Thermal maturity map of Devonian shale in the Illinois, Michigan, and Appalachian basins of North America

USGS Publications Warehouse

East, Joseph A.; Swezey, Christopher S.; Repetski, John E.; Hayba, Daniel O.

2012-01-01

Much of the oil and gas in the Illinois, Michigan, and Appalachian basins of eastern North America is thought to be derived from Devonian shale that is within these basins (for example, Milici and others, 2003; Swezey, 2002, 2008, 2009; Swezey and others, 2005, 2007). As the Devonian strata were buried by younger sediments, the Devonian shale was subjected to great temperature and pressure, and in some areas the shale crossed a thermal maturity threshold and began to generate oil. With increasing burial (increasing temperature and pressure), some of this oil-generating shale crossed another thermal maturity threshold and began to generate natural gas. Knowledge of the thermal maturity of the Devonian shale is therefore useful for predicting the occurrence and the spatial distribution of oil and gas within these three basins. This publication presents a thermal maturity map of Devonian shale in the Illinois, Michigan, and Appalachian basins. The map shows outlines of the three basins (dashed black lines) and an outline of Devonian shale (solid black lines). The basin outlines are compiled from Thomas and others (1989) and Swezey (2008, 2009). The outline of Devonian shale is a compilation from Freeman (1978), Thomas and others (1989), de Witt and others (1993), Dart (1995), Nicholson and others (2004), Dicken and others (2005a,b), and Stoeser and others (2005).

Dissolved methane in New York groundwater, 1999-2011

USGS Publications Warehouse

Kappel, William M.; Nystrom, Elizabeth A.

2012-01-01

New York State is underlain by numerous bedrock formations of Cambrian to Devonian age that produce natural gas and to a lesser extent oil. The first commercial gas well in the United States was dug in the early 1820s in Fredonia, south of Buffalo, New York, and produced methane from Devonian-age black shale. Methane naturally discharges to the land surface at some locations in New York. At Chestnut Ridge County Park in Erie County, just south of Buffalo, N.Y., several surface seeps of natural gas occur from Devonian black shale, including one behind a waterfall. Methane occurs locally in the groundwater of New York; as a result, it may be present in drinking-water wells, in the water produced from those wells, and in the associated water-supply systems (Eltschlager and others, 2001). The natural gas in low-permeability bedrock formations has not been accessible by traditional extraction techniques, which have been used to tap more permeable sandstone and carbonate bedrock reservoirs. However, newly developed techniques involving horizontal drilling and high-volume hydraulic fracturing have made it possible to extract previously inaccessible natural gas from low-permeability bedrock such as the Marcellus and Utica Shales. The use of hydraulic fracturing to release natural gas from these shale formations has raised concerns with water-well owners and water-resource managers across the Marcellus and Utica Shale region (West Virginia, Pennsylvania, New York and parts of several other adjoining States). Molofsky and others (2011) documented the widespread natural occurrence of methane in drinking-water wells in Susquehanna County, Pennsylvania. In the same county, Osborn and others (2011) identified elevated methane concentrations in selected drinking-water wells in the vicinity of Marcellus gas-development activities, although pre-development samples were not available for comparison. In order to manage water resources in areas of gas-well drilling and hydraulic fracturing in New York, the natural occurrence of methane in the State's aquifers needs to be documented. This brief report presents a compilation of data on dissolved methane concentrations in the groundwater of New York available from the U.S. Geological Survey (USGS) National Water Information System (NWIS) (http://waterdata.usgs.gov/nwis).

Revisions to the original extent of the Devonian Shale-Middle and Upper Paleozoic Total Petroleum System

USGS Publications Warehouse

Enomoto, Catherine B.; Rouse, William A.; Trippi, Michael H.; Higley, Debra K.

2016-04-11

Technically recoverable undiscovered hydrocarbon resources in continuous accumulations are present in Upper Devonian and Lower Mississippian strata in the Appalachian Basin Petroleum Province. The province includes parts of New York, Pennsylvania, Ohio, Maryland, West Virginia, Virginia, Kentucky, Tennessee, Georgia, and Alabama. The Upper Devonian and Lower Mississippian strata are part of the previously defined Devonian Shale-Middle and Upper Paleozoic Total Petroleum System (TPS) that extends from New York to Tennessee. This publication presents a revision to the extent of the Devonian Shale-Middle and Upper Paleozoic TPS. The most significant modification to the maximum extent of the Devonian Shale-Middle and Upper Paleozoic TPS is to the south and southwest, adding areas in Tennessee, Georgia, Alabama, and Mississippi where Devonian strata, including potential petroleum source rocks, are present in the subsurface up to the outcrop. The Middle to Upper Devonian Chattanooga Shale extends from southeastern Kentucky to Alabama and eastern Mississippi. Production from Devonian shale has been established in the Appalachian fold and thrust belt of northeastern Alabama. Exploratory drilling has encountered Middle to Upper Devonian strata containing organic-rich shale in west-central Alabama. The areas added to the TPS are located in the Valley and Ridge, Interior Low Plateaus, and Appalachian Plateaus physiographic provinces, including the portion of the Appalachian fold and thrust belt buried beneath Cretaceous and younger sediments that were deposited on the U.S. Gulf Coastal Plain.

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

Negus-De Wys, J.; Dixon, J. M.; Evans, M. A.

This document consists of the following papers: inorganic geochemistry studies of the Eastern Kentucky Gas Field; lithology studies of upper Devonian well cuttings in the Eastern Kentucky Gas Field; possible effects of plate tectonics on the Appalachian Devonian black shale production in eastern Kentucky; preliminary depositional model for upper Devonian Huron age organic black shale in the Eastern Kentucky Gas Field; the anatomy of a large Devonian black shale gas field; the Cottageville (Mount Alto) Gas Field, Jackson County, West Virginia: a case study of Devonian shale gas production; the Eastern Kentucky Gas Field: a geological study of the relationshipsmore » of Ohio Shale gas occurrences to structure, stratigraphy, lithology, and inorganic geochemical parameters; and a statistical analysis of geochemical data for the Eastern Kentucky Gas Field.« less

Correlation of LANDSAT lineaments with Devonian gas fields in Lawrence County, Ohio

NASA Technical Reports Server (NTRS)

Johnson, G. O.

1981-01-01

In an effort to locate sources of natural gas in Ohio, the fractures and lineaments in Black Devonian shale were measured by: (1) field mapping of joints, swarms, and fractures; (2) stereophotointerpretation of geomorphic lineaments with precise photoquads; and (3) by interpreting the linear features on LANDSAT images. All results were compiled and graphically represented on 1:250,000 scale maps. The geologic setting of Lawrence County was defined and a field fracture map was generated and plotted as rose patterns at the exposure site. All maps were compared, contrasted, and correlated by superimposing each over the other as a transparency. The LANDSAT lineaments had significant correlation with the limits of oil and gas producing fields. These limits included termination of field production as well as extensions to other fields. The lineaments represent real rock fractures with zones of increased permeability in the near surface bedrock.

Retrospective Case Study in Northeastern Pennsylvania, Study of the Potential Impacts of Hydraulic Fracturing On Drinking Water Resources

EPA Science Inventory

This report describes the retrospective case study for northeastern Pennsylvania, which was conducted in Bradford and Susquehanna Counties where some of the most intensive unconventional gas production from the Devonian-age Marcellus Shale has occurred. Gas production from the M...

18 CFR 270.303 - Natural gas produced from Devonian shale.

Code of Federal Regulations, 2010 CFR

2010-04-01

... 18 Conservation of Power and Water Resources 1 2010-04-01 2010-04-01 false Natural gas produced... DETERMINATION PROCEDURES Requirements for Filings With Jurisdictional Agencies § 270.303 Natural gas produced from Devonian shale. A person seeking a determination that natural gas is produced from Devonian shale...

18 CFR 270.303 - Natural gas produced from Devonian shale.

Code of Federal Regulations, 2011 CFR

2011-04-01

... 18 Conservation of Power and Water Resources 1 2011-04-01 2011-04-01 false Natural gas produced... DETERMINATION PROCEDURES Requirements for Filings With Jurisdictional Agencies § 270.303 Natural gas produced from Devonian shale. A person seeking a determination that natural gas is produced from Devonian shale...

Sedimentology of gas-bearing Devonian shales of the Appalachian Basin

NASA Astrophysics Data System (ADS)

Potter, P. E.; Maynard, J. B.; Pryor, W. A.

1981-01-01

Sedimentology of the Devonian shales and its relationship to gas, oil, and uranium are reported. Information about the gas bearing Devonian shales of the Appalachian Basin is organized in the following sections: paleogeography and basin analysis; lithology and internal stratigraphy; paleontology; mineralogy, petrology, and chemistry; and gas oil, and uranium.

Eastern Devonian shales: Organic geochemical studies, past and present

USGS Publications Warehouse

Breger, I.A.; Hatcher, P.G.; Romankiw, L.A.; Miknis, F.P.

1983-01-01

The Eastern Devonian shales are represented by a sequence of sediments extending from New York state, south to the northern regions of Georgia and Alabama, and west into Ohio and to the Michigan and Ilinois Basins. Correlatives are known in Texas. The shale is regionally known by a number of names: Chattanooga, Dunkirk, Rhinestreet, Huron, Antrim, Ohio, Woodford, etc. These shales, other than those in Texas, have elicited much interest because they have been a source of unassociated natural gas. It is of particular interest, however, that most of these shales have no associated crude oil, in spite of the fact that they have some of the characteristics normally attributed to source beds. This paper addresses some of the organic geochemical aspects of the kerogen in these shales, in relation to their oil generating potential. Past organic geochemical studies on Eastern Devonian shales will be reviewed. Recent solid state 13C NMR studies on the nature of the organic matter in Eastern Devonian shales show that Eastern Devonian shales contain a larger fraction of aromatic carbon in their chemical composition. Thus, despite their high organic matter contents, their potential as a petroleum source rock is low, because the kerogen in these shales is of a "coaly" nature and hence more prone to producing natural gas.

Eastern Devonian shales: Organic geochemical studies

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

Berger, I.A.; Hatchner, P.G.; Miknis, F.P.

The Eastern Devonian shales are represented by a sequence of sediments extending from New York state, south to the northern regions of Georgia and Alabama, and west into Ohio and to the Michigan and Illinois Basins. Correlatives are known in Texas. The shale is regionally known by a number of names: Chattanooga, Dunkirk, Rhinestreet, Huron, Antrim, Ohio, Woodford, etc. These shales, other than those in Texas, have elicited much interest because they have been a source of unassociated natural gas. It is of particular interest, however, that most of these shales have no associated crude oil, in spite of themore » fact that they have some of the characteristics normally attributed to source beds. This paper addresses some of the organic geochemical aspects of the kerogen in these shales, in relation to their oil generating potential. Past organic geochemical studies on Eastern Devonian shales are reviewed. Recent solid state /sup 13/C NMR studies on the nature of the organic matter in Eastern Devonian shales show that Eastern Devonian shales contain a larger fraction of aromatic carbon in their chemical composition. Thus, despite their high organic matter contents, their potential as a petroleum source rock is low, because the kerogen in these shales is of a ''coaly'' nature and hence more prone to producing natural gas.« less

Discrete Fracture Network Characterization of Fractured Shale Reservoirs with Implications to Hydraulic Fracturing Optimization

NASA Astrophysics Data System (ADS)

Jin, G.

2016-12-01

Shales are important petroleum source rocks and reservoir seals. Recent developments in hydraulic fracturing technology have facilitated high gas production rates from shale and have had a strong impact on the U.S. gas supply and markets. Modeling of effective permeability for fractured shale reservoirs has been challenging because the presence of a fracture network significantly alters the reservoir hydrologic properties. Due to the frequent occurrence of fracture networks, it is of vital importance to characterize fracture networks and to investigate how these networks can be used to optimize the hydraulic fracturing. We have conducted basic research on 3-D fracture permeability characterization and compartmentization analyses for fractured shale formations, which takes the advantages of the discrete fracture networks (DFN). The DFN modeling is a stochastic modeling approach using the probabilistic density functions of fractures. Three common scenarios of DFN models have been studied for fracture permeability mapping using our previously proposed techniques. In DFN models with moderately to highly concentrated fractures, there exists a representative element volume (REV) for fracture permeability characterization, which indicates that the fractured reservoirs can be treated as anisotropic homogeneous media. Hydraulic fracturing will be most effective if the orientation of the hydraulic fracture is perpendicular to the mean direction of the fractures. A DFN model with randomized fracture orientations, on the other hand, lacks an REV for fracture characterization. Therefore, a fracture permeability tensor has to be computed from each element. Modeling of fracture interconnectivity indicates that there exists no preferred direction for hydraulic fracturing to be most effective oweing to the interconnected pathways of the fracture network. 3-D fracture permeability mapping has been applied to the Devonian Chattanooga Shale in Alabama and the results suggest that an REV exist for fluid flow and transport modeling at element sizes larger than 200 m. Fracture pathway analysis indicates that hydraulic fracturing can be equally effective for hydrocarbon fluid/gas exploration as long as its orientation is not aligned with that of the regional system fractures.

Assessment of Appalachian basin oil and gas resources: Devonian gas shales of the Devonian Shale-Middle and Upper Paleozoic Total Petroleum System: Chapter G.9 in Coal and petroleum resources in the Appalachian basin: distribution, geologic framework, and geochemical character

USGS Publications Warehouse

Milici, Robert C.; Swezey, Christopher S.; Ruppert, Leslie F.; Ryder, Robert T.

2014-01-01

This report presents the results of a U.S. Geological Survey (USGS) assessment of the technically recoverable undiscovered natural gas resources in Devonian shale in the Appalachian Basin Petroleum Province of the eastern United States. These results are part of the USGS assessment in 2002 of the technically recoverable undiscovered oil and gas resources of the province. This report does not use the results of a 2011 USGS assessment of the Devonian Marcellus Shale because the area considered in the 2011 assessment is much greater than the area of the Marcellus Shale described in this report. The USGS assessment in 2002 was based on the identification of six total petroleum systems, which include strata that range in age from Cambrian to Pennsylvanian. The Devonian gas shales described in this report are within the Devonian Shale-Middle and Upper Paleozoic Total Petroleum System, which extends generally from New York to Tennessee. This total petroleum system is divided into ten assessment units (plays), four of which are classified as conventional and six as continuous. The Devonian shales described in this report make up four of these continuous assessment units. The assessment results are reported as fully risked fractiles (F95, F50, F5, and the mean); the fractiles indicate the probability of recovery of the assessment amount. The products reported are oil, gas, and natural gas liquids. The mean estimates for technically recoverable undiscovered hydrocarbons in the four gas shale assessment units are 12,195.53 billion cubic feet (12.20 trillion cubic feet) of gas and 158.91 million barrels of natural gas liquids

The Devonian Marcellus Shale and Millboro Shale

USGS Publications Warehouse

Soeder, Daniel J.; Enomoto, Catherine B.; Chermak, John A.

2014-01-01

The recent development of unconventional oil and natural gas resources in the United States builds upon many decades of research, which included resource assessment and the development of well completion and extraction technology. The Eastern Gas Shales Project, funded by the U.S. Department of Energy in the 1980s, investigated the gas potential of organic-rich, Devonian black shales in the Appalachian, Michigan, and Illinois basins. One of these eastern shales is the Middle Devonian Marcellus Shale, which has been extensively developed for natural gas and natural gas liquids since 2007. The Marcellus is one of the basal units in a thick Devonian shale sedimentary sequence in the Appalachian basin. The Marcellus rests on the Onondaga Limestone throughout most of the basin, or on the time-equivalent Needmore Shale in the southeastern parts of the basin. Another basal unit, the Huntersville Chert, underlies the Marcellus in the southern part of the basin. The Devonian section is compressed to the south, and the Marcellus Shale, along with several overlying units, grades into the age-equivalent Millboro Shale in Virginia. The Marcellus-Millboro interval is far from a uniform slab of black rock. This field trip will examine a number of natural and engineered exposures in the vicinity of the West Virginia–Virginia state line, where participants will have the opportunity to view a variety of sedimentary facies within the shale itself, sedimentary structures, tectonic structures, fossils, overlying and underlying formations, volcaniclastic ash beds, and to view a basaltic intrusion.

