and CO2 sequestration in Kansas

USGS Publications Warehouse

Carr, T.R.; Merriam, D.F.; Bartley, J.D.

2005-01-01

Large-scale relational databases and geographic information system tools are used to integrate temperature, pressure, and water geo-chemistry data from numerous wells to better understand regional-scale geothermal and hydrogeological regimes of the lower Paleozoic aquifer systems in the mid-continent and to evaluate their potential for geologic CO2 sequestration. The lower Paleozoic (Cambrian to Mississippian) aquifer systems in Kansas, Missouri, and Oklahoma comprise one of the largest regional-scale saline aquifer systems in North America. Understanding hydrologic conditions and processes of these regional-scale aquifer systems provides insight to the evolution of the various sedimentary basins, migration of hydrocarbons out of the Anadarko and Arkoma basins, and the distribution of Arbuckle petroleum reservoirs across Kansas and provides a basis to evaluate CO2 sequestration potential. The Cambrian and Ordovician stratigraphic units form a saline aquifer that is in hydrologic continuity with the freshwater recharge from the Ozark plateau and along the Nemaha anticline. The hydrologic continuity with areas of freshwater recharge provides an explanation for the apparent underpressure in the Arbuckle Group. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

The geology of the northern tip of the Arabian-Nubian Shield

NASA Astrophysics Data System (ADS)

Beyth, M.; Eyal, Y.; Garfunkel, Z.

2014-11-01

Recently, a detailed (1:50,000) geological map of the Elat area, southern Israel was published. Attached to this map is a stratigraphic table of the Neoproterozoic metamorphic-magmatic complex of the study area. The Neoproterozoic basement in the Elat area encapsulates the Arabian Nubian Shield (ANS) geologic evolution. Uranium-Lead and Lead-Lead zircon ages, included in previous studies and referred to in this paper, reveal that these rocks were formed during more than 300 million years of Neoproterozoic time. The major process controlling the formation of the ANS as part of the East African Orogen is the closure of the Mozambique Ocean. The first orogenic phase in the Elat area, represented by the metamorphic rocks, includes the development of an island arc, erosion of the islands and deposition, and metamorphism. This event took place between ∼950 Ma and 780-790 Ma. Elat Schist, the oldest metamorphic rock in the area, was deformed and then intruded by quartz dioritic and granitic plutons that were later deformed and metamorphosed. The amphibolite metamorphic rock facies indicate metamorphic conditions of up to 650 °C and between 4 and 5 kbar. The peak of the metamorphic event was most probably before 750 Ma. A gradual change from compressional to extensional stress regime is evidenced by emplacement andesitic magnesium-rich dykes dated to 705 Ma that were later metamorphosed to schistose dykes at a greenschist metamorphic facies. The second orogenic phase (terrane amalgamation, main shaping of crust) was associated with the emplacement of large volumes (>50% of area) of calc-alkaline intrusions in a post-collision setting. These very last stages of metamorphism and deformation are characterized by intrusion of ∼630 Ma granitoids exhibiting some foliation. Pluton emplacement continued also after the end of deformation. Exhumation and transition to an extensional regime is recorded by the intrusion of shallow alkaline granites in ∼608 Ma which were accompanied in ∼609 Ma by rhyolite, andesite and composite dykes. The last magmatic event in the Elat area is represented by the volcano-conglomeratic series comprising rhyolites, basalts, andesites, hypabyssal intrusions of monzonite and syenite and conglomerates. The conglomerates, dated to about 590 Ma, are the products of a major erosion phase in which about 12,000 m of the section were removed. These conglomerates were intruded by 585 Ma rhyolite, andesite and composite dykes. The Neoproterozoic basement is truncated by a peneplain whose age, post 532 Ma, is constrained by the age of the youngest eroded dolerite dykes. This Early Cambrian peneplain was associated with erosion of 2000 m of the section and by chemical weathering. Three major breaks in Neoproterozoic magmatic activity are recognized: the first, occurred in Cryogenian time, lasted ∼60 million years after the amphibolite facies metamorphism and before emplacement of the calc alkaline plutons, separating the first and the second orogenic phases; the second break between the orogenic and the extensional phases occurred in early Ediacaran time, encompassed ∼20 million years between the emplacement of the calc-alkaline and alkaline plutonic rocks and rhyolite, andesite and the composite dykes; and the third, ∼50 Ma break, occurred between the emplacement of the last felsic intrusions at ∼585 Ma and intrusion of the dolerite dykes in 532 Ma, before the Early Cambrian peneplain developed. The great lateral extension of the Cambrian to Eocene sedimentary rocks and their slow facies and thickness changes suggest a stable flat platform area at the northern tip of the ANS. Early Cambrian sedimentation began with fluviatile subarkoses of the Amudei Shlomo Formation. It was overlain by an Early to Middle Cambrian transgressive-regressive lagoonal cycle of dolostones, sandstones, and siltstones of the Timna Formation. Then Middle Cambrian subarkoses and siltstones of the Shehoret Formation and the quartz arenite of the Netafim Formation were deposited in a coastal, intertidal environment representing the southern transgression of a Cambrian ocean.

Mineralogy and diagenesis of low-permeability sandstones of Late Cretaceous age, Piceance Creek Basin, northwestern Colorado

USGS Publications Warehouse

Hansley, Paula L.; Johnson, Ronald C.

1980-01-01

This report presents preliminary results of a mineralogic and diagenetic study of some low-permeability sandstones from measured surface sections and cores obtained from drill holes in the Piceance Creek Basin of northwestern Colorado. A documentation of the mineralogy and diagenetic history will aid in the exploration for natural gas and in the development of recovery technology in these low-permability sandstones. These sandstones are in the nonmarine upper part of the Mesaverde Formation (or Group) of Late Cretaceous age and are separated from overlying lower Tertiary rocks by a major regional unconformity. Attention is focused on the sandstone units of the Ohio Creek Member, which directly underlies the unconformity; however, comparisons between the mineralogy of the Ohio Creek strata and that of the underlying sandstone units are made whenever possible. The Ohio Creek is a member of the Hunter Canyon Formation (Mesaverde Group) in the southwestern part of the basin, and the Mesaverde Formation in the southern and central parts of the basin. The detrital mineralogy is fairly constant throughout all of these nonrnarine Cretaceous sandstone units; however, in the southeastern part of the basin, there is an increase in percentage of feldspar, quartzite, and igneous rock fragments in sandstones of the Ohio Creek Member directly underlying the unconformity. In the southwestern part of the basin, sandstones of the Ohio Creek Member are very weathered and are almost-entirely comprised of quartz, chert, and kaolinite. A complex diagenetic history, partly related to the overlying unconformity, appears to be responsible for transforming these sandstones into potential gas reservoirs. The general diagenetic sequence for the entire Upper Cretaceous interval studied is interpreted to be (early to late): early(?) calcite cement, chlorite, quartz overgrowths, calcite cement, secondary porosity, analcime (surface only), kaolinite and illite, and late carbonate cements. Authigenic high-iron chlorite, which occurs on grain rims and in pore throats, is primarily responsible for the low-permeability of the subsurface sandstones of the Ohio Creek Member in the center of the basin. Kaolinite is the most abundant pore-filling authigenic clay in these sandstones, from the southwestern part of the basin and is responsible for their distinctive white-weathering color in outcrop. In the sandstones below the Ohio Creek Member, however, chlorite and kaolinite occur locally, and authigenic calcite and illite are more abundant. The occurrence and distribution of secondary porosity is one of the most important aspects of the diagenetic history of these sandstones. It is present as moldic intra- and intergranular porosity, as well as microporosity among authigenic clay pariicles. Although present locally in most sandstone units, secondary porosity is particularly common in the uppermost sandstone units and is interpreted to have formed primarily asa result ofweathering during the time represented by the Cretaceous-Tertiary unconformity.

Long-Term Effect of Fault-Controlled CO2 Alteration on the Weakening and Strengthening of Reservoir and Seal Lithologies at Crystal Geyser, Green River, Utah

NASA Astrophysics Data System (ADS)

Major, J. R.; Eichhubl, P.; Dewers, T. A.

2014-12-01

An understanding of the coupled chemical and mechanical properties and behavior of reservoir and seal rocks is critical for assessing both the short and long term security of sequestered CO2. A combined structural diagenesis approach using observations from natural analogs has great advantages for understanding these properties over longer time scales than is possible using laboratory or numerical experiments. Current numerical models evaluating failure of reservoirs and seals during and after CO2 injection in the subsurface are just beginning to account for such coupled processes. Well-characterized field studies of natural analogs such as Crystal Geyser, Utah, are essential for providing realistic input parameters, calibration, and testing of numerical models across a range of spatial and temporal scales. Fracture mechanics testing was performed on a suite of naturally altered and unaltered reservoir and seal rocks exposed at the Crystal Geyser field site. These samples represent end-products of CO2-related alteration over geologic (>103 yr) time scales. Both the double torsion and short rod test methods yield comparable results on the same samples. Tests demonstrate that CO2-related alteration has weakened one reservoir sandstone lithology by approximately 50%, but the subcritical index is not significantly affected. An altered siltstone sample also shows a reduction in fracture toughness values and lowered subcritical index in comparison to unaltered siltstone. In contrast, elevated calcite content in shales due to CO2 alteration has increased fracture toughness. Similarly, fracture toughness was increased in what is otherwise a weak, poorly cemented sandstone unit due to increased calcite cement. Combined, these results demonstrate that CO2-related alteration generally weakens rock to fracturing (i.e. lowers fracture toughness), except in cases where calcite cementation is significantly increased. The natural system at Crystal Geyser demonstrates that water-CO2-rock interaction driven by changes in the geochemical environment have measurably altered rock geomechanical properties and that some rock units may become more prone to failure, ultimately leading to fracturing and leakage of subsurface reservoirs. These results also have application for CO2-based enhanced oil recovery.

Sensitivity of CO2 storage performance to varying rates and dynamic injectivity in the Bunter Sandstone, UK

NASA Astrophysics Data System (ADS)

Kolster, C.; Mac Dowell, N.; Krevor, S. C.; Agada, S.

2016-12-01

Carbon capture and storage (CCS) is needed for meeting legally binding greenhouse gas emissions targets in the UK (ECCC 2016). Energy systems models have been key to identifying the importance of CCS but they tend to impose few constraints on the availability and use of geologic CO2 storage reservoirs. Our aim is to develop simple models that use dynamic representations of limits on CO2 storage resources. This will allow for a first order representation of the storage reservoir for use in systems models with CCS. We use the ECLIPSE reservoir simulator and a model of the Southern North Sea Bunter Sandstone saline aquifer. We analyse reservoir performance sensitivities to scenarios of varying CO2 injection demand for a future UK low carbon energy market. With 12 injection sites, we compare the impact of injecting at a constant 2MtCO2/year per site and varying this rate by a factor of 1.8 and 0.2 cyclically every 5 and 2.5 years over 50 years of injection. The results show a maximum difference in average reservoir pressure of 3% amongst each case and a similar variation in plume migration extent. This suggests that simplified models can maintain accuracy by using average rates of injection over similar time periods. Meanwhile, by initiating injection at rates limited by pressurization at the wellhead we find that injectivity steadily increases. As a result, dynamic capacity increases. We find that instead of injecting into sites on a need basis, we can strategically inject the CO2 into 6 of the deepest sites increasing injectivity for the first 15 years by 13%. Our results show injectivity as highly dependent on reservoir heterogeneity near the injection site. Injecting 1MTCO2/year into a shallow, low permeability and porosity site instead of into a deep injection site with high permeability and porosity reduces injectivity in the first 5 years by 52%. ECCC. 2016. Future of Carbon Capture and Storage in the UK. UK Parliament House of Commons, Energy and Climate Change Committee, London: The Stationary Office Limited.

Effect of lithological heterogeneity of bitumen sandstones on SAGD reservoir development

NASA Astrophysics Data System (ADS)

Korolev, E. A.; Usmanov, S. A.; Nikolaev, D. S.; Gabdelvaliyeva, R. R.

2018-05-01

The article describes the heavy oil field developed by the SAGD method. While development planning all the heterogeneity of the reservoir is must be taken into account. The objective of this work is to identify the distribution of lithological heterogeneities and their influence on oil production. For this reason, the studies of core samples were conducted and the heterogeneity was identified. Then properties and approximate geometry of lithological objects were studied. Also the effect of the heterogeneity on the heat propagation and production of fluid were analyzed. In the end, recommendations were made for the study of such heterogeneities on other deposits with similar geology

Formation factor in Bentheimer and Fontainebleau sandstones: Theory compared with pore-scale numerical simulations

NASA Astrophysics Data System (ADS)

Ghanbarian, Behzad; Berg, Carl F.

2017-09-01

Accurate quantification of formation resistivity factor F (also called formation factor) provides useful insight into connectivity and pore space topology in fully saturated porous media. In particular the formation factor has been extensively used to estimate permeability in reservoir rocks. One of the widely applied models to estimate F is Archie's law (F = ϕ- m in which ϕ is total porosity and m is cementation exponent) that is known to be valid in rocks with negligible clay content, such as clean sandstones. In this study we compare formation factors determined by percolation and effective-medium theories as well as Archie's law with numerical simulations of electrical resistivity on digital rock models. These digital models represent Bentheimer and Fontainebleau sandstones and are derived either by reconstruction or directly from micro-tomographic images. Results show that the universal quadratic power law from percolation theory accurately estimates the calculated formation factor values in network models over the entire range of porosity. However, it crosses over to the linear scaling from the effective-medium approximation at the porosity of 0.75 in grid models. We also show that the effect of critical porosity, disregarded in Archie's law, is nontrivial, and the Archie model inaccurately estimates the formation factor in low-porosity homogeneous sandstones.

Post-depositional alteration of titanomagnetite in a Miocene sandstone, south Texas (U.S.A.)

USGS Publications Warehouse

Reynolds, R.L.

1982-01-01

Petrographic and geochemical studies have yielded information on the time-space relationships of the post-depositional alteration of detrital titanomagnetite (Ti-mt) in fine- to medium-grained sandstone from unoriented core samples (taken below the water table at depths of 30-45 m) of the Miocene Catahoula Sandstone, south Texas. Aqueous sulfide introduced from sour gas reservoirs along a growth fault into part of the Catahoula shortly after deposition resulted in the replacement at the periphery of Ti-mt grains by iron disulfide (FeS2) minerals. Remnants of Ti-mt in cores of the partly sulfidized grains show no evidence of earlier hematitic oxidation. After sulfidization, part of the sandstone body was invaded by oxygenated groundwaters flowing down a shallowly inclined (1??) hydrologic gradient. The boundary between oxidized and reduced facies is clearly defined by the distribution of ferric and ferrous iron minerals, and the concentrations of Mo, U, and Se. In oxidized (light-red) strata that had not been previously subjected to sulfidic-reducing conditions but that are correlative with strata containing FeS2 minerals, Ti-mt has been partly to entirely replaced pseudomorphously by hematite to form martite. The absence of hematitic alteration of Ti-mt in the reduced facies is strong evidence that martite in the oxidized facies formed after deposition. ?? 1982.

Lattice Boltzmann Simulation of Seismic Mobilization of Residual Oil in Sandstone

NASA Astrophysics Data System (ADS)

Guo, R.; Jiang, F.; Deng, W.

2017-12-01

Seismic stimulation is a promising technology for enhanced oil recovery. However, current mechanism studies are mainly in the single constricted tubes or idealized porous media, and no study has been conducted in real reservoir porous media. We have developed a numerical simulation which uses the lattice Boltzmann method to directly calculate the characteristics of residual oil clusters to quantify seismic mobilization of residual oil in real Berea sandstone in a scale of 400μm x 400μm x 400μm. The residual oil clusters will be firstly obtained by applying the water flooding scheme to the oil-saturated sandstone. Then, we will apply the seismic stimulation to the sandstone by converting the seismic effect to oscillatory inertial force and add to the pore fluids. This oscillatory inertial force causes the mobilization of residual oil by overcoming the capillary force. The response of water and oil to the seismic stimulation will be observed in our simulations. Two seismic oil mobilization mechanisms will be investigated: (1) the passive response of residual oil clusters to the seismic stimulation, and (2) the resonance of oil clusters subject to low frequency seismic stimulation. We will then discuss which mechanism should be the dominant mechanism for the seismic stimulation oil recovery for practical applications.

Stratigraphy and depositional environment of upper Cambrian Red Lion Formation, southwestern Montana

DOE Office of Scientific and Technical Information (OSTI.GOV)

Hayden, L.L.; Bush, J.H.

1987-08-01

The Red Lion Formation was examined along a northwest-southeast transect from Missoula to Bozeman, Montana. Lateral equivalents are the Snowy Range Formation east of Bozeman and the upper Fishtrap Dolomite in northwest Montana. The basal Dry Creek Member (0-5 m) consists of shale interbedded with quartz siltstones and sandstones. The overlying Sage Member, up to 115 meters in thickness, is characterized by ribbon carbonate beds containing lime mudstone and quartzose calcisiltite couplets arranged in fining-upward sequences 1-5 cm thick. Couplets are interlayered in places with thin (1-5 cm) to medium bedded (6-70 cm) units of laminated and non-laminated calcareous siltstones,more » flat-pebble conglomerates, trilobite packstones, cryptalgal boundstones, bioturbated lime mudstones and shales. In places, the upper Sage contains columnar and domal algal features. The Red Lion Formation is considered to be one Grand Cycle with the Dry Creek representing a lower inner detrital half-cycle and the Sage an upper carbonate half-cycle. The Dry Creek formed as the result of a westward clastic pulse from the inner detrital belt across an intrashelf basin onto outer middle carbonate peritidal complexes of the underlying Pilgrim Formation. Lower Sage ribbon rocks were deposited in storm-crossed, below wave-base areas. During deposition of the upper Sage, shallowing formed discontinuous algal-peritidal complexes over much of western and central Montana. These complexes were less extensive than earlier Cambrian buildups owing to slower rates of basin subsidence and clastic input suppressing carbonate production.« less

Controls on the deposition and preservation of the Cretaceous Mowry Shale and Frontier Formation and equivalents, Rocky Mountain region, Colorado, Utah, and Wyoming

USGS Publications Warehouse

Kirschbaum, Mark A.; Mercier, Tracey J.

2013-01-01

Regional variations in thickness and facies of clastic sediments are controlled by geographic location within a foreland basin. Preservation of facies is dependent on the original accommodation space available during deposition and ultimately by tectonic modification of the foreland in its postthrusting stages. The preservation of facies within the foreland basin and during the modification stage affects the kinds of hydrocarbon reservoirs that are present. This is the case for the Cretaceous Mowry Shale and Frontier Formation and equivalent strata in the Rocky Mountain region of Colorado, Utah, and Wyoming. Biostratigraphically constrained isopach maps of three intervals within these formations provide a control on eustatic variations in sea level, which allow depositional patterns across dip and along strike to be interpreted in terms of relationship to thrust progression and depositional topography. The most highly subsiding parts of the Rocky Mountain foreland basin, near the fold and thrust belt to the west, typically contain a low number of coarse-grained sandstone channels but limited sandstone reservoirs. However, where subsidence is greater than sediment supply, the foredeep contains stacked deltaic sandstones, coal, and preserved transgressive marine shales in mainly conformable successions. The main exploration play in this area is currently coalbed gas, but the enhanced coal thickness combined with a Mowry marine shale source rock indicates that a low-permeability, basin-centered play may exist somewhere along strike in a deep part of the basin. In the slower subsiding parts of the foreland basin, marginal marine and fluvial sandstones are amalgamated and compartmentalized by unconformities, providing conditions for the development of stratigraphic and combination traps, especially in areas of repeated reactivation. Areas of medium accommodation in the most distal parts of the foreland contain isolated marginal marine shoreface and deltaic sandstones that were deposited at or near sea level lowstand and were reworked landward by ravinement and longshore currents by storms creating stratigraphic or combination traps enclosed with marine shale seals. Paleogeographic reconstructions are used to show exploration fairways of the different play types present in the Laramide-modified, Cretaceous foreland basin. Existing oil and gas fields from these plays show a relatively consistent volume of hydrocarbons, which results from the partitioning of facies within the different parts of the foreland basin.

Experimental study of two-phase fluid flow in two different porosity types of sandstone by P-wave velocity and electrical Impedance measurement

NASA Astrophysics Data System (ADS)

Honda, H.; Mitani, Y.; Kitamura, K.; Ikemi, H.; Takaki, S.

2015-12-01

Carbon dioxide (CO2) capture and storage (CCS) is recently expected as the promising method to reduce greenhouse gas emissions. It is important to investigate CO2 behavior in the reservoir, to evaluate the safety and to account the stored CO2 volume. In this study, experimental investigation is conducted to discuss the relationships between injected fluid speed (Flow rate: FR) or capillary number (Ca) and non-wetting fluid flow by compressional wave velocity (Vp) and electrical impedance (Z). In the experiment, N2 and supercritical CO2 were injected into the two sandstones with different porosity (φ), Berea sandstone (φ: 18 %), and Ainoura sandstone (φ: 11.9 %). The dimension of the rock specimens is cored cylinder with a 35 mm diameter and 70 mm height. Experimental conditions are nearly same as the reservoir of deep underground (Confining pressure:15MPa, 40℃). Initial conditions of the specimen are brine (0.1wt%-KCl) saturated. Four piezo-electrical transducers (PZTs) are set on the each surface of the top, middle, lower of the specimen to monitor the CO2 bahavior by Vp. To measuring Z, we use for electrodes method with Ag-AgCl electrodes. Four electrodes are wounded around specimen on the both sides of PZTs. We measured the changes of these parameters with injecting N2, injected fluid speed (FR), the differential pore pressure (DP), N2 saturation (SN2), P-wave velocity (Vp) and electrical impedance (Z), respectively. We also estimated the Ca from measured FR. From these experimental results, there are no obvious Vp changes with increasing Ca, while Z measurement indicates clear and continuous increment. In regards to Vp, Vp reduced at the small FR (0.1 to 0.2 ml/min). As the Ca increases, Vp doesn't indicate large reduction. On the other hand, Z is more sensitive to change the fluid saturation than Vp. It is well-known that both of Vp and Z are the function of fluid saturation. Though, these experimental results are not consistent with previous studies. In this study, we will discuss this mismatch by using fluid mechanical theory and numerical simulation of two-phase fluid flow in porous geological medium based on experimental results of two different types of sandstone.