Fractographic logging for determination of pre-core and core-induced fractures: Nicholas Combs No. 7239 well, Hazard, Kentucky

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

Kulander, B.R.; Dean, S.L.; Barton, C.C.

1977-01-01

Methods results, and conclusions formulated during a prototype fractographic logging study of seventy-five feet of oriented Devonian shale core are summarized. The core analyzed is from the Nicholas Combs No. 7239 well located twelve miles due north of Hazard, Kentucky. The seventy-five foot core length was taken from a cored section lying between 2369.0 feet (subsea) and 2708.0 feet (subsea). Total core length is 339.0 feet. The core was extracted from the upper Devonian Ohio and Olentangy shale formations. Results indicate that there are few tectonic (pre-core) fractures within the studied core section. The region may nevertheless be cut atmore » core sample depth by well-defined vertical or inclined tectonic fractures that the vertically drilled test core didn't intersect. This is likely since surface Plateau systematic fractures in other Plateau areas are vertical to sub-vertical and seldom have a frequency of less than one major fracture per foot. The remarkable directional preference of set three fractures about strikes of N 40/sup 0/ E, N 10/sup 0/ W, N 45/sup 0/ W, suggests some incipient pre-core rock anisotropy or stored directional strain energy. If this situation exists, the anisotropy strike change or stored strain variance from N 40/sup 0/ E to N 45/sup 0/ W downcore remains an unanswered question. Tectonic features, indicating local and/or regional movement plans, are present on and within the tectonichorizontal fracture set one. Slickensides had a preferred orientation within several core levels, and fibrous-nonfibrous calcite serves as fracture fillings.« less

Geology of the Devonian black shales of the Appalachian basin

USGS Publications Warehouse

Roen, J.B.

1983-01-01

Black shales of Devonian age in the Appalachian basin are a unique rock sequence. The high content of organic matter, which imparts the characteristic lithology, has for years attracted considerable interest in the shales as a possible source of energy. Concurrent with periodic and varied economic exploitations of the black shales are geologic studies. The recent energy shortage prompted the U.S. Department of Energy through the Eastern Gas Shales Project of the Morgantown Energy Technology Center to underwrite a research program to determine the geologic, geochemical, and structural characteristics of the Devonian black shales in order to enhance the recovery of gas from the shales. Geologic studies produced a regional stratigraphic network that correlates the 15-foot sequence in Tennessee with 3,000 feet of interbedded black and gray shales in central New York. The classic Devonian black-shale sequence in New York has been correlated with the Ohio Shale of Ohio and Kentucky and the Chattanooga Shale of Tennessee and southwestern Virginia. Biostratigraphic and lithostratigraphic markers in conjunction with gamma-ray logs facilitated long range correlations within the Appalachian basin and provided a basis for correlations with the black shales of the Illinois and Michigan basins. Areal distribution of selected shale units along with paleocurrent studies, clay mineralogy, and geochemistry suggests variations in the sediment source and transport directions. Current structures, faunal evidence, lithologic variations, and geochemical studies provide evidence to support interpretation of depositional environments. In addition, organic geochemical data combined with stratigraphic and structural characteristics of the shale within the basin allow an evaluation of the resource potential of natural gas in the Devonian shale sequence.

Multiple fracturing experiments: propellant and borehole considerations

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

Cuderman, J F

1982-01-01

The technology for multiple fracturing of a wellbore, using progressively burning propellants, is being developed to enhance natural gas recovery. Multiple fracturing appears especially attractive for stimulating naturally fractured reservoirs such as Devonian shales where it is expected to effectively intersect existing fractures and connect them to a wellbore. Previous experiments and modeling efforts defined pressure risetimes required for multiple fracturing as a function of borehole diameter, but identified only a weak dependence on peak pressure attained. Typically, from four to eight equally spaced major fractures occur as a function of pressure risetime and in situ stress orientation. The presentmore » experiments address propellant and rock response considerations required to achieve the desired pressure risetimes for reliable multiple fracturing.« less

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).

Assessment of undiscovered oil and gas resources of the Devonian Marcellus Shale of the Appalachian Basin Province

USGS Publications Warehouse

Coleman, James L.; Milici, Robert C.; Cook, Troy A.; Charpentier, Ronald R.; Kirshbaum, Mark; Klett, Timothy R.; Pollastro, Richard M.; Schenk, Christopher J.

2011-01-01

Using a geology-based assessment methodology, the U.S. Geological Survey (USGS) estimated a mean undiscovered natural gas resource of 84,198 billion cubic feet and a mean undiscovered natural gas liquids resource of 3,379 million barrels in the Devonian Marcellus Shale within the Appalachian Basin Province. All this resource occurs in continuous accumulations. In 2011, the USGS completed an assessment of the undiscovered oil and gas potential of the Devonian Marcellus Shale within the Appalachian Basin Province of the eastern United States. The Appalachian Basin Province includes parts of Alabama, Georgia, Kentucky, Maryland, New York, Ohio, Pennsylvania, Tennessee, Virginia, and West Virginia. The assessment of the Marcellus Shale is based on the geologic elements of this formation's total petroleum system (TPS) as recognized in the characteristics of the TPS as a petroleum source rock (source rock richness, thermal maturation, petroleum generation, and migration) as well as a reservoir rock (stratigraphic position and content and petrophysical properties). Together, these components confirm the Marcellus Shale as a continuous petroleum accumulation. Using the geologic framework, the USGS defined one TPS and three assessment units (AUs) within this TPS and quantitatively estimated the undiscovered oil and gas resources within the three AUs. For the purposes of this assessment, the Marcellus Shale is considered to be that Middle Devonian interval that consists primarily of shale and lesser amounts of bentonite, limestone, and siltstone occurring between the underlying Middle Devonian Onondaga Limestone (or its stratigraphic equivalents, the Needmore Shale and Huntersville Chert) and the overlying Middle Devonian Mahantango Formation (or its stratigraphic equivalents, the upper Millboro Shale and middle Hamilton Group).

Subsurface stratigraphy of upper Devonian clastics in southern West Virginia

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

Neal, D.W.; Patchen, D.G.

Studies of upper Devonian shales and siltstones in southern West Virginia have resulted in a refinement of the stratigraphic framework used in characterizing the gas-producing Devonian shales. Gamma-ray log correlation around the periphery of the Appalachian Basin has extended the usage of New York stratigraphic nomenclature for the interval between the base of the Dunkirk shale and the top of the Tully limestone to southern West Virginia. Equivalents of the Dunkirk shale and younger rocks of New York are recognized in southwestern West Virginia and are named according to Ohio usage. Gas production is primarily from the basal black shalemore » member of the Ohio shale. Gas shows from older black shale units (Rhinestreet and Marcellus shales) are recorded from wells east of the major producing trend. Provided suitable stimulation techniques can be developed, these older and deeper black shales may prove to be another potential gas resource.« less

The carpenter fork bed, a new - and older - Black-shale unit at the base of the New Albany shale in central Kentucky: Characterization and significance

USGS Publications Warehouse

Barnett, S.F.; Ettensohn, F.R.; Norby, R.D.

1996-01-01

Black shales previously interpreted to be Late Devonian cave-fill or slide deposits are shown to be much older Middle Devonian black shales only preserved locally in Middle Devonian grabens and structural lows in central Kentucky. This newly recognized - and older -black-shale unit occurs at the base of the New Albany Shale and is named the Carpenter Fork Bed of the Portwood Member of the New Albany Shale after its only known exposure on Carpenter Fork in Boyle County, central Kentucky; two other occurrences are known from core holes in east-central Kentucky. Based on stratigraphic position and conodont biostratigraphy, the unit is Middle Devonian (Givetian: probably Middle to Upper P. varcus Zone) in age and occurs at a position represented by an unconformity atop the Middle Devonian Boyle Dolostone and its equivalents elsewhere on the outcrop belt. Based on its presence as isolated clasts in the overlying Duffin Bed of the Portwood Member, the former distribution of the unit was probably much more widespread - perhaps occurring throughout western parts of the Rome trough. Carpenter Fork black shales apparently represent an episode of subsidence or sea-level rise coincident with inception of the third tectophase of the Acadian orogeny. Deposition, however, was soon interrupted by reactivation of several fault zones in central Kentucky, perhaps in response to bulge migration accompanying start of the tectophase. As a result, much of central Kentucky was uplifted and tilted, and the Carpenter Fork Bed was largely eroded from the top of the Boyle, except in a few structural lows like the Carpenter Fork graben where a nearly complete record of Middle to early Late Devonian deposition is preserved.

Geology of the Devonian black shales of the Appalachian Basin

USGS Publications Warehouse

Roen, J.B.

1984-01-01

Black shales of Devonian age in the Appalachian Basin are a unique rock sequence. The high content of organic matter, which imparts the characteristic lithology, has for years attracted considerable interest in the shales as a possible source of energy. The recent energy shortage prompted the U.S. Department of Energy through the Eastern Gas Shales Project of the Morgantown Energy Technology Center to underwrite a research program to determine the geologic, geochemical, and structural characteristics of the Devonian black shales in order to enhance the recovery of gas from the shales. Geologic studies by Federal and State agencies and academic institutions produced a regional stratigraphic network that correlates the 15 ft black shale sequence in Tennessee with 3000 ft of interbedded black and gray shales in central New York. These studies correlate the classic Devonian black shale sequence in New York with the Ohio Shale of Ohio and Kentucky and the Chattanooga Shale of Tennessee and southwestern Virginia. Biostratigraphic and lithostratigraphic markers in conjunction with gamma-ray logs facilitated long-range correlations within the Appalachian Basin. Basinwide correlations, including the subsurface rocks, provided a basis for determining the areal distribution and thickness of the important black shale units. The organic carbon content of the dark shales generally increases from east to west across the basin and is sufficient to qualify as a hydrocarbon source rock. Significant structural features that involve the black shale and their hydrocarbon potential are the Rome trough, Kentucky River and Irvine-Paint Creek fault zone, and regional decollements and ramp zones. ?? 1984.

Study of hydrocarbon production from the Devonian shale in Letcher, Knott, Floyd, Martin, and Pike Counties, eastern Kentucky annual technical report, July 1, 1984-June 30, 1985

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

Frankie, W.T.

The Kentucky Geological Survey (KGS) at the University of Kentucky is conducting a 2-year research project funded by the Gas Research Institute (GRI) to study hydrocarbon production from the Devonian shale in eastern Kentucky. Objectives are to develop an understanding of relationships between stratigraphy and hydrocarbon production, create a data base, and prepare geologic reports for each county in the study area. Data were compiled from the KGS, GRI Eastern Gas Data System (EGDS), U. S. Department of Energy (DOE), and industry. Research for Letcher County was completed and 270 Devonian wells were entered into the KGS computer data base.more » Devonian black-shale units were correlated using gamma-ray logs. Structure and isopach maps, and stratigraphic cross sections have been constructed. An isopotential map defining areas of equal initial gas production has been prepared. Statistics for Letcher County have been run on the data base using Datatrieve software package. Statistical analyses focused on different types of formation treatments and the resulting production. Temperature logs were used to detect gas-producing intervals within the Mississippian-Devonian black-shale sequence. The results of the research provide the petroleum industry with a valuable tool for gas exploration in the Devonian shales.« less

Thermal maturity of northern Appalachian Basin Devonian shales: Insights from sterane and terpane biomarkers

USGS Publications Warehouse

Hackley, Paul C.; Ryder, Robert T.; Trippi, Michael H.; Alimi, Hossein

2013-01-01

To better estimate thermal maturity of Devonian shales in the northern Appalachian Basin, eleven samples of Marcellus and Huron Shale were characterized via multiple analytical techniques. Vitrinite reflectance, Rock–Eval pyrolysis, gas chromatography (GC) of whole rock extracts, and GC–mass spectrometry (GCMS) of extract saturate fractions were evaluated on three transects that lie across previously documented regional thermal maturity isolines. Results from vitrinite reflectance suggest that most samples are immature with respect to hydrocarbon generation. However, bulk geochemical data and sterane and terpane biomarker ratios from GCMS suggest that almost all samples are in the oil window. This observation is consistent with the presence of thermogenic gas in the study area and higher vitrinite reflectance values recorded from overlying Pennsylvanian coals. These results suggest that vitrinite reflectance is a poor predictor of thermal maturity in early mature areas of Devonian shale, perhaps because reported measurements often include determinations of solid bitumen reflectance. Vitrinite reflectance interpretations in areas of early mature Devonian shale should be supplanted by evaluation of thermal maturity information from biomarker ratios and bulk geochemical data.

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.

Assessment of undiscovered continuous gas resources in Upper Devonian Shales of the Appalachian Basin Province, 2017

USGS Publications Warehouse

Enomoto, Catherine B.; Trippi, Michael H.; Higley, Debra K.; Rouse, William A.; Dulong, Frank T.; Klett, Timothy R.; Mercier, Tracey J.; Brownfield, Michael E.; Leathers-Miller, Heidi M.; Finn, Thomas M.; Marra, Kristen R.; Le, Phuong A.; Woodall, Cheryl A.; Schenk, Christopher J.

2018-04-19

Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean undiscovered, technically recoverable continuous resources of 10.7 trillion cubic feet of natural gas in Upper Devonian shales of the Appalachian Basin Province.

Devonian-Carboniferous boundary succession in Eastern Taurides, Turkey

NASA Astrophysics Data System (ADS)

Atakul-Özdemir, Ayşe; Altıner, Demir; Özkan-Altıner, Sevinç

2015-04-01

The succession covering the Devonian-Carboniferous boundary in Eastern Taurides comprises mainly limestones, shales and siltstones. The studied section starts at the base with bioturbated limestones alternating with shales and is followed upwards by platy limestones, and continues with the alternations of bioturbated and platy limestones. Towards the upper part of the succession the alternations of limestone, shales and siltstones reappear again and the top of the section is capped by quartz arenitic sandstone. The studied section spanning the Uppermost Devonian-Lower Carboniferous interval yields a not very abundant, but quite important assemblage of conodont taxa including species of Bispathodus, Polygnathus, Palmatolepis, Spathognathodus and Vogelgnathus. The uppermost Devonian part of the succession is characterized by the presence of Bispathodus costatus, Bispathodus aculeatus aculeatus, Polygnathus communis communis, Palmatolepis gracilis gracilis and Spathognathodus sp.. The Lower Carboniferous in the studied section is represented by the appearance of Polygnathus inornatus and Polygnathus communis communis. Based on the recovered conodont assemblages, Devonian-Carboniferous boundary in Eastern Turides has been determined by the appearance and disappearance of major conodont species.

Geochemical constraints on the origin and volume of gas in the New Albany Shale (Devonian-Mississippian), eastern Illinois Basin

USGS Publications Warehouse

Strapoc, D.; Mastalerz, Maria; Schimmelmann, A.; Drobniak, A.; Hasenmueller, N.R.

2010-01-01

This study involved analyses of kerogen petrography, gas desorption, geochemistry, microporosity, and mesoporosity of the New Albany Shale (Devonian-Mississippian) in the eastern part of the Illinois Basin. Specifically, detailed core analysis from two locations, one in Owen County, Indiana, and one in Pike County, Indiana, has been conducted. The gas content in the locations studied was primarily dependent on total organic carbon content and the micropore volume of the shales. Gas origin was assessed using stable isotope geochemistry. Measured and modeled vitrinite reflectance values were compared. Depth of burial and formation water salinity dictated different dominant origins of the gas in place in the two locations studied in detail. The shallower Owen County location (415-433 m [1362-1421 ft] deep) contained significant additions of microbial methane, whereas the Pike County location (832-860 m [2730-2822 ft] deep) was characterized exclusively by thermogenic gas. Despite differences in the gas origin, the total gas in both locations was similar, reaching up to 2.1 cm3/g (66 scf/ton). Lower thermogenic gas content in the shallower location (lower maturity and higher loss of gas related to uplift and leakage via relaxed fractures) was compensated for by the additional generation of microbial methane, which was stimulated by an influx of glacial melt water, inducing brine dilution and microbial inoculation. The characteristics of the shale of the Maquoketa Group (Ordovician) in the Pike County location are briefly discussed to provide a comparison to the New Albany Shale. Copyright ??2010. The American Association of Petroleum Geologists. All rights reserved.