Assessment of managed aquifer recharge from Sand Hollow Reservoir, Washington County, Utah, updated to conditions in 2010

USGS Publications Warehouse

Heilweil, Victor M.; Marston, Thomas M.

2011-01-01

Sand Hollow Reservoir in Washington County, Utah, was completed in March 2002 and is operated primarily for managed aquifer recharge by the Washington County Water Conservancy District. From 2002 through 2009, total surface-water diversions of about 154,000 acre-feet to Sand Hollow Reservoir have allowed it to remain nearly full since 2006. Groundwater levels in monitoring wells near the reservoir rose through 2006 and have fluctuated more recently because of variations in reservoir water-level altitude and nearby pumping from production wells. Between 2004 and 2009, a total of about 13,000 acre-feet of groundwater has been withdrawn by these wells for municipal supply. In addition, a total of about 14,000 acre-feet of shallow seepage was captured by French drains adjacent to the North and West Dams and used for municipal supply, irrigation, or returned to the reservoir.From 2002 through 2009, about 86,000 acre-feet of water seeped beneath the reservoir to recharge the underlying Navajo Sandstone aquifer. Water-quality sampling was conducted at various monitoring wells in Sand Hollow to evaluate the timing and location of reservoir recharge moving through the aquifer. Tracers of reservoir recharge include major and minor dissolved inorganic ions, tritium, dissolved organic carbon, chlorofluorocarbons, sulfur hexafluoride, and noble gases. By 2010, this recharge arrived at monitoring wells within about 1,000 feet of the reservoir.

Assessment of managed aquifer recharge at Sand Hollow Reservoir, Washington County, Utah, updated to conditions through 2014

USGS Publications Warehouse

Marston, Thomas M.; Heilweil, Victor M.

2016-09-08

Sand Hollow Reservoir in Washington County, Utah, was completed in March 2002 and is operated primarily for managed aquifer recharge by the Washington County Water Conservancy District. From 2002 through 2014, diversions of about 216,000 acre-feet from the Virgin River to Sand Hollow Reservoir have allowed the reservoir to remain nearly full since 2006. Groundwater levels in monitoring wells near the reservoir rose through 2006 and have fluctuated more recently because of variations in reservoir stage and nearby pumping from production wells. Between 2004 and 2014, about 29,000 acre-feet of groundwater was withdrawn by these wells for municipal supply. In addition, about 31,000 acre-feet of shallow seepage was captured by French drains adjacent to the North and West Dams and used for municipal supply, irrigation, or returned to the reservoir. From 2002 through 2014, about 127,000 acre-feet of water seeped beneath the reservoir to recharge the underlying Navajo Sandstone aquifer.Water quality continued to be monitored at various wells in Sand Hollow during 2013–14 to evaluate the timing and location of reservoir recharge as it moved through the aquifer. Changing geochemical conditions at monitoring wells WD 4 and WD 12 indicate rising groundwater levels and mobilization of vadose-zone salts, which could be a precursor to the arrival of reservoir recharge.

Cross-bedding Related Anisotropy and its Role in the Orientation of Joints in an Aeolian Sandstone

NASA Astrophysics Data System (ADS)

Deng, S.; Cilona, A.; Mapeli, C.; Panfilau, A.; Aydin, A.; Prasad, M.

2014-12-01

Previous research revealed that the cross-bedding related anisotropy in aeolian sandstones affects the orientation of compaction bands, also known as anticracks. We hypothesize that cross-bedding should a have similar influence on the orientation of the joints within the same rock at the same location. To test this hypothesis, we investigated the relationship between the cross-beds and the cross-bed package confined joints in the Jurassic aeolian Aztec Sandstone cropping out in the Valley of Fire State Park, Nevada. The field data demonstrates that the cross-bed package confined joints occur at high-angle to bedding and trend roughly parallel to the dip direction of the cross-beds. This shows that the cross-bed orientation and the associated anisotropy also exert a strong control on the formation and orientation of the joints. In order to characterize the anisotropy due to cross-bedding in the Aztec Sandstone, we measured the P-wave velocities parallel and perpendicular to bedding from 11 samples in the laboratory using a bench-top ultrasonic assembly. The measured P-wave anisotropy is about 13% on average. Based on these results, a numerical model based on the generalized Hooke's law for anisotropic materials is analyzed assuming the cross-bedded sandstone to be transversely isotropic. Using this model, we tested various cross-bed orientations as well as different strain boundary conditions (uniaxial, axisymmetric and triaxial). It is possible to define a boundary condition under which the modeled results roughly match with the observed relationship between cross-bed package confined joints and cross-beds. These results have important implications for fluid flow through aeolian sandstones in reservoirs and aquifers.

Total petroleum systems of the Bonaparte Gulf Basin area, Australia; Jurassic, Early Cretaceous-Mesozoic; Keyling, Hyland Bay-Permian; Milligans-Carboniferous, Permian

USGS Publications Warehouse

Bishop, M.G.

1999-01-01

The Bonaparte Gulf Basin Province (USGS #3910) of northern Australia contains three important hydrocarbon source-rock intervals. The oldest source-rock interval and associated reservoir rocks is the Milligans-Carboniferous, Permian petroleum system. This petroleum system is located at the southern end of Joseph Bonaparte Gulf and includes both onshore and offshore areas within a northwest to southeast trending Paleozoic rift that was initiated in the Devonian. The Milligans Formation is a Carboniferous marine shale that sources accumulations of both oil and gas in Carboniferous and Permian deltaic, marine shelf carbonate, and shallow to deep marine sandstones. The second petroleum system in the Paleozoic rift is the Keyling, Hyland Bay-Permian. Source rocks include Lower Permian Keyling Formation delta-plain coals and marginal marine shales combined with Upper Permian Hyland Bay Formation prodelta shales. These source-rock intervals provide gas and condensate for fluvial, deltaic, and shallow marine sandstone reservoirs primarily within several members of the Hyland Bay Formation. The Keyling, Hyland Bay-Permian petroleum system is located in the Joseph Bonaparte Gulf, north of the Milligans-Carboniferous, Permian petroleum system, and may extend northwest under the Vulcan graben sub-basin. The third and youngest petroleum system is the Jurassic, Early Cretaceous-Mesozoic system that is located seaward of Joseph Bonaparte Gulf on the Australian continental shelf, and trends southwest-northeast. Source-rock intervals in the Vulcan graben sub-basin include deltaic mudstones of the Middle Jurassic Plover Formation and organic-rich marine shales of the Upper Jurassic Vulcan Formation and Lower Cretaceous Echuca Shoals Formation. These intervals produce gas, oil, and condensate that accumulates in, shallow- to deep-marine sandstone reservoirs of the Challis and Vulcan Formations of Jurassic to Cretaceous age. Organic-rich, marginal marine claystones and coals of the Plover Formation (Lower to Upper Jurassic), combined with marine claystones of the Flamingo Group and Darwin Formation (Upper Jurassic to Lower Cretaceous) comprise the source rocks for the remaining area of the system. These claystones and coals source oil, gas, and condensate accumulations in reservoirs of continental to marine sandstones of the Plover Formation and Flamingo Group. Shales of the regionally distributed Lower Cretaceous Bathurst Island Group and intraformational shales act as seals for hydrocarbons trapped in anticlines and fault blocks, which are the major traps of the province. Production in the Bonaparte Gulf Basin Province began in 1986 using floating production facilities, and had been limited to three offshore fields located in the Vulcan graben sub-basin. Cumulative production from these fields totaled more than 124 million barrels of oil before the facilities were removed after production fell substantially in 1995. Production began in 1998 from three offshore wells in the Zone of Cooperation through floating production facilities. After forty years of exploration, a new infrastructure of pipelines and facilities are planned to tap already discovered offshore reserves and to support additional development.

Geology, sequence stratigraphy, and oil and gas assessment of the Lewis Shale Total Petroleum System, San Juan Basin, New Mexico and Colorado: Chapter 5 in Total petroleum systems and geologic assessment of undiscovered oil and gas resources in the San Juan Basin Province, exclusive of Paleozoic rocks, New Mexico and Colorado

USGS Publications Warehouse

Dubiel, R.F.

2013-01-01

The Lewis Shale Total Petroleum System (TPS) in the San Juan Basin Province contains a continuous gas accumulation in three distinct stratigraphic units deposited in genetically related depositional environments: offshore-marine shales, mudstones, siltstones, and sandstones of the Lewis Shale, and marginal-marine shoreface sandstones and siltstones of both the La Ventana Tongue and the Chacra Tongue of the Cliff House Sandstone. The Lewis Shale was not a completion target in the San Juan Basin (SJB) in early drilling from about the 1950s through 1990. During that time, only 16 wells were completed in the Lewis from natural fracture systems encountered while drilling for deeper reservoir objectives. In 1991, existing wells that penetrated the Lewis Shale were re-entered by petroleum industry operators in order to fracture-stimulate the Lewis and to add Lewis gas production onto preexisting, and presumably often declining, Mesaverde Group production stratigraphically lower in the section. By 1997, approximately 101 Lewis completions had been made, both as re-entries into existing wells and as add-ons to Mesaverde production in new wells. Based on recent industry drilling and completion practices leading to successful gas production from the Lewis and because new geologic models indicate that the Lewis Shale contains both source rocks and reservoir rocks, the Lewis Shale TPS was defined and evaluated as part of this U.S. Geological Survey oil and gas assessment of the San Juan Basin. Gas in the Lewis Shale Total Petroleum System is produced from shoreface sandstones and siltstones in the La Ventana and Chacra Tongues and from distal facies of these prograding clastic units that extend into marine rocks of the Lewis Shale in the central part of the San Juan Basin. Reservoirs are in shoreface sandstone parasequences of the La Ventana and Chacra and their correlative distal parasequences in the Lewis Shale where both natural and artificially enhanced fractures produce gas. The Lewis Continuous Gas Assessment Unit (AU 50220261) is thought to be self-sourced from and self-sealed by marine shales and mudstones deposited within the Lewis Shale that enclose clastic parasequences in the La Ventana and Chacra Tongues. The gas resource is thought to be a continuous accumulation sourced from the Lewis Shale throughout the depositional basin. In the Lewis Continuous Gas Assessment Unit (AU 50220261), for continuous gas resources, there is an F95 of 8,315.22 billion cubic feet of gas (BCFG) and an F5 of 12,282.31 BCFG, with a mean value of 10,177.24 BCFG. There is an F95 of 18.08 million barrels of natural gas liquids (MMBNGL) and an F5 of 47.32 MMBNGL, with a mean of 30.53 MMBNGL.

Development of a Geologic Exploration Model foe the Permo-Pennsylvanian Petroleum System in South-Central Montana

DOE Office of Scientific and Technical Information (OSTI.GOV)

David A. Lopez

2007-06-30

Eolian sands are the main Pennsylvanian Tensleep Sandstone reservoir rocks, and were deposited in a near-shore environment interbedded with near-shore marine and sabkha calcareous and dolomitic rocks. Within the Tensleep, numerous cycles are characterized by basal marine or sabkha calcareous sandstone or dolomitic sandstone overlain by porous and permeable eolian sandstone, which in turn is capped by marine sandstone. The cycles represent the interplay of near-shore marine, sabkha, and eolian environments. On the west side of the project area, both the lower and upper Tensleep are present and the total thickness reaches a maximum of about 240 ft. The lowermore » Tensleep is 100 to 120 ft thick and consists of a sequence of repeating cycles of limey shallow marine sandstone, sandy limestone, and sandy dolomite. The upper Tensleep is generally characterized by cycles of sandy limestone or dolomite, overlain by light-colored, eolian dune sandstone capped by marine limey sandstone. In the central and eastern parts of the project area, only the lower Tensleep is present, but here eolian sandstones are in cycles much like those in the west in the upper Tensleep. The lower Tensleep is quite variable in thickness, ranging from about 25 ft to over 200 ft. Oil accumulations in the Tensleep are best described as structurally modified paleostratigraphic accumulations. At Frannie Field, the irregular oil column can be explained by a post-Tensleep channel scour on the west flank of the anticline. On the Powder River Basin side of the project area, the Soap Creek and Lodge Grass Fields produce from the Permo-Pennsylvanian system. In these two fields, erosional remnants of eolian sandstone control the production, similar to the situation at Frannie Field. At Soap Creek the trap is enhanced by structural closure. In the Lodge Grass area, Tensleep oil is trapped in preserved dunes in the footwall of a Laramide reverse fault. Oil generation and migration was early. Two hypotheses have been presented: migration occurred (1) before mid-Jurassic erosion produced a major regional unconformity or (2) about 82 million years ago. Migration pre-Laramide occurred because oil in both the Bighorn Basin and the Powder River Basin are part of the same petroleum system. Geochemical analyses of oils from producing fields across the region show the oils are all similar and have the same source and generation history. No Phosphoria source rocks exist in the project area of south-central Montana, requiring that oil migrated from distant source areas, probably in central and southwestern Wyoming. Oil shows and production in the Tensleep are absent in the northern part of the project area. This appears to be controlled by the merging of the top of the Tensleep Sandstone and the Jurassic unconformity (top of the Triassic Chugwater Formation). There should be potential for the discovery of oil in Tensleep stratigraphic traps or combination traps everywhere south of the Jurassic-Pennsylvanian Isopach zero contour except where the Tensleep has been exposed by uplift and erosion. Known Tensleep fields in south-central Montana are generally small in area, which agrees with outcrop studies that show eolian dune sequences are generally quite small in lateral extent, on the order of 10 to 40 acres. Although existing fields are small in area, they are very productive; individual wells will probably make 300,000 to 500,000 barrels of oil. In the project area, hydrodynamic considerations are important. All the existing Tensleep fields have active water drives. In many cases, the reservoir pressure today is as it was when initially discovered. In areas of high structural complexity, such as the Lodge Grass-Crow Agency fault and the Lake Basin fault zone, significant structural closure may be necessary to trap oil because of the strong hydrodynamic influence exerted by the underlying Madison Formation aquifer.« less

Unraveling the redox evolution of the Yangtze Block across the Precambrian/Cambrian transition

NASA Astrophysics Data System (ADS)

Diamond, C. W.; Zhang, F.; Chen, Y.; Lyons, T. W.

2016-12-01

Rocks preserved on the South China Craton have played a critical role in refining our understanding of the co-evolution of life and Earth's surface environments in the Late Neoproterozoic and earliest Paleozoic. From the earliest metazoan embryos to the many examples of exceptional preservation throughout the Cambrian Explosion, South China has preserved an outstanding record of animal evolution across this critical transition. Similarly, rocks preserved in South China hold key insights into the changing ocean chemistry that accompanied this extraordinary time. Recent work form Sahoo and others (2016, Geobiology) used redox sensitive metal enrichments in the Ediacaran Doushantuo Formation to demonstrate that the redox state of the Latest Neoproterozoic oceans was highly dynamic, rather than stably oxygenated or anoxic as had both been suggested previously. In an attempt to follow on from this and other studies, we have examined samples from a drill core taken in eastern Guizhou capturing deep-water facies of the Liuchapo and Jiumenchong formations, which contain the Precambrian/Cambrian boundary. In addition to containing the boundary, the sampled interval contains an enigmatic, widespread horizon that is strongly enriched in Ni and Mo. We have taken a multi-proxy approach in our investigation of this layer, the possible implications it has for the strata above and below (i.e., how its presence affects their utility as archives of paleo-redox conditions), and what those strata can tell us about local and global redox conditions during this pivotal time in Earth's history. Our Fe speciation data indicate that conditions were sulfidic at this location throughout the majority of the sampled interval. While redox sensitive metal concentrations are dramatically enriched in the Ni/Mo interval, their concentrations return to modest enrichments above it and continue to decrease upward. This trend suggests that while the conditions that favored extreme enrichment during the deposition of the Ni/Mo layer may have continued to provide a source of metals above the layer itself, by the time this source was exhausted, the background reservoir of these metals was low, sufficient only to provide small enrichments - consistent with the notion that deep ocean anoxia was a regular, if not dominant, feature of the Cambrian world.

Effective Wettability Measurements of CO2-Brine-Sandstone System at Different Reservoir Conditions

NASA Astrophysics Data System (ADS)

Al-Menhali, Ali; Krevor, Samuel

2014-05-01

The wetting properties of CO2-brine-rock systems will have a major impact on the management of CO2 injection processes. The wettability of a system controls the flow and trapping efficiency during the storage of CO2 in geological formations as well as the efficiency of enhanced oil recovery operations. Despite its utility in EOR and the continued development of CCS, little is currently known about the wetting properties of the CO2-brine system on reservoir rocks, and no investigations have been performed assessing the impact of these properties on CO2 flooding for CO2 storage or EOR. The wetting properties of multiphase fluid systems in porous media have major impacts on the multiphase flow properties such as the capillary pressure and relative permeability. While recent studies have shown CO2 to generally act as a non-wetting phase in siliciclastic rocks, some observations report that the contact angle varies with pressure, temperature and water salinity. Additionally, there is a wide range of reported contact angles for this system, from strongly to weakly water-wet. In the case of some minerals, intermediate wet contact angles have been observed. Uncertainty with regard to the wetting properties of CO2-brine systems is currently one of the remaining major unresolved issues with regards to reservoir management of CO2 storage. In this study, we make semi-dynamic capillary pressure measurements of supercritical CO2 and brine at reservoir conditions to observe shifts in the wetting properties. We utilize a novel core analysis technique recently developed by Pini et al in 2012 to evaluate a core-scale effective contact angle. Carbon dioxide is injected at constant flow rate into a core that is initially fully saturated with water, while maintaining a constant outlet pressure. In this scenario, the pressure drop across the core corresponds to the capillary pressure at the inlet face of the core. When compared with mercury intrusion capillary pressure measurements, core-scale effective contact angle can be determined. In addition to providing a quantitative measure of the core-averaged wetting properties, the technique allows for the observation of shifts in contact angle with changing conditions. We examine the wettability changes of the CO2-brine system in Berea sandstone with variations in reservoir conditions including supercritical, gaseous and liquid CO2injection. We evaluate wettability variation within a single rock with temperature, pressure, and salinity across a range of conditions relevant to subsurface CO2 storage. This study will include results of measurements in a Berea sandstone sample across a wide range of conditions representative of subsurface reservoirs suitable for CO2 storage (5-20 MPa, 25-90 oC, 0-5 mol kg-1). The measurement uses X-ray CT imaging in a state of the art core flooding laboratory designed to operate at high temperature, pressure, and concentrated brines.

Technique policy for concurrent development of natural and artificial water flooding of strong edge water reservoir: A case study of central layer Yu-III of Akshabulak oilfield

NASA Astrophysics Data System (ADS)

Angang, Zhang; Zifei, Fan; Lun, Zhao; Jincai, Wang; Xiangzhong, Zhang; Heng, Song; Qingying, Hou

2018-06-01

The central layer Yu-III in Akshabulak oilfield is a sandstone reservoir with strong edge water, whose major development characteristics are high oil recovery rate and heterogeneous water invasion. Aiming at this problem, the development policy chart of concurrent displacement of natural water and injected water is established on the basis of material balance principle. Injection-production ratio and oil recovery rate are the main controlling factors for the concurrent displacement of natural water and injected water. Each injection-production ratio corresponds with only one rational oil recovery rate, and the rational oil recovery rate increases with the injection-production ratio. When the actual injection-production ratio of the central Yu-III reservoir is 0.9, the rational oil recovery rate should be 4%.

Experimental measurements of the SP response to concentration and temperature gradients in sandstones with application to subsurface geophysical monitoring

NASA Astrophysics Data System (ADS)

Leinov, E.; Jackson, M. D.

2014-09-01

Exclusion-diffusion potentials arising from temperature gradients are widely neglected in self-potential (SP) surveys, despite the ubiquitous presence of temperature gradients in subsurface settings such as volcanoes and hot springs, geothermal fields, and oil reservoirs during production via water or steam injection. Likewise, with the exception of borehole SP logging, exclusion-diffusion potentials arising from concentration gradients are also neglected or, at best, it is assumed that the diffusion potential dominates. To better interpret these SP sources requires well-constrained measurements of the various coupling terms. We report measurements of thermoelectric and electrochemical exclusion-diffusion potentials across sandstones saturated with NaCl brine and find that electrode effects can dominate the measured voltage. After correcting for these, we find that Hittorf transport numbers are the same within experimental error regardless of whether ion transport occurs in response to temperature or concentration gradients over the range of NaCl concentration investigated that is typical of natural systems. Diffusion potentials dominate only if the pore throat radius is more than approximately 4000 times larger than the diffuse layer thickness. In fine-grained sandstones with small pore throat diameter, this condition is likely to be met only if the saturating brine is of relatively high salinity; thus, in many cases of interest to earth scientists, exclusion-diffusion potentials will comprise significant contributions from both ionic diffusion through, and ionic exclusion from, the pore space of the rock. However, in coarse-grained sandstones, or sandstones saturated with high-salinity brine, exclusion-diffusion potentials can be described using end-member models in which ionic exclusion is neglected. Exclusion-diffusion potentials in sandstones depend upon pore size and salinity in a complex way: they may be positive, negative, or zero depending upon sandstone rock texture (expressed here by the pore radius r) and salinity.

Sulfur Isotope Analysis of Minerals and Fluids in a Natural CO2 Reservoir, Green River, Utah

NASA Astrophysics Data System (ADS)

Chen, F.; Kampman, N.; Bickle, M. J.; Busch, A.; Turchyn, A. V.