18 CFR 270.306 - Devonian shale wells in Michigan.

Code of Federal Regulations, 2010 CFR

2010-04-01

... 18 Conservation of Power and Water Resources 1 2010-04-01 2010-04-01 false Devonian shale wells in Michigan. 270.306 Section 270.306 Conservation of Power and Water Resources FEDERAL ENERGY REGULATORY...) Attesting the applicant has no knowledge of any information not described in the application which is...

Upper Paleozoic Marine Shale Characteristics and Exploration Prospects in the Northwestern Guizhong Depression, South China

NASA Astrophysics Data System (ADS)

Zhu, Zhenhong; Yao, Genshun; Lou, Zhanghua; Jin, Aimin; Zhu, Rong; Jin, Chong; Chen, Chao

2018-05-01

Multiple sets of organic-rich shales developed in the Upper Paleozoic of the northwestern Guizhong Depression in South China. However, the exploration of these shales is presently at a relatively immature stage. The Upper Paleozoic shales in the northwestern Guizhong Depression, including the Middle Devonian Luofu shale, the Nabiao shale, and the Lower Carboniferous Yanguan shale, were investigated in this study. Mineral composition analysis, organic matter analysis (including total organic carbon (TOC) content, maceral of kerogen and the vitrinite reflection (Ro)), pore characteristic analysis (including porosity and permeability, pore type identification by SEM, and pore size distribution by nitrogen sorption), methane isothermal sorption test were conducted, and the distribution and thickness of the shales were determined, Then the characteristics of the two target shales were illustrated and compared. The results show that the Upper Paleozoic shales have favorable organic matter conditions (mainly moderate to high TOC content, type I and II1 kerogen and high to over maturity), good fracability potential (brittleness index (BI) > 40%), multiple pore types, stable distribution and effective thickness, and good methane sorption capacity. Therefore, the Upper Paleozoic shales in the northern Guizhong Depression have good shale gas potential and exploration prospects. Moreover, the average TOC content, average BI, thickness of the organic-rich shale (TOC > 2.0 wt%) and the shale gas resources of the Middle Devonian shales are better than those of the Lower Carboniferous shale. The Middle Devonian shales have better shale gas potential and exploration prospects than the Lower Carboniferous shales.

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

Potter, P.E.; Maynard, J.B.; Pryor, W.A.

Studies of shales in the Appalachian area are reported (mainly in the form of abstracts of reports or manuscripts). They discuss the geology, lithology, stratigraphy, radioactivity, organic matter, the isotopic abundance of carbon and sulfur isotopes, etc. of shales in this area with maps. One report discusses Devonian paliocurrents in the central and northern Appalachian basin. Another discusses sedimentology of the Brallier Formation. The stratigraphy of upper Devonian shales along the southern shore of Lake Erie was also studied. (LTN)

Geochemical and strontium isotope characterization of produced waters from Marcellus Shale natural gas extraction.

PubMed

Chapman, Elizabeth C; Capo, Rosemary C; Stewart, Brian W; Kirby, Carl S; Hammack, Richard W; Schroeder, Karl T; Edenborn, Harry M

2012-03-20

Extraction of natural gas by hydraulic fracturing of the Middle Devonian Marcellus Shale, a major gas-bearing unit in the Appalachian Basin, results in significant quantities of produced water containing high total dissolved solids (TDS). We carried out a strontium (Sr) isotope investigation to determine the utility of Sr isotopes in identifying and quantifying the interaction of Marcellus Formation produced waters with other waters in the Appalachian Basin in the event of an accidental release, and to provide information about the source of the dissolved solids. Strontium isotopic ratios of Marcellus produced waters collected over a geographic range of ~375 km from southwestern to northeastern Pennsylvania define a relatively narrow set of values (ε(Sr)(SW) = +13.8 to +41.6, where ε(Sr) (SW) is the deviation of the (87)Sr/(86)Sr ratio from that of seawater in parts per 10(4)); this isotopic range falls above that of Middle Devonian seawater, and is distinct from most western Pennsylvania acid mine drainage and Upper Devonian Venango Group oil and gas brines. The uniformity of the isotope ratios suggests a basin-wide source of dissolved solids with a component that is more radiogenic than seawater. Mixing models indicate that Sr isotope ratios can be used to sensitively differentiate between Marcellus Formation produced water and other potential sources of TDS into ground or surface waters.

The effect of long-term regional pumping on hydrochemistry and dissolved gas content in an undeveloped shale-gas-bearing aquifer in southwestern Ontario, Canada

NASA Astrophysics Data System (ADS)

Hamilton, Stewart M.; Grasby, Stephen E.; McIntosh, Jennifer C.; Osborn, Stephen G.

2015-02-01

Baseline groundwater geochemical mapping of inorganic and isotopic parameters across 44,000 km2 of southwestern Ontario (Canada) has delineated a discreet zone of natural gas in the bedrock aquifer coincident with an 8,000-km2 exposure of Middle Devonian shale. This study describes the ambient geochemical conditions in these shales in the context of other strata, including Ordovician shales, and discusses shale-related natural and anthropogenic processes contributing to hydrogeochemical conditions in the aquifer. The three Devonian shales—the Kettle Point Formation (Antrim equivalent), Hamilton Group and Marcellus Formation—have higher DOC, DIC, HCO3, CO2(aq), pH and iodide, and much higher CH4(aq). The two Ordovician shales—the Queenston and Georgian-Bay/Blue Mountain Formations—are higher in Ca, Mg, SO4 and H2S. In the Devonian shale region, isotopic zones of Pleistocene-aged groundwater have halved in size since first identified in the 1980s; potentiometric data implicate regional groundwater extraction in the shrinkage. Isotopically younger waters invading the aquifer show rapid increases in CH4(aq), pH and iodide with depth and rapid decrease in oxidized carbon species including CO2, HCO3 and DIC, suggesting contemporary methanogenesis. Pumping in the Devonian shale contact aquifer may stimulate methanogenesis by lowering TDS, removing products and replacing reactants, including bicarbonate, derived from overlying glacial sedimentary aquifers.

Geochemical Evidence for Possible Natural Migration of Marcellus Formation Brine to Shallow Aquifers in Pennsylvania

NASA Astrophysics Data System (ADS)

Warner, N. R.; Darrah, T. H.; Jackson, R. B.; Osborn, S.; Down, A.; Vengosh, A.

2012-12-01

The acceleration in production of natural gas from shale formations through horizontal drilling and hydraulic fracturing has altered the landscape of domestic energy production in the USA. Yet shale gas exploration has generated an increased awareness of risks to drinking water quality amid concerns for the possible migration of stray gas or hydraulic fracturing fluid and/or flowback brine to shallow drinking water aquifers. The degree to which shallow drinking water is at risk from hydraulic fracturing could depend upon the hydraulic connectivity between the shale gas formations and the surface. In this study, we analyzed the geochemistry of over 400 water samples located across six counties of northeastern Pennsylvania in the three principle aquifers, two Upper Devonian Age bedrock aquifers (Catskill and Lock Haven) and one Quaternary Age (Alluvium) that overlie the Marcellus Formation. Based on a detailed analysis of major (Br, Cl, Na, Mg, Ba, and Sr) and trace (Li) element geochemistry, coupled with utilization of a specific spectrum of isotopic tracers (87Sr/86Sr, 228Ra/ 226Ra, 2H/H, 18O/16O), we identify a salinized (Cl> 20 mg/L) shallow groundwater type which suggests conservative mixing relationships between fresh shallow groundwater and an underlying brine. Identification of the brine source is complicated as many of the brines in the northern Appalachian Basin likely share a common origin as the expelled remnants of the formation of the Silurian Salina evaporate deposits. To determine the ultimate source of the diluted brine we compared the observed geochemistry to over 80 brines produced from northern Appalachian Basin formations. The shallow salinized groundwater most closely resembles diluted produced water from the Middle Devonian Marcellus Formation. The 18O/16O and 2H/H of the salinized groundwater indicate that the brine is likely diluted with post-glacial (<10,000 ybp) meteoric water. Combined, these data indicate that hydraulic connections allowed cross formational migration of brine from deeper formations (1-2 kilometers below ground surface) and subsequent dilution. The occurrence of the saline water does not appear to be correlated with the location of shale-gas wells. Also, salinized groundwater with similar major element chemistry was reported prior to the most recent shale-gas development in the region. The source of the salinized water is likely not the recent drilling and hydraulic fracturing; instead brine migrated into the shallow aquifers and was recently diluted through natural pathways and processes. However, the presence of natural hydraulic connections to deeper formations suggests specific structural and hydrodynamic regimes in northeastern Pennsylvania where shallow drinking water resources are at greater risk of contamination, particularly with fugitive gases, during drilling and hydraulic fracturing of shale gas. The severity of the risk could depend upon the presence of pathways that allow the migration of fluids into the shallow aquifers on human time scales.

Late Devonian shale deposition based on known and predicted occurrence of Foerstia in Michigan basin

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

Matthews, R.D.

The fossil Foerstia (Protosalvinia) marks a time zone within Late Devonian shale sequences in the eastern US. Its recent discovery in Michigan has led to more accurate correlations among the three large eastern basins. Subdivisions of the Devonian-Mississippi shale sequence in Michigan based on gamma-ray correlations reveal an idealized black shale geometry common to other eastern black shales, such as the Sunbury of Michigan and Ohio, the Clegg Creek of Indiana, the Dunkirk of Pennsylvania and New York, and the lower Huron of Ohio and West Virginia. In Michigan, Foerstia occurs at a stratigraphic position postulated to mark a majormore » change in depositional conditions and source areas. This position strengthens the physical and paleontologic evidence for a formal division of the Antrim. Isopach maps of the shale sequence above and below Foerstia show a relatively uniform and continuous black shale deposit (units 1A, 1B, and 1C) below Foerstia. This deposit is unlike the wedge of sediment found above Foerstia, which is composed of a western facies (Ellsworth) and an eastern facies (upper Antrim) that should be combined in a single stratigraphic unit conforming to Forgotson's concept of a format.« less

Assessment of Factors Influencing Effective CO 2 Storage Capacity and Injectivity in Eastern Gas Shales

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

Godec, Michael

Building upon advances in technology, production of natural gas from organic-rich shales is rapidly developing as a major hydrocarbon supply option in North America and around the world. The same technology advances that have facilitated this revolution - dense well spacing, horizontal drilling, and hydraulic fracturing - may help to facilitate enhanced gas recovery (EGR) and carbon dioxide (CO 2) storage in these formations. The potential storage of CO 2 in shales is attracting increasing interest, especially in Appalachian Basin states that have extensive shale deposits, but limited CO 2 storage capacity in conventional reservoirs. The goal of this cooperativemore » research project was to build upon previous and on-going work to assess key factors that could influence effective EGR, CO 2 storage capacity, and injectivity in selected Eastern gas shales, including the Devonian Marcellus Shale, the Devonian Ohio Shale, the Ordovician Utica and Point Pleasant shale and equivalent formations, and the late Devonian-age Antrim Shale. The project had the following objectives: (1) Analyze and synthesize geologic information and reservoir data through collaboration with selected State geological surveys, universities, and oil and gas operators; (2) improve reservoir models to perform reservoir simulations to better understand the shale characteristics that impact EGR, storage capacity and CO 2 injectivity in the targeted shales; (3) Analyze results of a targeted, highly monitored, small-scale CO 2 injection test and incorporate into ongoing characterization and simulation work; (4) Test and model a smart particle early warning concept that can potentially be used to inject water with uniquely labeled particles before the start of CO 2 injection; (5) Identify and evaluate potential constraints to economic CO 2 storage in gas shales, and propose development approaches that overcome these constraints; and (6) Complete new basin-level characterizations for the CO 2 storage capacity and injectivity potential of the targeted eastern shales. In total, these Eastern gas shales cover an area of over 116 million acres, may contain an estimated 6,000 trillion cubic feet (Tcf) of gas in place, and have a maximum theoretical storage capacity of over 600 million metric tons. Not all of this gas in-place will be recoverable, and economics will further limit how much will be economic to produce using EGR techniques with CO 2 injection. Reservoir models were developed and simulations were conducted to characterize the potential for both CO 2 storage and EGR for the target gas shale formations. Based on that, engineering costing and cash flow analyses were used to estimate economic potential based on future natural gas prices and possible financial incentives. The objective was to assume that EGR and CO 2 storage activities would commence consistent with the historical development practices. Alternative CO 2 injection/EGR scenarios were considered and compared to well production without CO 2 injection. These simulations were conducted for specific, defined model areas in each shale gas play. The resulting outputs were estimated recovery per typical well (per 80 acres), and the estimated CO 2 that would be injected and remain in the reservoir (i.e., not produced), and thus ultimately assumed to be stored. The application of this approach aggregated to the entire area of the four shale gas plays concluded that they contain nearly 1,300 Tcf of both primary production and EGR potential, of which an estimated 460 Tcf could be economic to produce with reasonable gas prices and/or modest incentives. This could facilitate the storage of nearly 50 Gt of CO 2 in the Marcellus, Utica, Antrim, and Devonian Ohio shales.« less

Evaluation of Methane Sources in Groundwater in Northeastern Pennsylvania

PubMed Central

Molofsky, Lisa J; Connor, John A; Wylie, Albert S; Wagner, Tom; Farhat, Shahla K

2013-01-01

Testing of 1701 water wells in northeastern Pennsylvania shows that methane is ubiquitous in groundwater, with higher concentrations observed in valleys vs. upland areas and in association with calcium-sodium-bicarbonate, sodium-bicarbonate, and sodium-chloride rich waters—indicating that, on a regional scale, methane concentrations are best correlated to topographic and hydrogeologic features, rather than shale-gas extraction. In addition, our assessment of isotopic and molecular analyses of hydrocarbon gases in the Dimock Township suggest that gases present in local water wells are most consistent with Middle and Upper Devonian gases sampled in the annular spaces of local gas wells, as opposed to Marcellus Production gas. Combined, these findings suggest that the methane concentrations in Susquehanna County water wells can be explained without the migration of Marcellus shale gas through fractures, an observation that has important implications for understanding the nature of risks associated with shale-gas extraction. PMID:23560830

History of gas production from Devonian shale in eastern Kentucky

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

Kemper, J.R.; Frankie, W.T.; Smath, R.A.

More than 10,500 wells that penetrate the Devonian shale have been compiled into a data base covering a 25-county area of eastern Kentucky. This area includes the Big Sandy gas field, the largest in the Appalachian basin, and marginal areas to the southwest, west, and northwest. The development of the Big Sandy gas field began in the 1920s in western Floyd County, Kentucky, and moved concentrically outward through 1970. Since 1971, the trend has been for infill and marginal drilling, and fewer companies have been involved. The resulting outline of the Big Sandy gas field covers most of Letcher, Knott,more » Floyd, Martin, and Pike Counties in Kentucky; it also extends into West Virginia. Outside the Big Sandy gas field, exploration for gas has been inconsistent, with a much higher ratio of dry holes. The results of this study, which was partially supported by the Gas Research Institute (GRI), indicate that certain geologic factors, such as fracture size and spacing, probably determine the distribution of commercial gas reserves as well as the outline of the Big Sandy gas field. Future Big Sandy infill and extension drilling will need to be based on an understanding of these factors.« less

Preliminary stratigraphic cross section showing radioactive zones in the Devonian dark shales in the eastern part of the Appalachian Basin

USGS Publications Warehouse

West, Mareta N.