2013-12-01

Predicting the security of geological CO2 storage sites requires an understanding of the geochemical behavior of the stored CO2, especially of fluid-rock reactions in reservoirs, caprocks and fault zones. Factors that may influence geochemical behavior include co-injection of sulfur gases along with the CO2, either in acid-gas disposal or as contaminants in CO2 storage sites, and microbial activity, such as bacterial sulfate reduction. The latter may play an important role in buffering the redox chemistry of subsurface fluids, which could affect toxic trace metal mobilization and transport in acidic CO2-rich fluids. These processes involving sulfur are poorly understood. Natural CO2-reservoirs provide natural laboratories, where the flow and reactions of the CO2-charged fluids and the activity of microbial communities are integrated over sufficient time-scales to aid prediction of long-term CO2 storage. This study reports on sulfur isotope analyses of sulfate and sulfide minerals in rock core and in CO2-charged fluids collected from a stacked sequence of natural CO2 reservoirs at Green River, Utah. Scientific drilling adjacent to a CO2-degassing normal fault to a depth of 325m retrieved core and fluid samples from two CO2 reservoirs in the Entrada and Navajo Sandstones and from the intervening Carmel Formation caprock. Fluid samples were collected from CO2-charged springs that discharge through the faults. Sulfur exists as sulfate in the fluids, as sedimentary gypsum beds in the Carmel Formation, as remobilized gypsum veins within a fault damage zone in the Carmel Fm. and in the Entrada Sandstone, and as disseminated pyrite and pyrite-mineralized open fractures throughout the cored interval. We use the stable sulfur (δ34S) and oxygen (δ18OSO4) isotopes of the sulfate, gypsum, and pyrite to understand the source of sulfur in the reservoir as well as the timing of gypsum vein and pyrite formation. The hydration water of the gypsum is also reported to explore the different timing of gypsum vein formation. Macroscopic and microscopic gradients in the sulfur isotope composition of pyrite throughout the core and at discernible redox-reaction fronts were examined in detail to assess the role of bacteria in mediating sulfate reduction, sulfide mineralization and buffering of groundwater redox chemistry. The CO2 charged fluids and gypsum veins within the Entrada Sandstone have a narrow and very similar range in both δ34SSO4 and δ18OSO4, suggesting that the fluids (9.1-10.7‰) are the most likely source of the sulfate in the veins (11.4-12.8‰) and that the veins formed during recent fluid flow through the Entrada, with sulfate coming from remobilized gypsum beds in the Carmel. The Carmel also contains two isotopically distinct types of gypsum veins: one with δ34SSO4 values similar to the Entrada veins and one with much higher δ34SSO4 values (15.1-16.1‰). The latter are likely primary gypsum, while the former are likely secondary gypsum. Sulfur isotope fractionation between pyrite (-16.5‰ to -35.7‰) at the Carmel-Navajo interface and reservoir fluids (9.1-10.7‰) suggest that sulfur reducing bacteria play a role in producing the deposited sulfide. This data demonstrates active sulfur cycling in CO2 reservoirs with many different sulfur species cycled among various pools creating the wide isotope dispersion we observe.

The Research and Application of Microbial Degradation Technology on Heavy Oil Reservoir in Huabei Oilfield

NASA Astrophysics Data System (ADS)

Wang, Guan; Wang, Rui; Fu, Yaxiu; Duan, Lisha; Yuan, Xizhi; Zheng, Ya; Wang, Ai; Huo, Ran; Su, Na

2018-06-01

Mengulin sandstone reservoir in Huabei oilfield is low- temperature heavy oil reservoir. Recently, it is at later stage of waterflooding development. The producing degree of water flooding is poor, and it is difficult to keep yield stable. To improve oilfield development effect, according to the characteristics of reservoir geology, microbial enhanced oil recovery to improve oil displacement efficiency is researched. 2 microbial strains suitable for the reservoir conditions were screened indoor. The growth characteristics of strains, compatibility and function mechanism with crude oil were studied. Results show that the screened strains have very strong ability to utilize petroleum hydrocarbon to grow and metabolize, can achieve the purpose of reducing oil viscosity, and can also produce biological molecules with high surface activity to reduce the oil-water interfacial tension. 9 oil wells had been chosen to carry on the pilot test of microbial stimulation, of which 7 wells became effective with better experiment results. The measures effective rate is 77.8%, the increased oil is 1,093.5 tons and the valid is up to 190 days.

The regional geology and hydrocarbon potential of the Baltic Sea

DOE Office of Scientific and Technical Information (OSTI.GOV)

Haselton, T.M.; Brangulis, A.P.; Margulis, L.S.

The Baltic Sea is roughly equivalent in size to the North Sea. Like the North Sea, is has an excellent oil prone source rock present over most of the area. In the entire Baltic Sea about 40 wells have been drilled. During the 1980s, exploration was carried out in the Soviet, Polish, and East German sectors of the Baltic Sea by Petrobaltic. Twenty-eight wells were drilled, 14 of which tested hydrocarbons. Two wells have been drilled in Danish waters and 11 in Swedish waters - all dry holes. Most of the Baltic Sea is included in the Baltic syneclise. Inmore » the deepest part of the basin a full Paleozoic and Mesozoic section is present. Major structural features are associated with reactivation of old basement faults. Most hydrocarbon discoveries are associated with structural arches. Exploration targets are Cambrian sandstones and Ordovician and Silurian reefs. The major discoveries are the B3 field in Poland and the D6 field offshore Lithuania and Kaliningrad, both of which have in-place reserves of around 100 million bbl. The Teisseyre-Tornquist line to the southwest represents the plate boundary between the East European platform and Europe. Repeated strike slip movements along this zone result in a complex pattern of extensional and compressional features in the Danish and German sectors. Primary exploration targets include Permian carbonates and sandstones as well as older zones. Gas has been tested in the German sector onshore.« less

Chapter 3: Geologic Assessment of Undiscovered Oil and Gas Resources in the Phosphoria Total Petroleum System of the Wind River Basin Province, Wyoming

USGS Publications Warehouse

Kirschbaum, M.A.; Lillis, P.G.; Roberts, L.N.R.

2007-01-01

The Phosphoria Total Petroleum System (TPS) encompasses the entire Wind River Basin Province, an area of 4.7 million acres in central Wyoming. The source rocks most likely are black, organic-rich shales of the Meade Peak and Retort Phosphatic Shale Members of the Permian Phosphoria Formation located in the Wyoming and Idaho thrust belt to the west and southwest of the province. Petroleum was generated and expelled during Jurassic and Cretaceous time in westernmost Wyoming and is interpreted to have migrated into the province through carrier beds of the Pennsylvanian Tensleep Sandstone where it was preserved in hypothesized regional stratigraphic traps in the Tensleep and Permian Park City Formation. Secondary migration occurred during the development of structural traps associated with the Laramide orogeny. The main reservoirs are in the Tensleep Sandstone and Park City Formation and minor reservoirs are in the Mississippian Madison Limestone, Mississippian-Pennsylvanian Amsden Formation, Triassic Chugwater Group, and Jurassic Nugget Sandstone and Sundance Formation. The traps are sealed by shale or evaporite beds of the Park City, Amsden, and Triassic Dinwoody Formations, Triassic Chugwater Group, and Jurassic Gypsum Spring Formation. A single conventional oil and gas assessment unit (AU), the Tensleep-Park City AU, was defined for the Phosphoria TPS. Both the AU and TPS cover the entire Wind River Basin Province. Oil is produced from 18 anticlinal fields, the last of which was discovered in 1957, and the possibility of discovering new structural oil accumulations is considered to be relatively low. Nonassociated gas is produced from only two fields, but may be underexplored in the province. The discovery of new gas is more promising, but will be from deep structures. The bulk of new oil and gas accumulations is dependent on the discovery of hypothesized stratigraphic traps in isolated carbonate reservoirs of the Park City Formation. Mean resource estimates for the Tensleep-Park City Conventional Oil and Gas AU total 18 million barrels of oil, 294 billion cubic feet of gas, and 5.9 million barrels of natural gas liquids.

Compaction and Permeability Reduction of Castlegate Sandstone under Pore Pressure Cycling

NASA Astrophysics Data System (ADS)

Bauer, S. J.

2014-12-01

We investigate time-dependent compaction and permeability changes by cycling pore pressure with application to compressed air energy storage (CAES) in a reservoir. Preliminary experiments capture the impacts of hydrostatic stress, pore water pressure, pore pressure cycling, chemical, and time-dependent considerations near a borehole in a CAES reservoir analog. CAES involves creating an air bubble in a reservoir. The high pressure bubble serves as a mechanical battery to store potential energy. When there is excess grid energy, bubble pressure is increased by air compression, and when there is energy needed on the grid, stored air pressure is released through turbines to generate electricity. The analog conditions considered are depth ~1 km, overburden stress ~20 MPa and a pore pressure ~10MPa. Pore pressure is cycled daily or more frequently between ~10 MPa and 6 MPa, consistent with operations of a CAES facility at this depth and may continue for operational lifetime (25 years). The rock can vary from initially fully-to-partially saturated. Pore pressure cycling changes the effective stress.Jacketed, room temperature tap water-saturated samples of Castlegate Sandstone are hydrostatically confined (20 MPa) and subjected to a pore pressure resulting in an effective pressure of ~10 MPa. Pore pressure is cycled between 6 to 10 MPa. Sample displacement measurements yielded determinations of volumetric strain and from water flow measurements permeability was determined. Experiments ran for two to four weeks, with 2 to 3 pore pressure cycles per day. The Castlegate is a fluvial high porosity (>20%) primarily quartz sandstone, loosely calcite cemented, containing a small amount of clay.Pore pressure cycling induces compaction (~.1%) and permeability decreases (~20%). The results imply that time-dependent compactive processes are operative. The load path, of increasing and decreasing pore pressure, may facilitate local loosening and grain readjustments that results in the compaction and permeability decreases observed. Sandia National Laboratories is a multi-program laboratory managed and operated by Sandia Corporation, a wholly owned subsidiary of Lockheed Martin Corporation, for the U.S. Dept. of Energy's National Nuclear Security Administration under contract DE-AC04-94AL85000.SAND2014-16586A

Aerial radiometric and magnetic reconnaissance survey of portions of Arizona, Idaho, Montana, New Mexico, South Dakota and Washington. Volume 2-F. Lewistown Quadrangle. Final report

DOE Office of Scientific and Technical Information (OSTI.GOV)

Not Available

1979-06-01

Results of a high-sensitivity, aerial, gamma-ray spectrometer and magnetometer survey of the Lewistown Quadrangle, Montana, are presented. Instrumentation and methods are described in Volume 1 of this final report. Statistical and geological analysis of the radiometric data revealed 58 uranium anomalies worthy of field-checking as possible prospects. One anomaly may be associated with the Cambrian Flathead Quartzite that may contain deposits similar to the Blind River and Rand uranium deposits. Three anomalies may be indicative of sandstone-type deposits in Jurassic rocks, particularly the Morrison Formation, which hosts uranium mineralization elsewhere. One of the latter anomalies is also related to rocksmore » of the Mississippian Madison Group, and this suggests the possible presence of uranium in limestones of the Mission Canyon Formation. There are 45 anomalies related to the Cretaceous rocks. Lignite in the Hell Creek and Judith River formations and Eagle Sandstone may have caused the formation of 22 epigenetic uranium deposits. Many anomalies occur in the Bearpaw Shale and Claggett Formation. However, only five are considered significant of the remainder are expected to be caused by large amounts of radioactive bentonite or bentonitic shale. Two other Cretaceous units that may host sandstone-type deposits are the Colorado Shale and Kootenai Formation that register 16 and two anomalies respectively. Only one anomaly pertains to Tertiary rocks, and it may be indicative of vein-type deposits in the intrusives of the Judith Mountains. These rocks may also act as source rocks for deposits surrounding the Judith Mountains. Eight anomalies related only to Quaternary units may be demonstrative of uranium-rich source rocks that could host uranium mineralization.Several anomalies are located close to oil fields and may have been cause by radium-rich oil-field brines.« less

Dynamic fluid connectivity during steady-state multiphase flow in a sandstone.

PubMed

Reynolds, Catriona A; Menke, Hannah; Andrew, Matthew; Blunt, Martin J; Krevor, Samuel

2017-08-01

The current conceptual picture of steady-state multiphase Darcy flow in porous media is that the fluid phases organize into separate flow pathways with stable interfaces. Here we demonstrate a previously unobserved type of steady-state flow behavior, which we term "dynamic connectivity," using fast pore-scale X-ray imaging. We image the flow of N 2 and brine through a permeable sandstone at subsurface reservoir conditions, and low capillary numbers, and at constant fluid saturation. At any instant, the network of pores filled with the nonwetting phase is not necessarily connected. Flow occurs along pathways that periodically reconnect, like cars controlled by traffic lights. This behavior is consistent with an energy balance, where some of the energy of the injected fluids is sporadically converted to create new interfaces.

Geologic framework for the national assessment of carbon dioxide storage resources: Denver Basin, Colorado, Wyoming, and Nebraska: Chapter G in Geologic framework for the national assessment of carbon dioxide storage resources

USGS Publications Warehouse

Drake II, Ronald M.; Brennan, Sean T.; Covault, Jacob A.; Blondes, Madalyn S.; Freeman, P.A.; Cahan, Steven M.; DeVera, Christina A.; Lohr, Celeste D.

2014-01-01

This is a report about the geologic characteristics of five storage assessment units (SAUs) within the Denver Basin of Colorado, Wyoming, and Nebraska. These SAUs are Cretaceous in age and include (1) the Plainview and Lytle Formations, (2) the Muddy Sandstone, (3) the Greenhorn Limestone, (4) the Niobrara Formation and Codell Sandstone, and (5) the Terry and Hygiene Sandstone Members. The described characteristics, as specified in the methodology, affect the potential carbon dioxide storage resource in the SAUs. The specific geologic and petrophysical properties of interest include depth to the top of the storage formation, average thickness, net-porous thickness, porosity, permeability, groundwater quality, and the area of structural reservoir traps. Descriptions of the SAU boundaries and the overlying sealing units are also included. Assessment results are not contained in this report; however, the geologic information included here will be used to calculate a statistical Monte Carlo-based distribution of potential storage volume in the SAUs.

Calibration of NMR well logs from carbonate reservoirs with laboratory NMR measurements and μXRCT

DOE PAGES

Mason, Harris E.; Smith, Megan M.; Hao, Yue; ...

2014-12-31

The use of nuclear magnetic resonance (NMR) well log data has the potential to provide in-situ porosity, pore size distributions, and permeability of target carbonate CO₂ storage reservoirs. However, these methods which have been successfully applied to sandstones have yet to be completely validated for carbonate reservoirs. Here, we have taken an approach to validate NMR measurements of carbonate rock cores with independent measurements of permeability and pore surface area to volume (S/V) distributions using differential pressure measurements and micro X-ray computed tomography (μXRCT) imaging methods, respectively. We observe that using standard methods for determining permeability from NMR data incorrectlymore » predicts these values by orders of magnitude. However, we do observe promise that NMR measurements provide reasonable estimates of pore S/V distributions, and with further independent measurements of the carbonate rock properties that universally applicable relationships between NMR measured properties may be developed for in-situ well logging applications of carbonate reservoirs.« less

Calibration of NMR well logs from carbonate reservoirs with laboratory NMR measurements and μXRCT

DOE Office of Scientific and Technical Information (OSTI.GOV)

Mason, Harris E.; Smith, Megan M.; Hao, Yue

The use of nuclear magnetic resonance (NMR) well log data has the potential to provide in-situ porosity, pore size distributions, and permeability of target carbonate CO₂ storage reservoirs. However, these methods which have been successfully applied to sandstones have yet to be completely validated for carbonate reservoirs. Here, we have taken an approach to validate NMR measurements of carbonate rock cores with independent measurements of permeability and pore surface area to volume (S/V) distributions using differential pressure measurements and micro X-ray computed tomography (μXRCT) imaging methods, respectively. We observe that using standard methods for determining permeability from NMR data incorrectlymore » predicts these values by orders of magnitude. However, we do observe promise that NMR measurements provide reasonable estimates of pore S/V distributions, and with further independent measurements of the carbonate rock properties that universally applicable relationships between NMR measured properties may be developed for in-situ well logging applications of carbonate reservoirs.« less

Modeling high resolution stratigraphy in the Cusiana Field, Eastern Colombia; static builds to dynamic simulation

DOE Office of Scientific and Technical Information (OSTI.GOV)

Pulham, A.; MacDonald, D.; Colin, D.

1996-12-31

The Cusiana Field (BP, Ecopetrol, Total and Triton) is located in the Llanos Foothills of Eastern Colombia. The Cusiana reservoirs range from late Cretaceous, passive margin deltaic to early Tertiary, early foreland basin estuarine-fluvial. The key reservoir is the late Eocene Mirador Formation which comprises over 50% of reserves. Currently the Mirador reservoir is providing nearly all of the 180,00 bopd of production from the Cusiana Field. The Mirador reservoir comprises a stack of incised valley deposits. The fills of the valleys are sandstone-dominated and comprise the majority of the reservoir quality in the reservoir. Critical to an effective understandingmore » of reservoir behavior has been a detailed reservoir description and reservoir modeling of the incised valley stratigraphy in the Mirador. Models have been constructed using the deterministic information provided by extensive core (3000 feet) coupled with stochastic tools and techniques. Dynamic data, provided by extensive acquisition of production logs during early development drilling, have been integrated within the static-descriptions. Important reservoir characteristics such as degree of valley connectivity, intra-valley heterogeneities and textural controls on permeability have been captured in the modeling process. Upscaling of the high resolution static model has preserved the key sequence stratigraphic facets of the reservoir and also incorporated textural controls on relative permeability. Prediction of pressure transient behavior and fluid movement is working well in the full field simulator, VIP.« less

Identification and determination of trapping parameters as key site parameters for CO2 storage for the active CO2 storage site in Ketzin (Germany) - Comparison of different experimental approaches and analysis of field data

NASA Astrophysics Data System (ADS)

Zemke, Kornelia; Liebscher, Axel

2015-04-01

Petrophysical properties like porosity and permeability are key parameters for a safe long-term storage of CO2 but also for the injection operation itself. The accurate quantification of residual trapping is difficult, but very important for both storage containment security and storage capacity; it is also an important parameter for dynamic simulation. The German CO2 pilot storage in Ketzin is a Triassic saline aquifer with initial conditions of the target sandstone horizon of 33.5 ° C/6.1 MPa at 630 m. One injection and two observation wells were drilled in 2007 and nearly 200 m of core material was recovered for site characterization. From June 2008 to September 2013, slightly more than 67 kt food-grade CO2 has been injected and continuously monitored. A fourth observation well has been drilled after 61 kt injected CO2 in summer 2012 at only 25 m distance to the injection well and new core material was recovered that allow study CO2 induced changes in petrophysical properties. The observed only minor differences between pre-injection and post-injection petrophysical parameters of the heterogeneous formation have no severe consequences on reservoir and cap rock integrity or on the injection behavior. Residual brine saturation for the Ketzin reservoir core material was estimated by different methods. Brine-CO2 flooding experiments for two reservoir samples resulted in 36% and 55% residual brine saturation (Kiessling, 2011). Centrifuge capillary pressure measurements (pc = 0.22 MPa) yielded the smallest residual brine saturation values with ~20% for the lower part of the reservoir sandstone and ~28% for the upper part (Fleury, 2010). The method by Cerepi (2002), which calculates the residual mercury saturation after pressure release on the imbibition path as trapped porosity and the retracted mercury volume as free porosity, yielded unrealistic low free porosity values of only a few percent, because over 80% of the penetrated mercury remained in the samples after pressure release to atmospheric pressure. The results from the centrifuge capillary pressure measurements were then used for calibrating the cutoff time of NMR T2 relaxation (average value 8 ms) to differentiate between the mobile and immobile water fraction (standard for clean sandstone 33 ms). Following Norden (2010) a cutoff time of 10 ms was applied to estimate the residual saturation as Bound Fluid Volume for the Ketzin core materials and to estimate NMR permeability after Timur-Coates. This adapted cutoff value is also consistent with results from RST logging after injection. The maximum measured CO2 saturation corresponds to the effective porosity for the upper most CO2 filled sandstone horizon. The directly measured values and the estimated residual brine saturations from NMR measurements with the adapted cutoff time of 10 ms are within the expected range compared to the literature data with a mean residual brine saturation of 53%. A. Cerepi et al., 2002, Journal of Petroleum Science and Engineering 35. M. Fleury et al., 2011, SCA2010-06. D. Kiessling et al., 2010, International Journal of Greenhouse Gas Control 4. B. Norden et al. 2010, SPE Reservoir Evaluation & Engineering 13. .

Monitoring CO2 penetration and storage in the brine-saturated low permeable sandstone by the geophysical exploration technologies

NASA Astrophysics Data System (ADS)

Honda, H.; Mitani, Y.; Kitamura, K.; Ikemi, H.; Imasato, M.

2017-12-01

Carbon dioxide (CO2) capture and storage (CCS) plays a vital role in reducing greenhouse gas emissions. In the northern part of Kyushu region of Japan, complex geological structure (Coalfield) is existed near the CO2 emission source and has 1.06 Gt of CO2 storage capacity. The geological survey shows that these layers are formed by low permeable sandstone. It is necessary to monitor the CO2 behavior and clear the mechanisms of CO2 penetration and storage in the low permeable sandstone. In this study, measurements of complex electrical impedance (Z) and elastic wave velocity (P-wave velocity: Vp) were conducted during the supercritical CO2 injection experiment into the brine-saturated low permeable sandstone. The experiment conditions were as follows; Confining pressure: 20 MPa, Initial pore pressure: 10 MPa, 40 °, CO2 injection rate: 0.01 to 0.5 mL/min. Z was measured in the center of the specimen and Vp were measured at three different heights of the specimen at constant intervals. In addition, we measured the longitudinal and lateral strain at the center of the specimen, the pore pressure and CO2 injection volume (CO2 saturation). During the CO2 injection, the change of Z and Vp were confirmed. In the drainage terms, Vp decreased drastically once CO2 reached the measurement cross section.Vp showed the little change even if the flow rate increased (CO2 saturation increased). On the other hand, before the CO2 front reached, Z decreased with CO2-dissolved brine. After that, Z showed continuously increased as the CO2 saturation increased. From the multi-parameter (Hydraulic and Rock-physics parameters), we revealed the detail CO2 behavior in the specimen. In the brine-saturated low permeable sandstone, the slow penetration of CO2 was observed. However, once CO2 has passed, the penetration of CO2 became easy in even for brine-remainded low permeable sandstone. We conclude low permeable sandstone has not only structural storage capacity but also residual tapping (Capillary trapping) capacity. There is a positive possibility to conduct CCS in the low-quality reservoir (low permeable sandstone).