1978-01-01

The U.S. Geological Survey (USGS), in a cooperative agreement with the U.S. Department of Energy (DOE), is participating in the Eastern Gas Shales Project. The purpose of the DOE project is to increase the production of natural gas from eastern United States shales in petroliferous basins through improved exploration and extraction techniques. The USGS participation includes stratigraphic studies which will contribute to the characterization and appraisal of the natural gas resources of Devonian shale in the Appalachian basin.This cross section differs from others in this series partly because many of the shales in the eastern part of the basin are less radioactive than those farther west and because in this area shales that may be gas-productive are not necessarily highly radioactive and black.

Geochemical and mineralogical sampling of the Devonian shales in the Broadtop synclinorium, Appalachian basin, in Virginia, West Virginia, Maryland, and Pennsylvania

USGS Publications Warehouse

Enomoto, Catherine B.; Coleman, James L.; Swezey, Christopher S.; Niemeyer, Patrick W.; Dulong, Frank T.

2015-01-01

The presence of conventional anticlinal gas fields in the study area that are productive from the underlying Lower Devonian Oriskany Sandstone suggests that an unconventional (or continuous) shale gas system may be in place within the Marcellus Shale in the study area. Results of this study indicate that the Marcellus Shale in the Broadtop synclinorium generally is similar in organic geochemical nature throughout its extent, and based on the sample analyses, there are no clearly identifiable high potential areas (or “sweet spots”) in the study area. This report contains analyses of 132 outcrop and well drill-cuttings samples.

Radium release mechanisms during hydraulic fracturing of Marcellus Shale

NASA Astrophysics Data System (ADS)

Sharma, M.; Landis, J. D.; Renock, D. J.

2016-12-01

Wastewater co-produced with methane from Devonian Marcellus Shale is hypersaline and enriched in Ra. Recent studies find that water injected during hydraulic fracturing can leach out significant quantities of Na, Ca, Ba and Sr from solid phases in the shale over just hours to days. Here, we show with water-rock leaching experiments that the measured 226Ra/228Ra ratios of Marcellus wastewater could also derive from rapid leaching of mineral and organic phases of the shale. Radium isotopes 226Ra (t1/2 = 1600 a) and 228Ra (t1/2 = 5.8 a) are produced through radioactive decay of 238U (t1/2 = 4.5 Ga) and 232Th (t1/2 = 14 Ga), respectively. In the absence of processes that fractionate U, Th and Ra from one another, the decay rates of each parent-daughter pair become identical over 5 half-lives of the daughter radionuclide reaching a condition of secular equilibrium. Water-rock interaction may induce pronounced deviations from secular equilibrium in the water phase, however. Such is the case during hydraulic fracturing, where Ra is soluble and mobile, and is orphaned from insoluble U and Th parents. Once 226Ra and 228Ra are mobilized no fractionation between these isotopes is expected during their transport to the surface. Thus the 226Ra/228Ra ratio in wastewater provides a fingerprint of Ra source(s). Leaching Marcellus Shale with pure water under anoxic conditions releases mainly 228Ra from clays; extraction of 228Ra from radiation damaged sites is likely the dominant contributing mechanism. Using a novel isotope dilution technique we find that 90% of the Ra released in pure water partitions back onto rock (possibly clays). In comparison, leaching with high ionic strength solutions induces the release of 226Ra from mainly organics; the breakdown of organic matter in these solutions may be the driving mechanism controlling 226Ra release in solution. Radium released by high ionic strength solutions strongly partitions into water and results in the development of leachates with high 226Ra/228Ra ratios that are comparable to those of Marcellus wastewaters. Our results suggest that hydraulic fracturing using dilute HCl solution releases Ca and Na from the shale and effects rapid Ra release from the rock. Hypersaline and radioactive wastewater is thus a consequence of active leaching of shale during hydraulic fracturing.

Evaluation of methane sources in groundwater in northeastern Pennsylvania.

PubMed

Molofsky, Lisa J; Connor, John A; Wylie, Albert S; Wagner, Tom; Farhat, Shahla K

2013-01-01

Testing of 1701 water wells in northeastern Pennsylvania shows that methane is ubiquitous in groundwater, with higher concentrations observed in valleys vs. upland areas and in association with calcium-sodium-bicarbonate, sodium-bicarbonate, and sodium-chloride rich waters--indicating that, on a regional scale, methane concentrations are best correlated to topographic and hydrogeologic features, rather than shale-gas extraction. In addition, our assessment of isotopic and molecular analyses of hydrocarbon gases in the Dimock Township suggest that gases present in local water wells are most consistent with Middle and Upper Devonian gases sampled in the annular spaces of local gas wells, as opposed to Marcellus Production gas. Combined, these findings suggest that the methane concentrations in Susquehanna County water wells can be explained without the migration of Marcellus shale gas through fractures, an observation that has important implications for understanding the nature of risks associated with shale-gas extraction. © 2013, Cabot Oil and Gas Corporation. Groundwater © 2013, National GroundWater Association.

The rise of fire: Fossil charcoal in late Devonian marine shales as an indicator of expanding terrestrial ecosystems, fire, and atmospheric change

USGS Publications Warehouse

Rimmer, Susan M.; Hawkins, Sarah J.; Scott, Andrew C.; Cressler, Walter L.

2015-01-01

Fossil charcoal provides direct evidence for fire events that, in turn, have implications for the evolution of both terrestrial ecosystems and the atmosphere. Most of the ancient charcoal record is known from terrestrial or nearshore environments and indicates the earliest occurrences of fire in the Late Silurian. However, despite the rise in available fuel through the Devonian as vascular land plants became larger and trees and forests evolved, charcoal occurrences are very sparse until the Early Mississippian where extensive charcoal suggests well-established fire systems. We present data from the latest Devonian and Early Mississippian of North America from terrestrial and marine rocks indicating that fire became more widespread and significant at this time. This increase may be a function of rising O2 levels and the occurrence of fire itself may have contributed to this rise through positive feedback. Recent atmospheric modeling suggests an O2 low during the Middle Devonian (around 17.5%), with O2 rising steadily through the Late Devonian and Early Mississippian (to 21–22%) that allowed for widespread burning for the first time. In Devonian-Mississippian marine black shales, fossil charcoal (inertinite) steadily increases up-section suggesting the rise of widespread fire systems. There is a concomitant increase in the amount of vitrinite (preserved woody and other plant tissues) that also suggests increased sources of terrestrial organic matter. Even as end Devonian glaciation was experienced, fossil charcoal continued to be a source of organic matter being introduced into the Devonian oceans. Scanning electron and reflectance microscopy of charcoal from Late Devonian terrestrial sites indicate that the fires were moderately hot (typically 500–600 °C) and burnt mainly surface vegetation dominated by herbaceous zygopterid ferns and lycopsids, rather than being produced by forest crown fires. The occurrence and relative abundance of fossil charcoal in marine black shales are significant in that these shales may provide a more continuous record of fire than is preserved in terrestrial environments. Our data support the idea that major fires are not seen in the fossil record until there is both sufficient and connected fuel and a high enough atmospheric O2 content for it to burn.

The Valley and Ridge Province of eastern Pennsylvania - stratigraphic and sedimentologic contributions and problems ( USA).

USGS Publications Warehouse

Epstein, J.B.

1986-01-01

The rocks in the area, which range from Middle Ordovician to Late Devonian in age, are more than 7620 m thick. This diversified group of sedimentary rocks was deposited in many different environments, ranging from deep sea, through neritic and tidal, to alluvial. In general, the Middle Ordovician through Lower Devonian strata are a sedimentary cycle related to the waxing and waning of Taconic tectonism. The sequence began with a greywacke-argillite suite (Martinsburg Formation) representing synorogenic basin deepening. This was followed by basin filling and progradation of a sandstone-shale clastic wedge (Shawangunk Formation and Bloomsburg Red Beds) derived from the erosion of the mountains that were uplifted during the Taconic orogeny. The sequence ended with deposition of many thin units of carbonate, sandstone, and shale on a shelf marginal to a land area of low relief. Another tectonic-sedimentary cycle, related to the Acadian orogeny, began with deposition of Middle Devonian rocks. Deep-water shales (Marcellus Shale) preceded shoaling (Mahantango Formation) and turbidite sedimentation (Trimmers Rock Formation) followed by another molasse (Catskill Formation). -from Author

Late Paleozoic SEDEX deposits in South China formed in a carbonate platform at the northern margin of Gondwana

NASA Astrophysics Data System (ADS)

Qiu, Wenhong Johnson; Zhou, Mei-Fu; Liu, Zerui Ray

2018-05-01

SEDEX sulfide deposits hosted in black shale and carbonate are common in the South China Block. The Dajiangping pyrite deposit is the largest of these deposits and is made up of stratiform orebodies hosted in black shales. Sandstone interlayered with stratiform orebodies contains detrital zircon grains with the youngest ages of 429 Ma. Pyrite from the orebodies has a Re-Os isochron age of 389 ± 62 Ma, indicative of formation of the hosting strata and syngenetic pyrite ores in the mid-late Devonian. The hosting strata is a transgression sequence in a passive margin and composed of carbonaceous limestone in the lower part and black shales in the upper part. The ore-hosting black shales have high TOC (total organic carbon), Mo, As, Pb, Zn and Cd, indicating an anoxic-euxinic deep basin origin. The high redox proxies, V/(V + Ni) > 0.6 and V/Cr > 1, and the positive correlations of TOC with Mo and V in black shales are also consistent with an anoxic depositional environment. The Dajiangping deposit is located close to the NE-trending Wuchuan-Sihui fault, which was active during the Devonian. The mid-late Devonian mineralization age and the anoxic-euxinic deep basinal condition of this deposit thus imply that the formation of this deposit was causally linked to hydrothermal fluid exhalation in an anoxic fault-bounded basin that developed in a carbonate platform of the South China Block. The regional distribution of many Devonian, stratiform, carbonaceous sediment-hosted sulfide deposits along the NE-trending fault-bounded basins in South China, similar to the Dajiangping deposit, indicates that these deposits formed at a basin developed in the passive margin setting of the South China Block during the Devonian. This environment was caused by the break-up and northward migration of the South China Block from Gandwana.

Alligator ridge district, East-Central Nevada: Carlin-type gold mineralization at shallow depths

USGS Publications Warehouse

Nutt, C.J.; Hofstra, A.H.

2003-01-01

Carlin-type deposits in the Alligator Ridge mining district are present sporadically for 40 km along the north-striking Mooney Basin fault system but are restricted to a 250-m interval of Devonian to Mississippian strata. Their age is bracketed between silicified ca. 45 Ma sedimentary rocks and unaltered 36.5 to 34 Ma volcanic rocks. The silicification is linked to the deposits by its continuity with ore-grade silicification in Devonian-Mississippian strata and by its similar ??18O values (_e1???17???) and trace element signature (As, Sb, Tl, Hg). Eocene reconstruction indicates that the deposits formed at depths of ???300 to 800 m. In comparison to most Carlin-type gold deposits, they have lower Au/Ag, Au grades, and contained Au, more abundant jasperoid, and textural evidence from deposition of an amorphous silica precursor in jasperoid. These differences most likely result from their shallow depth of formation. The peak fluid temperature (_e1???230??C) and large ??18OH2O value shift from the meteroric water line (_e1???20???) suggest that ore fluids were derived from depths of 8 km or more. A magnetotelluric survey indicates that the Mooney Basin fault system penetrates to mid-crustal depths. Deep circulation of meteoric water along the Mooney Basin fault system may have been in response to initial uplift of the East Humboldt-Ruby Mountains metamorphic core complex; convection also may have been promoted by increased heat flow associated with large magnitude extension in the core complex and regional magmatism. Ore fluids ascended along the fault system until they encountered impermeable Devonian and Mississippian shales, at which point they moved laterally through permeable strata in the Devonian Guilmette Formation, Devonian-Mississippian Pilot Shale, Mississippian Joana Limestone, and Mississippian Chainman Shale toward erosional windows where they ascended into Eocene fluvial conglomerates and lake sediments. Most gold precipitated by sulfidation of host-rock Fe and mixing with local ground water in zones of lateral fluid flow in reactive strata, such as the Lower Devonian-Mississippian Pilot Shale.

Organic metamorphism in the Lower Mississippian-Upper Devonian Bakken shales-II: Soxhlet extraction.

USGS Publications Warehouse

Price, L.C.; Ging, T.; Love, A.; Anders, D.

1986-01-01

We report on Soxhlet extraction (and subsequent related analyses) of 39 Lower Mississippian-Upper Devonian Bakken shales from the North Dakota portion of the Williston Basin, and analyses of 28 oils from the Basin. Because of the influence of primary petroleum migration, no increase in the relative or absolute concentrations of hydrocarbons or bitumen was observed at the threshold of intense hydrocarbon generation (TIHG), or during mainstage hydrocarbon generation in the Bakken shales. Thus, the maturation indices that have been so useful in delineating the TIHG and mainstage hydrocarbon generation in other studies were of no use in this study, where these events could clearly be identified only by Rock-Eval pyrolysis data. The data of this study demonstrate that primary petroleum migration is a very efficient process. Four distinctive classes of saturated hydrocarbon gas chromatograms from the Bakken shales arose from facies, maturation, and primary migration controls. As a consequence of maturation, the % of saturated hydrocarbons increased in the shale extract at the expense of decreases in the resins and asphaltenes. Measurements involving resins and asphaltenes appear to be excellent maturation indices in the Bakken shales. Two different and distinct organic facies were present in immature Bakken shales. -from Authors

Upper Devonian outcrop stratigraphy, southwestern Virginia and southeastern West Virginia

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

Dennison, J.M.; Filer, J.K.; Rossbach, T.J.

Ongoing outcrop studies are resulting in the extension of existing formal lithostratigraphic units and revision of previously less refined subdivisions of Upper Devonian strata in southwestern Virginia and southeastern West Virginia. A 425 km (263 mi) long stratigraphic cross-section has been constructed primarily from the outcrop belt along the Allegheny Structural Front, supplemented by sections from nearby outcrop belts. This NE-SW striking cross-section is oblique to the nearly due N-S depositional strike of the Upper Devonian Acadian orogenic wedge. To the southwest, the Upper Devonian section thins from 2,100 meters (6,900 feet) to 230 meters (756 feet) as progressively moremore » distal deposits are encountered. An integrated approach has been taken to establish chronostratigraphic control within the cross-section. The best time markers include particularly regressive parasequences which can be identified across facies boundaries (especially the Pound and Briery Gap Sandstones and their equivalents), volcanic ashes, and an organic-rich shale zone marking the base of a major transgression (equivalent to the base of the Huron Shale in Ohio and the Dunkirk Shale of New York). These tools provide chronostratigraphic correlation through the undivided Brallier Formation. Supplemental control includes biostratigraphic markers as well as marine dull redbeds within the Foreknobs which parallel other time lines and may represent partially reduced influxes of oxidized coastal plain sediments during minor parasequence scale regressions.« less

Physical and chemical characterization of Devonian gas shale. Quarterly status report, October 1-December 31, 1978

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

Zielinski, R.E.; Nance, S.W.

On shale samples from the WV-6 (Monongalia County, West Virginia) well, mean total gas yield was 80.4 ft/sup 3//ton. Mean hydrocarbon gas yield was 5.7 ft/sup 3//ton, 7% of total yield. Methane was the major hydrocarbon component and carbon dioxide the major nonhydrocarbon component. Oil yield was negligible. Clay minerals and organic matter were the dominant phases of the shale. Illite averages 76% of the total clay mineral content. This is detrital illite. Permeation of methane, parallel to the bedding direction for select samples from WV-5 (Mason County, West Virginia) well ranges from 10/sup -4/ to 10/sup -12/ darcys. Themore » permeability of these shales is affected by orgaic carbon content, density, particle orientation, depositional facies, etc. Preliminary studies of Devonian shale methane sorption rates suggest that these rates may be affected by shale porosity, as well as absorption and adsorption processes. An experimental system was designed to effectively simulate sorption of methane at natural reservoir conditions. The bulk density and color of select shales from Illinois, Appalachian and Michigan Basins suggest a general trend of decreasing density with increasing organic content. Black and grayish black shales have organic contents which normally exceed 1.0 wt %. Medium dark gray and gray shales generally have organic contents less than 1.0 wt %.« less

Organic content of Devonian shale in western Appalachian basin.