Bedrock aquifers of eastern San Juan County, Utah

USGS Publications Warehouse

Avery, Charles

1986-01-01

This study is one of a series of studies appraising the waterbearing properties of the Navajo Sandstone and associated formations in southern Utah.  The stu<¥ area is al:x>dy area is about 4,600 square miles, extending from the Utah-Arizona State line northward to the San Juan-Grand County line and westward from the Utah-Colorado State line to the longitude of about 109°50'.Some of the water-yielding formations are grouped into aquifer systems. The C aquifer is comprised of the DeChelly Sandstone Member of the Cutler Formation.  The P aquifer is comprised of the Cedar Mesa Member of the Cutler Formation and the undifferentiated Cutler Formation. The N aquifer is comprised of the sedimentary section that includes the Wingate Sandstone, Kayenta Formation, Navajo Sandstone, Carmel Formation, and Entrada sandstone.  The M aquifer is comprised of the Bluff Sandstone Member and other sandstone units of the Morrison Formation.  The D aquifer is comprised of the Burro Canyon Formation and Dakota Sandstone.  Discharge from the ground-water reservoir to the San Juan River between gaging stations at Four Corners and Mexican Hat is about 66 cubic feet per second.The N aquifer is the main aquifer in the study area. Recharge by infiltration of precipitation is estimated to be 25,000 acre-feet per year.  A major ground-water divide exists under the broad area east of Monticello.  The thickness of the N aquifer, where the sedimentary section is fully preserved and saturated, generally is 750 to 1,250 feet.   Hydraulic conductivity values obtained from aquifer tests range from 0.02 to 0.34 foot per day.  The total volume of water in transient storage is about 11 million acre-feet. Well discharge somewhat exceeded 2,340 acre-feet during 1981.  Discharge to the San Juan River from the N aquifer is estimated to be 6.9 cubic feet per second. Water quality ranges from a calcium bicarbonate to sodium chloride type water

Petroleum geology and resources of southeastern Mexico, northern Guatemala, and Belize

USGS Publications Warehouse

Peterson, James A.

1983-01-01

Petroleum deposits in southeastern Mexico and Guatemala occur in two main basinal provinces, the Gulf Coast Tertiary basin area, which includes the Reforma and offshore Campeche Mesozoic fields, and the Peten basin of eastern Chiapas State (Mexico) and Guatemala. Gas production is mainly from Tertiary sandstone reservoirs of Miocene age. Major oil production, in order of importance, is from Cretaceous, Paleocene, and Jurassic carbonate reservoirs in the Reforma and offshore Campeche areas. Several small oil fields have been discovered in Cretaceous carbonate reservoirs in west-central Guatemala, and one major discovery has been reported in northwestern Guatemala. Small- to medium-sized oil accumulations also occur in Miocene sandstone reservoirs on salt structures in the Isthmus Saline basin of western Tabasco State, Mexico. Almost all important production is in salt structure traps or on domes and anticlines that may be related to deep-seated salt structures. Some minor oil production has occurred in Cretaceous carbonate reservoirs in a buried overthrust belt along the west flank of the Veracruz basin. The sedimentary cover of Paleozoic through Tertiary rocks ranges in thickness from about 6,000 m (20,000 ft) to as much as 12,000 m (40,000 ft) or more in most of the region. Paleozoic marine carbonate and clastic rocks 1,000 to 2,000 m (3,300 to 6,500 ft) thick overlie the metamorphic and igneous basement in part of the region; Triassic through Middle Jurassic red beds and evaporite deposits, including halite, apparently are present throughout the region, deposited in part in a Triassic graben system. Upper Jurassic (Oxfordian) through Cretaceous rocks make up the bulk of the Mesozoic regional carbonate bank complex, which dominates most of the area. Tertiary marine and continental clastic rocks, some of deep water origin, 3,000 to 10,000 m (10,000 to 35,000 ft) thick, are present in the coastal plain Tertiary basins. These beds grade eastward into a carbonate sequence that overlies the Mesozoic carbonate complex on the Yucatan platform. During the past 10 years, about 50 large oil fields were discovered in the Reforma and offshore Campeche areas. Oil is produced from intensely microfractured Cretaceous, Paleocene, and Upper Jurassic dolomite reservoirs on blockfaulted salt swells or domes. Most fields are located in the Mesozoic carbonate-bank margin and forebank talus (Tamabra) facies, which passes through the offshore Campeche and onshore Reforma areas. Oil source rocks are believed to be organic-rich shales and shaly carbonate rocks of latest Jurassic and possibly Early Cretaceous age. At least six of the Mesozoic discoveries are giant or supergiant fields. The largest is the Cantarell complex (about 8 billion to 10 billion barrels (BB)) in the offshore Campeche area and the Bermudez complex (about 8 BB) in the Reforma onshore area. Oil columns are unusually large (from 50 m to as much as 1,000 m, or 160 ft to 3,300 ft). Production rates are extremely high, averaging at least 3,000 to 5,000 barrels of oil per day (bo/d); some wells produce more than 20,000 bo/d, particularly in the offshore Campeche area, where 30,000- to 60,000-bo/d wells are reported. Tertiary basin fields produce primarily from Miocene sandstone reservoirs. About 50 of these are oil fields ranging from 1 million barrels (MMB) to 200 MMB in size, located on faulted salt structures in the Isthmus Saline basin. Another 30 are gas or gas-condensate fields of a few billion cubic feet to 3 trillion to 4 trillion cubic feet (Tcf) located on salt structures or probable salt structures in the Macuspana, Comalcalco, Isthmus Saline, and Veracruz basins. Source rocks for the gas are believed to be carbonaceous shales interbedded with the sandstone reservoir bodies. Identified reserves in the southeastern Mexico-Guatemala area, almost all in the Mesozoic fields, are about 53 BB of oil, 3 BB of natural gas liquids, and 65 Tcf of gas. The estimat

Reconstructing the Avalon continent: Marginal to inner platform transition in the Cambrian of southern New Brunswick

USGS Publications Warehouse

Landing, E.

1996-01-01

A west to east, marginal to inner Avalonian platform transition, comparable to that in southeast Newfoundland and southern Britain, is present in the Cambrian of southern New Brunswick. The Saint John - Caton's Island - Hanford Brook area lay on the marginal platform, and its thick, uppermost Precambrian - lower Lower Cambrian is unconformably overlain by trilobite-bearing, upper Lower Cambrian. An inner platform remnant is preserved in the Cradle Brook outlier 60 km northeast of Saint John. In contrast to the marginal platform sequences, the Cradle Brook outlier has a very thin lower Lower Cambrian and has middle Lower Cambrian strata (Bonavista Group) not present on the marginal platform. The Cradle Brook Lower Cambrian closely resembles inner platform successions in eastern Massachusetts and Trinity and Placentia bays, southeast Newfoundland. A limestone with Camenella baltica Zone fossils on Cradle Brook seems to be the peritidal limestone cap of the subtrilobitic Lower Cambrian known in Avalonian North America (Fosters Point Formation) and England (Home Farm Member).

Effects of microstructure on water imbibition in sandstones using X-ray computed tomography and neutron radiography

NASA Astrophysics Data System (ADS)

Zhao, Yixin; Xue, Shanbin; Han, Songbai; Chen, Zhongwei; Liu, Shimin; Elsworth, Derek; He, Linfeng; Cai, Jianchao; Liu, Yuntao; Chen, Dongfeng

2017-07-01

Capillary imbibition in variably saturated porous media is important in defining displacement processes and transport in the vadose zone and in low-permeability barriers and reservoirs. Nonintrusive imaging in real time offers the potential to examine critical impacts of heterogeneity and surface properties on imbibition dynamics. Neutron radiography is applied as a powerful imaging tool to observe temporal changes in the spatial distribution of water in porous materials. We analyze water imbibition in both homogeneous and heterogeneous low-permeability sandstones. Dynamic observations of the advance of the imbibition front with time are compared with characterizations of microstructure (via high-resolution X-ray computed tomography (CT)), pore size distribution (Mercury Intrusion Porosimetry), and permeability of the contrasting samples. We use an automated method to detect the progress of wetting front with time and link this to square-root-of-time progress. These data are used to estimate the effect of microstructure on water sorptivity from a modified Lucas-Washburn equation. Moreover, a model is established to calculate the maximum capillary diameter by modifying the Hagen-Poiseuille and Young-Laplace equations based on fractal theory. Comparing the calculated maximum capillary diameter with the maximum pore diameter (from high-resolution CT) shows congruence between the two independent methods for the homogeneous silty sandstone but less effectively for the heterogeneous sandstone. Finally, we use these data to link observed response with the physical characteristics of the contrasting media—homogeneous versus heterogeneous—and to demonstrate the sensitivity of sorptivity expressly to tortuosity rather than porosity in low-permeability sandstones.

Unconformity-related oil entrapment in Muddy Sandstone: comparison of Kitty and Amos Draw fields, Powder River basin, Wyoming

DOE Office of Scientific and Technical Information (OSTI.GOV)

Odland, S.K.; Gardner, M.H.; Gustason, E.R.

1986-08-01

It has long been known that an unconformity plays a critical role in trapping oil in the Muddy Sandstone in the Powder River basin, but opinions have varied as to exactly where in the section that unconformity is located. Their work indicates that there are, in fact, two unconformities associated with the Muddy in the northern part of the basin. The older of these occurs on top of the Skull Creek Shale, whereas the younger is largely intraformational. In places, the younger unconformity has truncated the older one. It is the younger unconformity that is responsible for creating favorable settingsmore » for stratigraphic entrapment of oil. Two types of unconformity-related oil traps result from fluvial downcutting into and through the strand-plain sandstones of the oldest member of the Muddy during a major sea level drop. In cases where the unconformity cuts through the Muddy into the underlying Skull Creek Shale, permeable valley-fill sediments, deposited during the Muddy transgression, are juxtaposed against the impermeable Skull Creek Shale along the valley walls. Where valleys are oriented roughly perpendicular to regional structure, as at Kitty field, the updip portion of the valley wall can form a permeability barrier to the fluvial reservoir sandstones of the adjacent valley fill. In cases where the unconformity is intraformational, such as at Amos Draw field, early diagenetic clay, associated with the weathered horizon directly beneath the unconformity, can create a seal on top of the strand-plain sandstones of the oldest member of the Muddy.« less

Silurian "Clinton" Sandstone Reservoir Characterization for Evaluation of CO2-EOR Potential in the East Canton Oil Field, Ohio

DOE Office of Scientific and Technical Information (OSTI.GOV)