USGS Publications Warehouse

Schmoker, J.W.

1980-01-01

In the organic-rich facies of the Devonian shale in the western part of the Appalachian basin, the distribution of organic matter provides an indirect measure of both gas in place and the capacity of the shale to supply gas to permeable pathways.The boundary between organic-rich ('black') and organic-poor ('gray') facies is defined here as 2% organic content by volume. The thickness of organic-rich facies ranges from 200ft in central Kentucky to 1000ft along the Kentucky-West Virginia border. The average content of the organic-rich facies increases from 5% by volume on the edge to 16% in central Kentucky. The net thickness of organic matter in the organic-rich facies shows the amount of organic material in the shale, and is the most fundamental of the organic-content characterizations. Net thickness of organic matter ranges between 20 and 80ft (6.1 and 24.4m) within the mapped area.-from Author

Preliminary report on the clay mineralogy of the Upper Devonian Shales in the southern and middle Appalachian Basin

USGS Publications Warehouse

Hosterman, John W.; Loferski, Patricia J.

1978-01-01

The distribution of kaolinite in parts of the Devonian shale section is the most significant finding of this work. These shales are composed predominately of 2M illite and illitic mixed-layer clay with minor amounts of chlorite and kaolinite. Preliminary data indicate that kaolinite, the only allogenic clay mineral, is present in successively older beds of the Ohio Shale from south to north in the southern and middle parts of the Appalachian basin. This trend in the distribution of kaolinite shows a paleocurrent direction to the southwest. Three well-known methods of preparing the clay fraction for X-ray diffraction analysis were tested and evaluated. Kaolinite was not identified in two of the methods because of layering due to differing settling rates of the clay minerals. It is suggested that if one of the two settling methods of sample preparation is used, the clay film be thin enough for the X-ray beam to penetrate the entire thickness of clay.

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

Not Available

To evaluate the potential of the Devonian shale as a source of natural gas, the US Department of Energy (DOE) has undertaken the Eastern Gas Shales Project (EGSP). The EGSP is designed not only to identify the resource, but also to test improved methods of inducing permeability to facilitate gas drainage, collection, and production. The ultimate goal of this project is to increase the production of gas from the eastern shales through advanced exploration and exploitation techniques. The purpose of this report is to inform the general public and interested oil and gas operators about EGSP results as they pertainmore » to the Devonian gas shales of the Appalachian basin in Pennsylvania. Geologic data and interpretations are summarized and areas where the accumulation of gas may be large enough to justify commercial production are outlined. Because the data presented in this report are generalized and not suitable for evaluation of specific sites for exploration, the reader should consult the various reports cited for more detail and discussion of the data, concepts, and interpretations presented.« less

The hyper-enrichment of V and Zn in black shales of the Late Devonian-Early Mississippian Bakken Formation (USA)

USGS Publications Warehouse

Scott, Clinton T.; Slack, John F.; Kelley, Karen Duttweiler

2017-01-01

Black shales of the Late Devonian to Early Mississippian Bakken Formation are characterized by high concentrations of organic carbon and the hyper-enrichment (> 500 to 1000s of mg/kg) of V and Zn. Deposition of black shales resulted from shallow seafloor depths that promoted rapid development of euxinic conditions. Vanadium hyper-enrichments, which are unknown in modern environments, are likely the result of very high levels of dissolved H2S (~ 10 mM) in bottom waters or sediments. Because modern hyper-enrichments of Zn are documented only in Framvaren Fjord (Norway), it is likely that the biogeochemical trigger responsible for Zn hyper-enrichment in Framvaren Fjord was also present in the Bakken basin. With Framvaren Fjord as an analogue, we propose a causal link between the activity of phototrophic sulfide oxidizing bacteria, related to the development of photic-zone euxinia, and the hyper-enrichment of Zn in black shales of the Bakken Formation.

Zero Discharge Water Management for Horizontal Shale Gas Well Development

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

Paul Ziemkiewicz; Jennifer Hause; Raymond Lovett

Hydraulic fracturing technology (fracking), coupled with horizontal drilling, has facilitated exploitation of huge natural gas (gas) reserves in the Devonian-age Marcellus Shale Formation (Marcellus) of the Appalachian Basin. The most-efficient technique for stimulating Marcellus gas production involves hydraulic fracturing (injection of a water-based fluid and sand mixture) along a horizontal well bore to create a series of hydraulic fractures in the Marcellus. The hydraulic fractures free the shale-trapped gas, allowing it to flow to the well bore where it is conveyed to pipelines for transport and distribution. The hydraulic fracturing process has two significant effects on the local environment. First,more » water withdrawals from local sources compete with the water requirements of ecosystems, domestic and recreational users, and/or agricultural and industrial uses. Second, when the injection phase is over, 10 to 30% of the injected water returns to the surface. This water consists of flowback, which occurs between the completion of fracturing and gas production, and produced water, which occurs during gas production. Collectively referred to as returned frac water (RFW), it is highly saline with varying amounts of organic contamination. It can be disposed of, either by injection into an approved underground injection well, or treated to remove contaminants so that the water meets the requirements of either surface release or recycle use. Depending on the characteristics of the RFW and the availability of satisfactory disposal alternatives, disposal can impose serious costs to the operator. In any case, large quantities of water must be transported to and from well locations, contributing to wear and tear on local roadways that were not designed to handle the heavy loads and increased traffic. The search for a way to mitigate the situation and improve the overall efficiency of shale gas production suggested a treatment method that would allow RFW to be used as make-up water for successive fracs. RFW, however, contains dissolved salts, suspended sediment and oils that may interfere with fracking fluids and/or clog fractures. This would lead to impaired well productivity. The major technical constraints to recycling RFW involves: identification of its composition, determination of industry standards for make-up water, and development of techniques to treat RFW to acceptable levels. If large scale RFW recycling becomes feasible, the industry will realize lower transportation and disposal costs, environmental conflicts, and risks of interruption in well development schedules.« less

Paleoecology of the Devonian-Mississippian black-shale sequence in eastern Kentucky with an atlas of some common fossils

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

Barron, L.S.; Ettensohn, F.R.

The Devonian-Mississippian black-shale sequence of eastern North America is a distinctive stratigraphic interval generally characterized by low clastic influx, high organic production in the water column, anaerobic bottom conditions, and the relative absence of fossil evidence for biologic activity. The laminated black shales which constitute most of the black-shale sequence are broken by two major sequences of interbedded greenish-gray, clayey shales which contain bioturbation and pyritized micromorph invertebrates. The black shales contain abundant evidence of life from upper parts of the water column such as fish fossils, conodonts, algae and other phytoplankton; however, there is a lack of evidence ofmore » benthic life. The rare brachiopods, crinoids, and molluscs that occur in the black shales were probably epiplanktic. A significant physical distinction between the environment in which the black sediments were deposited and that in which the greenish-gray sediments were deposited was the level of dissolved oxygen. The laminated black shales point to anaerobic conditions and the bioturbated greenish-gray shales suggest dysaerobic to marginally aerobic-dysaerobic conditions. A paleoenvironmental model in which quasi-estuarine circulation compliments and enhances the effect of a stratified water column can account for both depletion of dissolved oxygen in the bottom environments and the absence of oxygen replenishment during black-shale deposition. Periods of abundant clastic influx from fluvial environments to the east probably account for the abundance of clays in the greenish-gray shale as well as the small amounts of oxygen necessary to support the depauparate, opportunistic, benthic faunas found there. These pulses of greenish-gray clastics were short-lived and eventually were replaced by anaerobic conditions and low rates of clastic sedimentation which characterized most of black-shale deposition.« less

The Eastern Gas Shales Project (EGSP) Data System: A case study in data base design, development, and application

USGS Publications Warehouse

Dyman, T.S.; Wilcox, L.A.

1983-01-01

The U.S. Geological Survey and Petroleum Information Corporation in Denver, Colorado, developed the Eastern Gas Shale Project (EGSP)Data System for the U.S. Department of Energy, Morgantown, West Virginia. Geological, geochemical, geophysical, and engineering data from Devonian shale samples from more than 5800 wells and outcrops in the Appalachian basin were edited and converted to a Petroleum Information Corporation data base. Well and sample data may be retrieved from this data system to produce (1)production-test summaries by formation and well location; (2)contoured isopach, structure, and trendsurface maps of Devonian shale units; (3)sample summary reports for samples by location, well, contractor, and sample number; (4)cross sections displaying digitized log traces, geochemical, and lithologic data by depth for wells; and (5)frequency distributions and bivariate plots. Although part of the EGSP Data System is proprietary, and distribution of complete well histories is prohibited by contract, maps and aggregated well-data listings are being made available to the public through published reports. ?? 1983 Plenum Publishing Corporation.

Petrology and diagenetic history of the upper shale member of the Late Devonian-Early Mississippian Bakken Formation, Williston Basin, North Dakota

USGS Publications Warehouse

Neil S. Fishman,; Sven O. Egenhoff,; Boehlke, Adam; Lowers, Heather A.

2015-01-01

The organic-rich upper shale member of the upper Devonian–lower Mississippian Bakken Formation (Williston Basin, North Dakota, USA) has undergone significant diagenetic alteration, irrespective of catagenesis related to hydrocarbon generation. Alteration includes precipitation of numerous cements, replacement of both detrital and authigenic minerals, multiple episodes of fracturing, and compaction. Quartz authigenesis occurred throughout much of the member, and is represented by multiple generations of microcrystalline quartz. Chalcedonic quartz fills radiolarian microfossils and is present in the matrix. Sulfide minerals include pyrite and sphalerite. Carbonate diagenesis is volumetrically minor and includes thin dolomite overgrowths and calcite cement. At least two generations of fractures are observed. Based on the authigenic minerals and their relative timing of formation, the evolution of pore waters can be postulated. Dolomite and calcite resulted from early postdepositional aerobic oxidation of some of the abundant organic material in the formation. Following aerobic oxidation, conditions became anoxic and sulfide minerals precipitated. Transformation of the originally opaline tests of radiolaria resulted in precipitation of quartz, and quartz authigenesis is most common in more distal parts of the depositional basin where radiolaria were abundant. Because quartz authigenesis is related to the distribution of radiolaria, there is a link between diagenesis and depositional environment. Furthermore, much of the diagenesis in the upper shale member preceded hydrocarbon generation, so early postdepositional processes were responsible for occlusion of significant original porosity in the member. Thus, diagenetic mineral precipitation was at least partly responsible for the limited ability of these mudstones to provide porosity for storage of hydrocarbons.

The New Albany Shale Petroleum System, Illinois Basin - Data and Map Image Archive from the Material-Balance Assessment

USGS Publications Warehouse

Higley, Debra K.; Henry, M.E.; Lewan, M.D.; Pitman, Janet K.

2003-01-01

The data files and explanations presented in this report were used to generate published material-balance approach estimates of amounts of petroleum 1) expelled from a source rock, and the sum of 2) petroleum discovered in-place plus that lost due to 3) secondary migration within, or leakage or erosion from a petroleum system. This study includes assessment of cumulative production, known petroleum volume, and original oil in place for hydrocarbons that were generated from the New Albany Shale source rocks.More than 4.00 billion barrels of oil (BBO) have been produced from Pennsylvanian-, Mississippian-, Devonian-, and Silurian-age reservoirs in the New Albany Shale petroleum system. Known petroleum volume is 4.16 BBO; the average recovery factor is 103.9% of the current cumulative production. Known petroleum volume of oil is 36.22% of the total original oil in place of 11.45 BBO. More than 140.4 BBO have been generated from the Upper Devonian and Lower Mississippian New Albany Shale in the Illinois Basin. Approximately 86.29 billion barrels of oil that was trapped south of the Cottage Grove fault system were lost by erosion of reservoir intervals. The remaining 54.15 BBO are 21% of the hydrocarbons that were generated in the basin and are accounted for using production data. Included in this publication are 2D maps that show the distribution of production for different formations versus the Rock-Eval pyrolysis hydrogen-indices (HI) contours, and 3D images that show the close association between burial depth and HI values.The primary vertical migration pathway of oil and gas was through faults and fractures into overlying reservoir strata. About 66% of the produced oil is located within the generative basin, which is outlined by an HI contour of 400. The remaining production is concentrated within 30 miles (50 km) outside the 400 HI contour. The generative basin is subdivided by contours of progressively lower hydrogen indices that represent increased levels of thermal maturity and generative capacity of New Albany Shale source rocks. The generative basin was also divided into seven oil-migration catchments. The catchments were determined using a surface-flow hydrologic model with contoured HI values as input to the model.

A review of the organic geochemistry of shales

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

Ho, P.C.; Meyer, R.E.

1987-06-01

Shale formations have been suggested as a potential site for a high level nuclear waste repository. As a first step in the study of the possible interaction of nuclides with the organic components of the shales, literature on the identification of organic compounds from various shales of the continent of the United States has been reviewed. The Green River shale of the Cenozoic era is the most studied shale followed by the Pierre shale of the Mesozoic era and the Devonian black shale of the Paleozoic era. Organic compounds that have been identified from these shales are hydrocarbons, fatty acids,more » fatty alcohols, steranes, terpanes, carotenes, carbohydrates, amino acids, and porphyrins. However, these organic compounds constitute only a small fraction of the organics in shales and the majority of the organic compounds in shales are still unidentified.« less

From carbonate platform to euxinic sea - the collapse of an Early/Middle Devonian reef, Cantabrian Mountains (Spain)

NASA Astrophysics Data System (ADS)

Loevezijn, Gerard B. S. van; Raven, J. G. M.

2017-12-01

The Santa Lucía Formation represents the major phase in Devonian reef development of the Cantabrian Zone (Cantabrian Mountains, northwest Spain). In the present study the transition from the carbonate platform deposits of the Santa Lucía Formation to the overlying euxinic basinal deposits of the Huergas Formation is described. These transitional strata are connected to the Basal Choteč Event and represent a condensed sedimentation of micritic dark-grey and black limestones with an upward increase of dark shale intercalations with iron mineralisation surfaces and storm-induced brachiopod coquinas. The transitional beds are grouped into a new unit, the Cabornera Bed, which consists of limestone, limestone-shale and shale facies associations, representing a sediment-starved euxinic offshore area just below the storm wave base. Four stages in reef decline can be recognised: a reef stage, an oxygen-depleted, nutrient-rich stage, a siliciclastic-influx stage and a pelagic-siliciclastic stage. Additional geochemical and geophysical investigations are needed to verify the results presented herein.

Gas storage in the Upper Devonian-Lower Mississippian Woodford Shale, Arbuckle Mountains, Oklahoma: how much of a role do the cherts play?

USGS Publications Warehouse

Fishman, Neil S.; Ellis, Geoffrey S.; Paxton, Stanley T.; Abbott, Marvin M.; Boehlke, Adam

2010-01-01

Microfractures also contribute to Woodford Shale porosity but they appear to be lithologically controlled. Fractures are relatively well-developed and are typically perpendicular to bedding in cherts, but these fractures typically end abruptly or become much more diffuse in adjacent mudstones. The brittle nature of the cherts, due to their high quartz content, is most likely the reason for their excellent fracture development, particularly relative to the mudstones, which are composed of much more ductile clay and Tasmanites constituents. Interestingly, the overlap of some petrophysical properties of cherts and mudstones (e.g., porosity, pore apertures) in the Woodford Shale for samples from the Arbuckle Mountains indicates that for shallowly-buried (i.e. minimally compacted) parts of the formation, both lithologies may have exhibited similar behavior relative to fluid movement. Where the Woodford has been more deeply buried and subjected to more intense compaction (i.e. in the Anadarko Basin), the petrophysical characteristics of cherts are likely to have changed only minimally due to their rigid fabric, whereas the petrophysical characteristics of the mudstones are likely to have changed significantly due to compaction and the resultant compression and collapse of ductile constituents such as clays and Tasmanites microfossils (those without quartz infilling). Moldic porosity, which could be expected to develop in kerogen as a consequence of maturation (Loucks and others, 2009), is more likely in the high TOC mudstones, but would also occur in Woodford cherts, which contain lower TOC contents. Owing to the potential for Woodford cherts to better retain porosity, coupled with their contained TOC, cherts may indeed provide important overlooked intervals of gas generation and overall gas storage in the formation. Thus, Woodford cherts may contribute a significant portion of the gas that is produced from the formation. As such, chert beds may play a very significant, heretofore overlooked role as source and reservoir intervals within the Woodford in the Anadarko Basin.

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

Skrinak, V.M.

The Eastern Devonian Gas Shales Technology Review is a technology transfer vehicle designed to keep industry and research organizations aware of major happenings in the shales. Four issues were published, and the majority of the readership was found to be operators. Under the other major task in this project, areal and analytic analyses of the basin resulted in reducing the study area by 30% while defining a rectangular coordinate system for the basin. Shale-well cost and economic models were developed and validated, and a simplified flow model was prepared.

Hydraulic Fracture Extending into Network in Shale: Reviewing Influence Factors and Their Mechanism

PubMed Central

Ren, Lan; Zhao, Jinzhou; Hu, Yongquan

2014-01-01

Hydraulic fracture in shale reservoir presents complex network propagation, which has essential difference with traditional plane biwing fracture at forming mechanism. Based on the research results of experiments, field fracturing practice, theory analysis, and numerical simulation, the influence factors and their mechanism of hydraulic fracture extending into network in shale have been systematically analyzed and discussed. Research results show that the fracture propagation in shale reservoir is influenced by the geological and the engineering factors, which includes rock mineral composition, rock mechanical properties, horizontal stress field, natural fractures, treating net pressure, fracturing fluid viscosity, and fracturing scale. This study has important theoretical value and practical significance to understand fracture network propagation mechanism in shale reservoir and contributes to improving the science and efficiency of shale reservoir fracturing design. PMID:25032240

Empirical Methods for Detecting Regional Trends and Other Spatial Expressions in Antrim Shale Gas Productivity, with Implications for Improving Resource Projections Using Local Nonparametric Estimation Techniques

USGS Publications Warehouse

Coburn, T.C.; Freeman, P.A.; Attanasi, E.D.

2012-01-01

The primary objectives of this research were to (1) investigate empirical methods for establishing regional trends in unconventional gas resources as exhibited by historical production data and (2) determine whether or not incorporating additional knowledge of a regional trend in a suite of previously established local nonparametric resource prediction algorithms influences assessment results. Three different trend detection methods were applied to publicly available production data (well EUR aggregated to 80-acre cells) from the Devonian Antrim Shale gas play in the Michigan Basin. This effort led to the identification of a southeast-northwest trend in cell EUR values across the play that, in a very general sense, conforms to the primary fracture and structural orientations of the province. However, including this trend in the resource prediction algorithms did not lead to improved results. Further analysis indicated the existence of clustering among cell EUR values that likely dampens the contribution of the regional trend. The reason for the clustering, a somewhat unexpected result, is not completely understood, although the geological literature provides some possible explanations. With appropriate data, a better understanding of this clustering phenomenon may lead to important information about the factors and their interactions that control Antrim Shale gas production, which may, in turn, help establish a more general protocol for better estimating resources in this and other shale gas plays. ?? 2011 International Association for Mathematical Geology (outside the USA).

Assessing Distribution and Origin of Methane in Shallow Groundwater in Horizontal Oil and Gas Play Areas, Eastern Kentucky

NASA Astrophysics Data System (ADS)

Zhu, J.; Parris, T. M.; Taylor, C. J.; Webb, S. E.; Davidson, B.; Smath, R.; Richardson, S. D.; Molofsky, L.; Kromann, J. S.

2016-12-01

Rapid implementation of horizontal drilling and hydraulic fracturing technology to produce oil and gas from tight rock formations across the country has increased public concern about possible impact on the environment, especially on shallow drinking-water aquifers. In eastern Kentucky, horizontal drilling and hydraulic fracturing have been used to develop the Upper Devonian Berea Sandstone in recent years. Although production in the Berea Sandstone is at a relatively small scale, the Rogersville Shale, a deeper, thicker, and more spatially extensive organic-rich shale, is projected to become a major shale play in eastern Kentucky. This has necessitated a better understanding of groundwater quality, especially the occurrence of dissolved methane, in aquifers overlying the Berea and Rogersville plays to help address the public's environmental concerns and protect groundwater resources. To assess baseline groundwater chemistry and evaluate distribution and origin of methane detected in the groundwater, 51 water wells in Greenup, Carter, Boyd, Lawrence, Johnson, and Elliott Counties were sampled and analyzed for major cations and anions, metals, and dissolved light hydrocarbon gases including methane. Twenty-six wells were identified as having methane concentrations greater than 1 mg/L and were further analyzed for carbon and hydrogen isotopes. The results indicate that methane is a relatively common constituent in shallow groundwater in eastern Kentucky. Correlation of methane distribution with water chemistry data shows that elevated methane concentrations were more common in sodium bicarbonate type water and in low-nitrate, low-sulfate redox conditions. Carbon and hydrogen isotope analysis suggests that the methane detected in groundwater is derived primarily from bacterial sources from the CO2 reduction pathway.

On the origin of a phosphate enriched interval in the Chattanooga Shale (Upper Devonian) of Tennessee-A combined sedimentologic, petrographic, and geochemical study

NASA Astrophysics Data System (ADS)

Li, Yifan; Schieber, Juergen

2015-11-01

The Devonian Chattanooga Shale contains an uppermost black shale interval with dispersed phosphate nodules. This interval extends from Tennessee to correlative strata in Kentucky, Indiana, and Ohio and represents a significant period of marine phosphate fixation during the Late Devonian of North America. It overlies black shales that lack phosphate nodules but otherwise look very similar in outcrop. The purpose of this study is to examine what sets these two shales apart and what this difference tells us about the sedimentary history of the uppermost Chattanooga Shale. In thin section, the lower black shales (PBS) show pyrite enriched laminae and compositional banding. The overlying phosphatic black shales (PhBS) are characterized by phosbioclasts, have a general banded to homogenized texture with reworked layers, and show well defined horizons of phosphate nodules that are reworked and transported. In the PhBS, up to 8000 particles of P-debris per cm2 occur in reworked beds, whereas the background black shale shows between 37-88 particles per cm2. In the PBS, the shale matrix contains between 8-16 phosphatic particles per cm2. The shale matrix in the PhBS contains 5.6% inertinite, whereas just 1% inertinite occurs in the PBS. The shale matrix in both units is characterized by flat REE patterns (shale-normalized), whereas Phosbioclast-rich layers in the PhBS show high concentrations of REEs and enrichment of MREEs. Negative Ce-anomalies are common to all samples, but are best developed in association with Phosbioclasts. Redox-sensitive elements (Co, U, Mo) are more strongly enriched in the PBS when compared to the PhBS. Trace elements associated with organic matter (Cu, Zn, Cd, Ni) show an inverse trend of enrichment. Deposited atop a sequence boundary that separates the two shale units, the PhBS unit represents a transgressive systems tract and probably was deposited in shallower water than the underlying PBS interval. The higher phosphate content in the PhBS is interpreted as the result of a combination of lower sedimentation rates with reworking/winnowing episodes. Three types of phosphatic beds that reflect different degrees of reworking intensity are observed. Strong negative Ce anomalies and abundant secondary marcasite formation in the PhBS suggests improved aeration of the water column, and improved downward diffusion of oxygen into the sediment. The associated oxidation of previously formed pyrite resulted in a lowering of pore water pH and forced dissolution of biogenic phosphate. Phosphate dissolution was followed by formation of secondary marcasite and phosphate. Repeated, episodic reworking caused repetitive cycles of phosphatic dissolution and reprecipitation, enriching MREEs in reprecipitated apatite. A generally "deeper" seated redox boundary favored P-remineralization within the sediment matrix, and multiple repeats of this process in combination with wave and current reworking at the seabed led to the formation of larger phosphatic aggregates and concentration of phosphate nodules in discrete horizons.

The geology of Burnsville Cove, Bath and Highland Counties, Virginia

USGS Publications Warehouse

Swezey, Christopher; Haynes, John T.; Lambert, Richard A.; White, William B.; Lucas, Philip C.; Garrity, Christopher P.

2015-01-01

Burnsville Cove is a karst region in Bath and Highland Counties of Virginia. A new geologic map of the area reveals various units of limestone, sandstone, and siliciclastic mudstone (shale) of Silurian through Devonian age, as well as structural features such as northeast-trending anticlines and synclines, minor thrust faults, and prominent joints. Quaternary features include erosional (strath) terraces and accumulations of mud, sand, and gravel. The caves of Burnsville Cove are located within predominantly carbonate strata above the Silurian Williamsport Sandstone and below the Devonian Oriskany Sandstone. Most of the caves are located within the Silurian Tonoloway Limestone, rather than the Silurian-Devonian Keyser Limestone as reported previously.

Sedimentology and stratigraphy of the Kanayut Conglomerate, central and western Brooks Range, Alaska; report of 1981 field season

USGS Publications Warehouse

Nilsen, T.H.; Moore, T.E.

1982-01-01

The Upper Devonian and Lower Mississippian(?) Kanayut Conglomerate forms a major stratigraphic unit along the crest of the Brooks Range of northern Alaska. It crops out for an east-west distance of about 900 km and a north-south distance of about 65 km. The Kanayut is wholly allochthonous and has probably been transported northward on a series of thrust plates. The Kanayut is as thick as 2,600 m in the east-central Brooks Range. It thins and fines to the south and west. The Kanayut forms the middle part of the allochthonous sequence of the Endicott Group, an Upper Devonian and Mississippian clastic sequence underlain by platform limestones of the Baird Group and overlain by platform limestone, carbonaceous shale, and black chert of the Lisburne Group. The Kanayut overlies the marine Upper Devonian Noatak Sandstone or, where it is missing, the marine Upper Devonian Hunt Fork Shale. It is overlain by the marine Mississippian Kayak Shale. The Kanayut Conglomerate forms the fluvial part of a large, coarse-grained delta that prograded to the southwest in Late Devonian time and retreated in Early Mississippian time. Four sections of the Kanayut Conglomerate in the central Brooks Range and five in the western Brooks Range were measured in 1981. The sections from the western Brooks Range document the presence of fluvial cycles in the Kanayut as far west as the shores of the Chukchi Sea. The Kanayut in this area is generally finer grained than it is in the central and eastern Brooks Range, having a maximum clast size of 3 cm. It is probably about 300 m thick. The upper and lower contacts of the Kanayut are gradational. The lower Kanayut contains calcareous, marine-influenced sandstone within channel deposits, and the upper Kanayut contains probable marine interdistributary-bay shale sequences. The members of the Kanayut Conglomerate cannot be differentiated in this region. In the central Brooks Range, sections of the Kanayut Conglomerate at Siavlat Mountain and Kakivilak Creek are typically organized into fining-upward fluvial cycles. The maximum clast size is about 3 cm in this area. The Kanayut in this region is 200-500 m thick and can be divided into the Ear Peak, Shainin Lake, and Stuver Members. The upper contact of the Kanayut with the Kayak Shale is very gradational at Kakivilak Creek and very abrupt at Siavlat Mountain. Paleocurrents from fluvial strata of the Kanayut indicate sediment transport toward the west and south in both the western and central Brooks Range. The maximum clast size distribution generally indicates westward fining from the Shainin Lake region.

Dry Volume Fracturing Simulation of Shale Gas Reservoir

NASA Astrophysics Data System (ADS)

Xu, Guixi; Wang, Shuzhong; Luo, Xiangrong; Jing, Zefeng

2017-11-01

Application of CO2 dry fracturing technology to shale gas reservoir development in China has advantages of no water consumption, little reservoir damage and promoting CH4 desorption. This paper uses Meyer simulation to study complex fracture network extension and the distribution characteristics of shale gas reservoirs in the CO2 dry volume fracturing process. The simulation results prove the validity of the modified CO2 dry fracturing fluid used in shale volume fracturing and provides a theoretical basis for the following study on interval optimization of the shale reservoir dry volume fracturing.

Rhenium and osmium isotopes in black shales and Ni-Mo-PGE-rich sulfide layers, Yukon Territory, Canada, and Hunan and Guizhou provinces, China

USGS Publications Warehouse

Horan, M.F.; Morgan, J.W.; Grauch, R.I.; Coveney, R.M.; Murowchick, J.B.; Hulbert, L.J.

1994-01-01

Rhenium and osmium abundances and osmium isotopic compositions were determined by negative thermal ionization mass spectrometry for samples of Devonian black shale and an associated Ni-enriched sulfide layer from the Yukon Territory, Canada. The same composition information was also obtained for samples of early Cambrian Ni-Mo-rich sulfide layers hosted in black shale in Guizhou and Hunan provinces, China. This study was undertaken to constrain the origin of the PGE enrichment in the sulfide layers. Samples of the Ni sulfide layer from the Yukon Territory are highly enriched in Re, Os, and other PGE, with distinctly higher Re/192Os but similar Pt/Re, compared to the black shale host. Re-Os isotopic data of the black shale and the sulfide layer are approximately isochronous, and the data plot close to reference isochrons which bracket the depositional age of the enclosing shales. Samples of the Chinese sulfide layers are also highly enriched in Re, Os, and the other PGE. Re/192Os are lower than in the Yukon sulfide layer. Re-Os isotopic data for the sulfide layers lie near a reference isochron with an age of 560 Ma, similar to the depositional age of the black shale host. The osmium isotopic data suggest that Re and PGE enrichment of the brecciated sulfide layers in both the Yukon Territory and in southern China may have occurred near the time of sediment deposition or during early diagenesis, during the middle to late Devonian and early Cambrian, respectively. ?? 1994.

Numerical simulation and fracture identification of dual laterolog in organic shale

NASA Astrophysics Data System (ADS)

Maojin, Tan; Peng, Wang; Qiong, Liu

2012-09-01

Fracture is one of important spaces in shale oil and shale gas reservoirs, and fractures identification and evaluation are an important part in organic shale interpretation. According to the fractured shale gas reservoir, a physical model is set up to study the dual laterolog logging responses. First, based on the principle of dual laterolog, three-dimensional finite element method (FEM) is used to simulate the dual laterolog responses in various formation models with different fractures widths, different fracture numbers, different fractures inclination angle. All the results are extremely important for the fracture identification and evaluation in shale reservoirs. Appointing to different base rock resistivity models, the fracture models are constructed respectively through a number of numerical simulation, and the fracture porosity can be calculated by solving the corresponding formulas. A case study about organic shale formation is analyst and discussed, and the fracture porosity is calculated from dual laterolog. The fracture evaluation results are also be validated right by Full borehole Micro-resistivity Imaging (FMI). So, in case of the absence of borehole resistivity imaging log, the dual laterolog resistivity can be used to estimate the fracture development.

Trace-element budgets in the Ohio/Sunbury shales of Kentucky: Constraints on ocean circulation and primary productivity in the Devonian-Mississippian Appalachian Basin

USGS Publications Warehouse

Perkins, R.B.; Piper, D.Z.; Mason, C.E.