Riley, Ronald; Wicks, John; Perry, Christopher

The purpose of this study was to evaluate the efficacy of using CO2-enhanced oil recovery (EOR) in the East Canton oil field (ECOF). Discovered in 1947, the ECOF in northeastern Ohio has produced approximately 95 million barrels (MMbbl) of oil from the Silurian “Clinton” sandstone. The original oil-in-place (OOIP) for this field was approximately 1.5 billion bbl and this study estimates by modeling known reservoir parameters, that between 76 and 279 MMbbl of additional oil could be produced through secondary recovery in this field, depending on the fluid and formation response to CO2 injection. A CO2 cyclic test (“Huff-n-Puff”) wasmore » conducted on a well in Stark County to test the injectivity in a “Clinton”-producing oil well in the ECOF and estimate the dispersion or potential breakthrough of the CO2 to surrounding wells. Eighty-one tons of CO2 (1.39 MMCF) were injected over a 20-hour period, after which the well was shut in for a 32-day “soak” period before production was resumed. Results demonstrated injection rates of 1.67 MMCF of gas per day, which was much higher than anticipated and no CO2 was detected in gas samples taken from eight immediately offsetting observation wells. All data collected during this test was analyzed, interpreted, and incorporated into the reservoir characterization study and used to develop the geologic model. The geologic model was used as input into a reservoir simulation performed by Fekete Associates, Inc., to estimate the behavior of reservoir fluids when large quantities of CO2 are injected into the “Clinton” sandstone. Results strongly suggest that the majority of the injected CO2 entered the matrix porosity of the reservoir pay zones, where it diffused into the oil. Evidence includes: (A) the volume of injected CO2 greatly exceeded the estimated capacity of the hydraulic fracture and natural fractures; (B) there was a gradual injection and pressure rate build-up during the test; (C) there was a subsequent, gradual flashout of the CO2 within the reservoir during the ensuing monitored production period; and (D) a large amount of CO2 continually off-gassed from wellhead oil samples collected as late as 3½ months after injection. After the test well was returned to production, it produced 174 bbl of oil during a 60-day period (September 22 to November 21, 2008), which represents an estimated 58 percent increase in incremental oil production over preinjection estimates of production under normal, conditions. The geologic model was used in a reservoir simulation model for a 700-acre model area and to design a pilot to test the model. The model was designed to achieve a 1-year response time and a five-year simulation period. The reservoir simulation modeling indicated that the injection wells could enhance oil production and lead to an additional 20 percent recovery in the pilot area over a five-year period. The base case estimated that by injecting 500 MCF per day of CO2 into each of the four corner wells, 26,000 STBO would be produced by the central producer over the five-year period. This would compare to 3,000 STBO if a new well were drilled without the benefit of CO2 injection. This study has added significant knowledge to the reservoir characterization of the “Clinton” in the ECOF and succeeded in identifying a range on CO2-EOR potential. However, additional data on fluid properties (PVT and swelling test), fractures (oriented core and microseis), and reservoir characteristics (relative permeability, capillary pressure, and wet ability) are needed to further narrow the uncertainties and refine the reservoir model and simulation. After collection of this data and refinement of the model and simulation, it is recommended that a larger scale cyclic- CO2 injection test be conducted to better determine the efficacy of CO2-EOR in the “Clinton” reservoir in the ECOF.« less

Silurian "Clinton" Sandstone Reservoir Characterization for Evaluation of CO2-EOR Potential in the East Canton Oil Field, Ohio

DOE Office of Scientific and Technical Information (OSTI.GOV)

Ronald Riley; John Wicks; Christopher Perry

The purpose of this study was to evaluate the efficacy of using CO2-enhanced oil recovery (EOR) in the East Canton oil field (ECOF). Discovered in 1947, the ECOF in northeastern Ohio has produced approximately 95 million barrels (MMbbl) of oil from the Silurian 'Clinton' sandstone. The original oil-in-place (OOIP) for this field was approximately 1.5 billion bbl and this study estimates by modeling known reservoir parameters, that between 76 and 279 MMbbl of additional oil could be produced through secondary recovery in this field, depending on the fluid and formation response to CO2 injection. A CO2 cyclic test ('Huff-n-Puff') wasmore » conducted on a well in Stark County to test the injectivity in a 'Clinton'-producing oil well in the ECOF and estimate the dispersion or potential breakthrough of the CO2 to surrounding wells. Eighty-one tons of CO2 (1.39 MMCF) were injected over a 20-hour period, after which the well was shut in for a 32-day 'soak' period before production was resumed. Results demonstrated injection rates of 1.67 MMCF of gas per day, which was much higher than anticipated and no CO2 was detected in gas samples taken from eight immediately offsetting observation wells. All data collected during this test was analyzed, interpreted, and incorporated into the reservoir characterization study and used to develop the geologic model. The geologic model was used as input into a reservoir simulation performed by Fekete Associates, Inc., to estimate the behavior of reservoir fluids when large quantities of CO2 are injected into the 'Clinton' sandstone. Results strongly suggest that the majority of the injected CO2 entered the matrix porosity of the reservoir pay zones, where it diffused into the oil. Evidence includes: (A) the volume of injected CO2 greatly exceeded the estimated capacity of the hydraulic fracture and natural fractures; (B) there was a gradual injection and pressure rate build-up during the test; (C) there was a subsequent, gradual flashout of the CO2 within the reservoir during the ensuing monitored production period; and (D) a large amount of CO2 continually off-gassed from wellhead oil samples collected as late as 3 1/2 months after injection. After the test well was returned to production, it produced 174 bbl of oil during a 60-day period (September 22 to November 21, 2008), which represents an estimated 58 percent increase in incremental oil production over preinjection estimates of production under normal, conditions. The geologic model was used in a reservoir simulation model for a 700-acre model area and to design a pilot to test the model. The model was designed to achieve a 1-year response time and a five-year simulation period. The reservoir simulation modeling indicated that the injection wells could enhance oil production and lead to an additional 20 percent recovery in the pilot area over a five-year period. The base case estimated that by injecting 500 MCF per day of CO2 into each of the four corner wells, 26,000 STBO would be produced by the central producer over the five-year period. This would compare to 3,000 STBO if a new well were drilled without the benefit of CO2 injection. This study has added significant knowledge to the reservoir characterization of the 'Clinton' in the ECOF and succeeded in identifying a range on CO2-EOR potential. However, additional data on fluid properties (PVT and swelling test), fractures (oriented core and microseis), and reservoir characteristics (relative permeability, capillary pressure, and wet ability) are needed to further narrow the uncertainties and refine the reservoir model and simulation. After collection of this data and refinement of the model and simulation, it is recommended that a larger scale cyclic-CO2 injection test be conducted to better determine the efficacy of CO2-EOR in the 'Clinton' reservoir in the ECOF.« less

A new petroleum system in offshore Campeche, Mexico

DOE Office of Scientific and Technical Information (OSTI.GOV)

Limon, M.

1996-08-01

A new petroleum system in the Sonda de Campeche of Mexico has been recently defined. This system is entirely Oxfordian in age, comprising eolian and beach sandstone reservoirs overlain by evaporates, which provide the seal, and in turn, overlain by organically rich, low energy carbonate mudstones, which are source rocks. This petroleum system was created during the late stages of opening of the Gulf of Mexico. The source rocks are composed of an algal mudstone overlying the evaporite sequence. Geochemistry, isotopic and biomarkers analyses allowed us to identify the Oxfordian source rock and also to obtain an excellent correlation withmore » the Oxfordian oils reservoired in the discoveries. Oxfordian sandstones in the Sonda de Campeche exhibit excellent reservoir quality, ranging from 6 to 26% porosity and 2 to 2730 md permeability. The porosity is principally secondary due to the dissolution of dolomite, anhydrite and cement, but intergranular porosity can also be observed. The tectonic evolution of the Gulf of Mexico in the Sonda de Campeche produced three types of traps (1) faulted blocks of {open_quotes}domino{close_quotes} style, developed during the extensional stage; (2) faulted anticlines formed during the Middle Miocene compressive event; and (3) traps related to diapirism of salt of the Middle Miocene-Pleistocene. The seal rocks are mainly composed by Oxfordian evaporates. Oil generation was initiated in the Middle Miocene following the compressional stage. The potential source rocks reached maturity beneath a thick Tertiary overburden in downthrown fault blocks and expelled hydrocarbons which migrated in a predominantly vertical direction. The oils do not show any diagnostic evidence of bacterial alteration.« less

A new petroleum system in offshore Campeche, Mexico

DOE Office of Scientific and Technical Information (OSTI.GOV)

Gonzalez, R.; Cruz, P.; Limon, M.

1995-08-01

A new petroleum system in the Sonda de Campeche of Mexico has been recently defined. This system is entirely Oxfordian in age, comprising eolian and beach sandstone reservoirs overlain by evaporites, which provide the seal, and in turn, overlain by organically rich, low energy carbonate mudstones, which are source rocks. This petroleum system was created during the late stages of opening of the Gulf of Mexico. The source rocks are composed of an algal mudstone overlying the evaporite sequence. Geochemistry, isotopic and biomarkers analyses allowed us to identify the Oxfordian source rock and also to obtain an excellent correlation withmore » the oils Oxfordian reservoired in the discoveries. Oxfordian sandstones in the Sonda de Campeche exhibit excellent reservoir quality, ranging from 6 to 26% porosity and 2 to 2730 md permeability. The porosity is principally secondary due to the dissolution of dolomite anhydrite and cement but intergranular porosity can also be observed. The tectonic evolution of the Gulf of Mexico, in the Sonda de Campeche produced three types of traps (1) faulted blocks of {open_quotes}domino{close_quotes} style, developed during the extensional stage; (2) faulted anticlines formed during the Middle Miocene compressive event; and (3) traps related to diapirism of salt of the Middle Miocene-Pleistocene. The seal rocks are mainly composed by Oxfordian evaporates. Oil generation was initiated in the Middle Miocene following the compressional stage. The potential source rocks reached maturity beneath a thick Tertiary overburden in downthrown fault blocks and expelled hydrocarbons which migrated in a predominantly vertical direction. The oils do not show any diagnostic evidence of bacterial alteration.« less

Shahejie-Shahejie/Guantao/Wumishan and Carboniferous/Permian Coal-Paleozoic Total Petroleum Systems in the Bohaiwan Basin, China (based on geologic studies for the 2000 World Energy Assessment Project of the U.S. Geological Survey)

USGS Publications Warehouse

Ryder, Robert T.; Qiang, Jin; McCabe, Peter J.; Nuccio, Vito F.; Persits, Felix

2012-01-01

This report discusses the geologic framework and petroleum geology used to assess undiscovered petroleum resources in the Bohaiwan basin province for the 2000 World Energy Assessment Project of the U.S. Geological Survey. The Bohaiwan basin in northeastern China is the largest petroleum-producing region in China. Two total petroleum systems have been identified in the basin. The first, the Shahejie&ndashShahejie/Guantao/Wumishan Total Petroleum System, involves oil and gas generated from mature pods of lacustrine source rock that are associated with six major rift-controlled subbasins. Two assessment units are defined in this total petroleum system: (1) a Tertiary lacustrine assessment unit consisting of sandstone reservoirs interbedded with lacustrine shale source rocks, and (2) a pre-Tertiary buried hills assessment unit consisting of carbonate reservoirs that are overlain unconformably by Tertiary lacustrine shale source rocks. The second total petroleum system identified in the Bohaiwan basin is the Carboniferous/Permian Coal–Paleozoic Total Petroleum System, a hypothetical total petroleum system involving natural gas generated from multiple pods of thermally mature coal beds. Low-permeability Permian sandstones and possibly Carboniferous coal beds are the reservoir rocks. Most of the natural gas is inferred to be trapped in continuous accumulations near the center of the subbasins. This total petroleum system is largely unexplored and has good potential for undiscovered gas accumulations. One assessment unit, coal-sourced gas, is defined in this total petroleum system.