2008-01-01

The hydrography of the Appalachian Basin in late Devonian-early Mississippian time is modeled based on the geochemistry of black shales and constrained by others' paleogeographic reconstructions. The model supports a robust exchange of basin bottom water with the open ocean, with residence times of less than forty years during deposition of the Cleveland Shale Member of the Ohio Shale. This is counter to previous interpretations of these carbon-rich units having accumulated under a stratified and stagnant water column, i.e., with a strongly restricted bottom bottom-water circulation. A robust circulation of bottom waters is further consistent with the palaeoclimatology, whereby eastern trade-winds drove upwelling and arid conditions limited terrestrial inputs of siliciclastic sediment, fresh waters, and riverine nutrients. The model suggests that primary productivity was high (~ 2??g C m- 2 d- 1), although no higher than in select locations in the ocean today. The flux of organic carbon settling through the water column and its deposition on the sea floor was similar to fluxes found in modern marine environments. Calculations based on the average accumulation rate of the marine fraction of Ni suggest the flux of organic carbon settling out of the water column was approximately 9% of primary productivity, versus an accumulation rate (burial) of organic carbon of 0.5% of primary productivity. Trace-element ratios of V:Mo and Cr:Mo in the marine sediment fraction indicate that bottom waters shifted from predominantly anoxic (sulfate reducing) during deposition of the Huron Shale Member of the Ohio Shale to predominantly suboxic (nitrate reducing) during deposition of the Cleveland Shale Member and the Sunbury Shale, but with anoxic conditions occurring intermittently throughout this period. ?? 2008 Elsevier B.V.

The subsurface impact of hydraulic fracturing in shales- Perspectives from the well and reservoir

NASA Astrophysics Data System (ADS)

ter Heege, Jan; Coles, Rhys

2017-04-01

It has been identified that the main risks of subsurface shale gas operations in the U.S.A. and Canada are associated with (1) drilling and well integrity, (2) hydraulic fracturing, and (3) induced seismicity. Although it is unlikely that hydraulic fracturing operations result in direct pathways of enhanced migration between stimulated fracture disturbed rock volume and shallow aquifers, operations may jeopardize well integrity or induce seismicity. From the well perspective, it is often assumed that fluid injection leads to the initiation of tensile (mode I) fractures at different perforation intervals along the horizontal sections of shale gas wells if pore pressure exceeds the minimum principal stress. From the reservoir perspective, rise in pore pressure resulting from fluid injection may lead to initiation of tensile fractures, reactivation of shear (mode II) fractures if the criterion for failure in shear is exceeded, or combinations of different fracturing modes. In this study, we compare tensile fracturing simulations using conventional well-based models with shear fracturing simulations using a fractured shale model with characteristic fault populations. In the fractured shale model, stimulated permeability is described by an analytical model that incorporates populations of reactivated faults and that combines 3D permeability tensors for layered shale matrix, damage zone and fault core. Well-based models applied to wells crosscutting the Posidonia Shale Formation are compared to generic fractured shale models, and fractured shale models are compared to micro-seismic data from the Marcellus Shale. Focus is on comparing the spatial distribution of permeability, stimulated reservoir volume and seismicity, and on differences in fracture initiation pressure and fracture orientation for tensile and shear fracturing end-members. It is shown that incorporation of fault populations (for example resulting from analysis of 3D seismics or outcrops) in hydraulic fracturing models provides better constraints on well pressures, stimulated fracture disturbed volume and induced seismicity. Thereby, it helps assessing the subsurface impact of hydraulic fracturing in shales and mitigating risks associated with loss of loss of well integrity, loss of fracture containment, and induced seismicity.

Use of arsenic and REE in black shales as potential environmental tracers in hydraulic fracturing operations

NASA Astrophysics Data System (ADS)

Yang, J.; Torres, M. E.; Haley, B. A.; McKay, J. L.; Algeo, T. J.; Hakala, A.; Joseph, C.; Edenborn, H. M.

2013-12-01

Black shales commonly targeted for shale gas development were deposited under low oxygen concentrations, and typically contain high As levels. The depositional environment governs its solid-phase association in the sediment, which in turn will influence degree of remobilization during hydraulic fracturing. Organic carbon (OC), trace element (TE) and REE distributions have been used as tracers for assessing deep water redox conditions at the time of deposition in the Midcontinent Sea of North America (Algeo and Heckel, 2008), during large-scale oceanic anoxic events (e.g., Bunte, 2009) and in modern OC-rich sediments underlying coastal upwelling areas (e.g., Brumsack, 2006). We will present REE and As data from a collection of six different locations in the continental US (Kansas, Iowa, Oklahoma, Kentucky, North Dakota and Pennsylvania), ranging in age from Devonian to Upper Pennsylvanian, and from a Cretaceous black shale drilled on the Demerara Rise during ODP Leg 207. We interpret our data in light of the depositional framework previously developed for these locations based on OC and TE patterns, to document the mechanisms leading to REE and As accumulation, and explore their potential use as environmental proxies and their diagenetic remobilization during burial, as part of our future goal to develop a predictive evaluation of arsenic release from shales and transport with flowback waters. Total REE abundance (ΣREE) ranged from 35 to 420 ppm in an organic rich sample from Stark shale, KS. PAAS-normalized REE concentrations ranged from 0.5 to 7, with the highest enrichments observed in the MREE (Sm to Ho). Neither the ΣREE nor the MREE enrichments correlated with OC concentrations or postulated depositional redox conditions, suggesting a principal association with aluminosilicates and selective REE fractionation during diagenesis. In the anoxic reducing environments in which black shales were deposited, sulfide minerals such as FeS2 trap aqueous arsenic in the crystal lattice, but As is also known to bind to the charged surfaces of clay minerals. Our arsenic concentration data show that the highest abundances (up to 70 ppm) are found in sediments with the highest total sulfur concentration (to 2.6 ppm), but there was no clear correlation with organic carbon or aluminosilicate content. We compare our results with preliminary data from a series of flowback waters sampled from ten producing wells in Pennsylvania and from high-pressure high-temperature experimental leaching of Marcellus shale samples.

A Systems Approach to Identifying Exploration and Development Opportunities in the Illinois Basin: Digital Portifolio of Plays in Underexplored Lower Paleozoic Rocks [Part 1 of 2

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

Seyler, Beverly; Harris, David; Keith, Brian

2008-06-30

This study examined petroleum occurrence in Ordovician, Silurian and Devonian reservoirs in the Illinois Basin. Results from this project show that there is excellent potential for additional discovery of petroleum reservoirs in these formations. Numerous exploration targets and exploration strategies were identified that can be used to increase production from these underexplored strata. Some of the challenges to exploration of deeper strata include the lack of subsurface data, lack of understanding of regional facies changes, lack of understanding the role of diagenetic alteration in developing reservoir porosity and permeability, the shifting of structural closures with depth, overlooking potential producing horizons,more » and under utilization of 3D seismic techniques. This study has shown many areas are prospective for additional discoveries in lower Paleozoic strata in the Illinois Basin. This project implemented a systematic basin analysis approach that is expected to encourage exploration for petroleum in lower Paleozoic rocks of the Illinois Basin. The study has compiled and presented a broad base of information and knowledge needed by independent oil companies to pursue the development of exploration prospects in overlooked, deeper play horizons in the Illinois Basin. Available geologic data relevant for the exploration and development of petroleum reservoirs in the Illinois Basin was analyzed and assimilated into a coherent, easily accessible digital play portfolio. The primary focus of this project was on case studies of existing reservoirs in Devonian, Silurian, and Ordovician strata and the application of knowledge gained to future exploration and development in these underexplored strata of the Illinois Basin. In addition, a review of published reports and exploration in the New Albany Shale Group, a Devonian black shale source rock, in Illinois was completed due to the recent increased interest in Devonian black shales across the United States. The New Albany Shale is regarded as the source rock for petroleum in Silurian and younger strata in the Illinois Basin and has potential as a petroleum reservoir. Field studies of reservoirs in Devonian strata such as the Geneva Dolomite, Dutch Creek Sandstone and Grassy knob Chert suggest that there is much additional potential for expanding these plays beyond their current limits. These studies also suggest the potential for the discovery of additional plays using stratigraphic concepts to develop a subcrop play on the subkaskaskia unconformity boundary that separates lower Devonian strata from middle Devonian strata in portions of the basin. The lateral transition from Geneva Dolomite to Dutch Creek Sandstone also offers an avenue for developing exploration strategies in middle Devonian strata. Study of lower Devonian strata in the Sesser Oil Field and the region surrounding the field shows opportunities for development of a subcrop play where lower Devonian strata unconformably overlie Silurian strata. Field studies of Silurian reservoirs along the Sangamon Arch show that opportunities exist for overlooked pays in areas where wells do not penetrate deep enough to test all reservoir intervals in Niagaran rocks. Mapping of Silurian reservoirs in the Mt. Auburn trend along the Sangamon Arch shows that porous reservoir rock grades laterally to non-reservoir facies and several reservoir intervals may be encountered in the Silurian with numerous exploration wells testing only the uppermost reservoir intervals. Mapping of the Ordovician Trenton and shallower strata at Centralia Field show that the crest of the anticline shifted through geologic time. This study illustrates that the axes of anticlines may shift with depth and shallow structure maps may not accurately predict structurally favorable reservoir locations at depth.« less

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

Barron, L.S.; Ettensohn, F.R.

The Devonian-Mississippian black-shale sequence is one of the most prominent and well-known stratigraphic horizons in the Paleozoic of the United States, yet the paleontology and its paleoecologic and paleoenvironmental implications are poorly known. This is in larger part related to the scarcity of fossils preserved in the shale - in terms of both diversity and abundance. Nonetheless, that biota which is preserved is well-known and much described, but there is little synthesis of this data. The first step in such a synthesis is the compilation of an inclusive bibliography such as this one. This bibliography contains 1193 entries covering allmore » the major works dealing with Devonian-Mississippian black-shale paleontology and paleoecology in North America. Articles dealing with areas of peripheral interest, such as paleogeography, paleoclimatology, ocean circulation and chemistry, and modern analogues, are also cited. In the index, the various genera, taxonomic groups, and other general topics are cross-referenced to the cited articles. It is hoped that this compilation will aid in the synthesis of paleontologic and paleoecologic data toward a better understanding of these unique rocks and their role as a source of energy.« less

The Multi-Porosity Multi-Permeability and Electrokinetic Natures of Shales and Their Effects in Hydraulic Fracturing of Unconventional Shale Reservoirs

NASA Astrophysics Data System (ADS)

Liu, C.; Hoang, S. K.; Tran, M. H.; Abousleiman, Y. N.

2013-12-01

Imaging studies of unconventional shale reservoir rocks have recently revealed the multi-porosity multi-permeability nature of these intricate formations. In particular, the porosity spectrum of shale reservoir rocks often comprises of the nano-porosity in the organic matters, the inter-particle micro-porosity, and the macroscopic porosity of the natural fracture network. Shale is also well-known for its chemically active behaviors, especially shrinking and swelling when exposed to aqueous solutions, as the results of pore fluid exchange with external environment due to the difference in electro-chemical potentials. In this work, the effects of natural fractures and electrokinetic nature of shale on the formation responses during hydraulic fracturing are examined using the dual-poro-chemo-electro-elasticity approach which is a generalization of the classical Biot's poroelastic formulation. The analyses show that the presence of natural fractures can substantially increase the leak-off rate of fracturing fluid into the formation and create a larger region of high pore pressure near the fracture face as shown in Fig.1a. Due to the additional fluid invasion, the naturally fractured shale swells up more and the fracture aperture closes faster compared to an intrinsically low permeability non-fractured shale formation as shown in Fig.1b. Since naturally fractured zones are commonly targeted as pay zones, it is important to account for the faster fracture closing rate in fractured shales in hydraulic fracturing design. Our results also show that the presence of negative fixed charges on the surface of clay minerals creates an osmotic pressure at the interface of the shale and the external fluid as shown in Fig.1c. This additional Donnan-induced pore pressure can result in significant tensile effective stresses and tensile damage in the shale as shown in Fig.1d. The induced tensile damage can exacerbate the problem of proppant embedment resulting in more fracture closure and reduction of fracture length and productivity. The results also suggest that a fracturing fluid with appropriately designed salinity can minimize the chemically induced tensile damage and, thus, maximize the productivity from the created hydraulic fractures.

Application of Fractal Geometry in Evaluation of Effective Stimulated Reservoir Volume in Shale Gas Reservoirs

NASA Astrophysics Data System (ADS)

Sheng, Guanglong; Su, Yuliang; Wang, Wendong; Javadpour, Farzam; Tang, Meirong

According to hydraulic-fracturing practices conducted in shale reservoirs, effective stimulated reservoir volume (ESRV) significantly affects the production of hydraulic fractured well. Therefore, estimating ESRV is an important prerequisite for confirming the success of hydraulic fracturing and predicting the production of hydraulic fracturing wells in shale reservoirs. However, ESRV calculation remains a longstanding challenge in hydraulic-fracturing operation. In considering fractal characteristics of the fracture network in stimulated reservoir volume (SRV), this paper introduces a fractal random-fracture-network algorithm for converting the microseismic data into fractal geometry. Five key parameters, including bifurcation direction, generating length (d), deviation angle (α), iteration times (N) and generating rules, are proposed to quantitatively characterize fracture geometry. Furthermore, we introduce an orthogonal-fractures coupled dual-porosity-media representation elementary volume (REV) flow model to predict the volumetric flux of gas in shale reservoirs. On the basis of the migration of adsorbed gas in porous kerogen of REV with different fracture spaces, an ESRV criterion for shale reservoirs with SRV is proposed. Eventually, combining the ESRV criterion and fractal characteristic of a fracture network, we propose a new approach for evaluating ESRV in shale reservoirs. The approach has been used in the Eagle Ford shale gas reservoir, and results show that the fracture space has a measurable influence on migration of adsorbed gas. The fracture network can contribute to enhancement of the absorbed gas recovery ratio when the fracture space is less than 0.2 m. ESRV is evaluated in this paper, and results indicate that the ESRV accounts for 27.87% of the total SRV in shale gas reservoirs. This work is important and timely for evaluating fracturing effect and predicting production of hydraulic fracturing wells in shale reservoirs.

Late Ordovician (post-Sardic) rifting branches in the North Gondwanan Montagne Noire and Mouthoumet massifs of southern France

NASA Astrophysics Data System (ADS)

Javier Álvaro, J.; Colmenar, Jorge; Monceret, Eric; Pouclet, André; Vizcaïno, Daniel

2016-06-01

Upper Ordovician-Lower Devonian rocks of the Cabrières klippes (southern Montagne Noire) and the Mouthoumet massif in southern France rest paraconformably or with angular discordance on Cambrian-Lower Ordovician strata. Neither Middle-Ordovician volcanism nor associated metamorphism is recorded, and the subsequent Middle-Ordovician stratigraphic gap is related to the Sardic phase. Upper Ordovician sedimentation started in the rifting branches of Cabrières and Mouthoumet with deposition of basaltic lava flows and lahar deposits (Roque de Bandies and Villerouge formations) of continental tholeiite signature (CT), indicative of continental fracturing. The infill of both rifting branches followed with the onset of (1) Katian (Ka1-Ka2) conglomerates and sandstones (Glauzy and Gascagne formations), which have yielded a new brachiopod assemblage representative of the Svobodaina havliceki Community; (2) Katian (Ka2-Ka4) limestones, marlstones, and shales with carbonate nodules, reflecting development of bryozoan-echinoderm meadows with elements of the Nicolella Community (Gabian and Montjoi formations); and (3) the Hirnantian Marmairane Formation in the Mouthoumet massif that has yielded a rich and diverse fossil association representative of the pandemic Hirnantia Fauna. The sealing of the subaerial palaeorelief generated during the Sardic phase is related to Silurian and Early Devonian transgressions leading to onlapping patterns and the record of high-angle discordances.

Natural Gases in Ground Water near Tioga Junction, Tioga County, North-Central Pennsylvania - Occurrence and Use of Isotopes to Determine Origins, 2005

USGS Publications Warehouse

Breen, Kevin J.; Revesz, Kinga; Baldassare, Fred J.; McAuley, Steven D.

2007-01-01

In January 2001, State oil and gas inspectors noted bubbles of natural gas in well water during a complaint investigation near Tioga Junction, Tioga County, north-central Pa. By 2004, the gas occurrence in ground water and accumulation in homes was a safety concern; inspectors were taking action to plug abandoned gas wells and collect gas samples. The origins of the natural-gas problems in ground water were investigated by the U.S. Geological Survey, in cooperation with the Pennsylvania Department of Environmental Protection, in wells throughout an area of about 50 mi2, using compositional and isotopic characteristics of methane and ethane in gas and water wells. This report presents the results for gas-well and water-well samples collected from October 2004 to September 2005. Ground water for rural-domestic supply and other uses near Tioga Junction is from two aquifer systems in and adjacent to the Tioga River valley. An unconsolidated aquifer of outwash sand and gravel of Quaternary age underlies the main river valley and extends into the valleys of tributaries. Fine-grained lacustrine sediments separate shallow and deep water-bearing zones of the outwash. Outwash-aquifer wells are seldom deeper than 100 ft. The river-valley sediments and uplands adjacent to the valley are underlain by a fractured-bedrock aquifer in siliciclastic rocks of Paleozoic age. Most bedrock-aquifer wells produce water from the Lock Haven Formation at depths of 250 ft or less. A review of previous geologic investigations was used to establish the structural framework and identify four plausible origins for natural gas. The Sabinsville Anticline, trending southwest to northeast, is the major structural feature in the Devonian bedrock. The anticline, a structural trap for a reservoir of deep native gas in the Oriskany Sandstone (Devonian) (origin 1) at depths of about 3,900 ft, was explored and tapped by numerous wells from 1930-60. The gas reservoir in the vicinity of Tioga Junction, depleted of native gas, was converted to the Tioga gas-storage field for injection and withdrawal of non-native gases (origin 2). Devonian shale gas (shallow native gas) also has been reported in the area (origin 3). Gas might also originate from microbial degradation of buried organic material in the outwash deposits (origin 4). An inventory of combustible-gas concentrations in headspaces of water samples from 91 wells showed 49 wells had water containing combustible gases at volume fractions of 0.1 percent or more. Well depth was a factor in the observed occurrence of combustible gas for the 62 bedrock wells inventoried. As well-depth range increased from less than 50 ft to 51-150 ft to greater than 151 ft, the percentage of bedrock-aquifer wells with combustible gas increased. Wells with high concentrations of combustible gas occurred in clusters; the largest cluster was near the eastern boundary of the gas-storage field. A subsequent detailed gas-sampling effort focused on 39 water wells with the highest concentrations of combustible gas (12 representing the outwash aquifer and 27 from the bedrock aquifer) and 8 selected gas wells. Three wells producing native gas from the Oriskany Sandstone and five wells (two observation wells and three injection/withdrawal wells) with non-native gas from the gas-storage field were sampled twice. Chemical composition, stable carbon and hydrogen isotopes of methane (13CCH4 and DCH4), and stable carbon isotopes of ethane (13CC2H6) were analyzed. No samples could be collected to document the composition of microbial gas originating in the outwash deposits (outwash or 'drift' gas) or of native natural gas originating solely in Devonian shale at depths shallower than the Oriskany Sandstone, although two of the storage-field observation wells sampled reportedly yielded some Devonian shale gas. Literature values for outwash or 'drift' gas and Devonian shale gases were used to supplement the data collection. Non-native gases fr

Relating Stress Drop Variations with Geological Setting for Injection-Induced Seismicity and Its Seismic Hazard Implications

NASA Astrophysics Data System (ADS)

Urbancic, T.; Viegas, G. F.; Baig, A.

2017-12-01

We observe conflicting stress drop estimates of M0 to M4 injection-induced earthquakes in two regions of the Western Canadian Sedimentary Basin. Induced earthquakes in the Horn River Basin show lower stress drops than induced earthquakes in the Duvernay Basin by a factor of 10 to 20. Higher stress drop earthquakes have a significant role in seismic hazard as they generate higher frequency strong ground motions which can potentially cause more damages, making it important to understand its causes. Both earthquake datasets occur below shale reservoirs under hydraulic-fracture stimulation programs. Both treatment programs target the same shale formation (Muskwa in Horn River Basin and Duvernay in Duvernay Basin) at approximately the same depth (3 km). Both reservoirs are located to the edge of the Western Canadian Sedimentary Basin bordering the Rocky Mountains and are under the same tectonic setting, both currently and during the Devonian depositional phase. The major observable difference is the local geology. While the Horn River Basin in northeast British Columbia shows mostly continuous horizontal stratification the Duvernay shale in the Fox Creek region in Alberta drapes over Leduc Formation reefs which cross-cut it as chains of reefs, isolated atolls and isolated pinnacles. Schultz et al. (2017) showed that induced seismicity in the Duvernay Basin region occurs primarily in the margins of the Devonian carbonate reefs (10 to 20 km away) where optimally oriented basement faults exist. The fault system is in part associated with basement tectonism and isostatic compensation mechanisms involved in the reefs diagenesis. We propose that the observed stress drop differences are caused by different regional stress characteristics, with events occurring in more stressed regions having higher stress drops. These areas of higher stress are found at the margins of the denser Leduc reefs formation and may be caused either by load transfer, isostatic compensation mechanisms, and accumulation of strain energy in the underlying fault system. The geological setting in which earthquakes occur may be a more important factor than previously considered in seismic hazard studies.

Late Devonian glacigenic and associated facies from the central Appalachian Basin, eastern United States

USGS Publications Warehouse

Brezinski, D.K.; Cecil, C.B.; Skema, V.W.

2010-01-01

Late Devonian strata in the eastern United States are generally considered as having been deposited under warm tropical conditions. However, a stratigraphically restricted Late Devonian succession of diamictite- mudstonesandstone within the Spechty Kopf and Rockwell Formations that extends for more than 400 km along depositional strike within the central Appalachian Basin may indicate other wise. This lithologic association unconformably overlies the Catskill Formation, where a 3- to 5-m-thick interval of deformed strata occurs immediately below the diamictite strata. The diamictite facies consists of several subfacies that are interpreted to be subglacial, englacial, supraglacial meltout, and resedimented deposits. The mudstone facies that overlies the diamictite consists of subfacies of chaotically bedded, clast-poor mudstone, and laminated mudstone sub facies that represent subaqueous proximal debris flows and distal glaciolacustrine rhythmites or varvites, respectively. The pebbly sandstone facies is interpreted as proglacial braided outwash deposits that both preceded glacial advance and followed glacial retreat. Both the tectonic and depositional frameworks suggest that the facies were deposited in a terrestrial setting within the Appalachian foreland basin during a single glacial advance and retreat. Regionally, areas that were not covered by ice were subject to increased rainfall as indicated by wet-climate paleosols. River systems eroded deeper channels in response to sea-level drop during glacial advance. Marine facies to the west contain iceborne dropstone boulders preserved within contemporaneous units of the Cleveland Shale Member of the Ohio Shale.The stratigraphic interval correlative with sea-level drop, climate change, and glacigenic succession represents one of the Appalachian Basin's most prolific oil-and gas-producing intervals and is contemporaneous with a global episode of sea-level drop responsible for the deposition of the Hangenberg Shale/Sandstone of Europe. This interval records the Hangenberg biotic crisis near the Devonian-Carboniferous boundary. ?? 2009 Geological Society of America.

Impact of Oxidative Dissolution on Black Shale Fracturing: Implication for Shale Fracturing Treatment Design

NASA Astrophysics Data System (ADS)

You, L.; Chen, Q.; Kang, Y.; Cheng, Q.; Sheng, J.

2017-12-01

Black shales contain a large amount of environment-sensitive compositions, e.g., clay minerals, carbonate, siderite, pyrite, and organic matter. There have been numerous studies on the black shales compositional and pore structure changes caused by oxic environments. However, most of the studies did not focus on their ability to facilitate shale fracturing. To test the redox-sensitive aspects of shale fracturing and its potentially favorable effects on hydraulic fracturing in shale gas reservoirs, the induced microfractures of Longmaxi black shales exposed to deionized water, hydrochloric acid, and hydrogen peroxide at room-temperature for 240 hours were imaged by scanning electron microscopy (SEM) and CT-scanning in this paper. Mineral composition, acoustic emission, swelling, and zeta potential of the untreated and oxidative treatment shale samples were also recorded to decipher the coupled physical and chemical effects of oxidizing environments on shale fracturing processes. Results show that pervasive microfractures (Fig.1) with apertures ranging from tens of nanometers to tens of microns formed in response to oxidative dissolution by hydrogen peroxide, whereas no new microfracture was observed after the exposure to deionized water and hydrochloric acid. The trajectory of these oxidation-induced microfractures was controlled by the distribution of phyllosilicate framework and flaky or stringy organic matter in shale. The experiments reported in this paper indicate that black shales present the least resistance to crack initiation and subcritical slow propagation in hydrogen peroxide, a process we refer to as oxidation-sensitive fracturing, which are closely related to the expansive stress of clay minerals, dissolution of redox-sensitive compositions, destruction of phyllosilicate framework, and the much lower zeta potential of hydrogen peroxide solution-shale system. It could mean that the injection of fracturing water with strong oxidizing aqueous solution may play an important role in improving hydraulic fracturing of shale formation by reducing the energy requirements for crack growth. However, additional work is needed to the selection of highly-effective, economical, and environmentally friendly oxidants.

Fracture-permeability behavior of shale

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

Carey, J. William; Lei, Zhou; Rougier, Esteban

The fracture-permeability behavior of Utica shale, an important play for shale gas and oil, was investigated using a triaxial coreflood device and X-ray tomography in combination with finite-discrete element modeling (FDEM). Fractures generated in both compression and in a direct-shear configuration allowed permeability to be measured across the faces of cylindrical core. Shale with bedding planes perpendicular to direct-shear loading developed complex fracture networks and peak permeability of 30 mD that fell to 5 mD under hydrostatic conditions. Shale with bedding planes parallel to shear loading developed simple fractures with peak permeability as high as 900 mD. In addition tomore » the large anisotropy in fracture permeability, the amount of deformation required to initiate fractures was greater for perpendicular layering (about 1% versus 0.4%), and in both cases activation of existing fractures are more likely sources of permeability in shale gas plays or damaged caprock in CO₂ sequestration because of the significant deformation required to form new fracture networks. FDEM numerical simulations were able to replicate the main features of the fracturing processes while showing the importance of fluid penetration into fractures as well as layering in determining fracture patterns.« less

Fracture-permeability behavior of shale

DOE PAGES

Carey, J. William; Lei, Zhou; Rougier, Esteban; ...

2015-05-08

The fracture-permeability behavior of Utica shale, an important play for shale gas and oil, was investigated using a triaxial coreflood device and X-ray tomography in combination with finite-discrete element modeling (FDEM). Fractures generated in both compression and in a direct-shear configuration allowed permeability to be measured across the faces of cylindrical core. Shale with bedding planes perpendicular to direct-shear loading developed complex fracture networks and peak permeability of 30 mD that fell to 5 mD under hydrostatic conditions. Shale with bedding planes parallel to shear loading developed simple fractures with peak permeability as high as 900 mD. In addition tomore » the large anisotropy in fracture permeability, the amount of deformation required to initiate fractures was greater for perpendicular layering (about 1% versus 0.4%), and in both cases activation of existing fractures are more likely sources of permeability in shale gas plays or damaged caprock in CO₂ sequestration because of the significant deformation required to form new fracture networks. FDEM numerical simulations were able to replicate the main features of the fracturing processes while showing the importance of fluid penetration into fractures as well as layering in determining fracture patterns.« less

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.

Record of the Late Devonian Hangenberg global positive carbon-isotope excursion in an epeiric sea setting: Carbonate production, organic-carbon burial and paleoceanography during the late Famennian

USGS Publications Warehouse

Cramer, Bradley D.; Saltzman, Matthew R.; Day, J.E.; Witzke, B.J.

2008-01-01

Latest Famennian marine carbonates from the mid-continent of North America were examined to investigate the Late Devonian (very late Famennian) Hangenberg positive carbon-isotope (??13 Ccarb) excursion. This global shift in the ?? 13C of marine waters began during the late Famennian Hangenberg Extinction Event that occurred during the Middle Siphonodella praesulcata conodont zone. The post-extinction recovery interval spans the Upper S. praesulcata Zone immediately below the Devonian-Carboniferous boundary. Positive excursions in ?? 13 Ccarb are often attributed to the widespread deposition of organic-rich black shales in epeiric sea settings. The Hangenberg ??13 Ccarb excursion documented in the Louisiana Limestone in this study shows the opposite trend, with peak ??13 Ccarb values corresponding to carbonate production in the U.S. mid-continent during the highstand phase of the very late Famennian post-glacial sea level rise. Our data indicate that the interval of widespread black shale deposition (Hangenberg Black Shale) predates the peak isotope values of the Hangenberg ??13 Ccarb excursion and that peak values of the Hangenberg excursion in Missouri are not coincident with and cannot be accounted for by high Corg burial in epeiric seas. We suggest instead that sequestration and burial of Corg in the deep oceans drove the peak interval of the ??13Ccarb excursion, as a result of a change in the site of deep water formation to low-latitude epeiric seas as the global climate shifted between cold and warm states.

Stress dependence of permeability of intact and fractured shale cores.

NASA Astrophysics Data System (ADS)

van Noort, Reinier; Yarushina, Viktoriya

2016-04-01

Whether a shale acts as a caprock, source rock, or reservoir, understanding fluid flow through shale is of major importance for understanding fluid flow in geological systems. Because of the low permeability of shale, flow is thought to be largely confined to fractures and similar features. In fracking operations, fractures are induced specifically to allow for hydrocarbon exploration. We have constructed an experimental setup to measure core permeabilities, using constant flow or a transient pulse. In this setup, we have measured the permeability of intact and fractured shale core samples, using either water or supercritical CO2 as the transporting fluid. Our measurements show decreasing permeability with increasing confining pressure, mainly due to time-dependent creep. Furthermore, our measurements show that for a simple splitting fracture, time-dependent creep will also eliminate any significant effect of this fracture on permeability. This effect of confinement on fracture permeability can have important implications regarding the effects of fracturing on shale permeability, and hence for operations depending on that.

Distribution and variation of the inorganic fraction of Devonian to Bashkirian black shales in the north-western part of the Dniepr-Donets Basin, Ukraine

NASA Astrophysics Data System (ADS)

Wegerer, Eva; Sachsenhofer, Reinhard; Misch, David; Aust, Nicolai

2016-04-01

Mineralogical data of 112 core samples from 12 wells are used to investigate lateral and vertical variations in the lithofacies of Devonian to Bashkirian black shales in the north-western part of the Dniepr-Donets-Basin. Sulphur and carbonate contents as well as organic geochemical parameters, including TOC and Hydrogen Index have been determined on the same sample set within the frame of an earlier study (Sachsenhofer et al. 2010). This allows the correlation of inorganic and organic composition of the black shales. Aims of the study are to distinguish between detrital and authigenic minerals, to relate the lithofacies of the black shales with the tectono-stratigraphic sequences of the Dniepr-Donets Basin, to contribute to the reconstruction of the depositional environment and to relate diagenetic processes with the thermal history of the basin. Mineral compositions were determined primarily using XRD-measurements applying several measurement procedures, e.g. chemical and temperature treatment, and specific standards. Major differences exist in the mineralogical composition of the black shales. For example, clay mineral contents range from less than 20 to more than 80 Vol%. Kaolinite contents are significantly higher in rocks with a Tournaisian or Early Visean age than in any other stratigraphic unit. This is also true for two Lower Visean coal samples from the shallow north-westernmost part of the basin. Chlorite contents reach maxima in uppermost Visean and overlying rocks. Quartz contents are often high in Upper Visean rocks and reach maxima in Bashkirian units. Feldspar-rich rocks are observed in Devonian sediments from the north-western part of the study area and may reflect the proximity to a sediment source. Carbonate contents are typically low, but reach very high values in some Tournaisian, Lower Visean and Serpukhovian samples. Pyrite contents reach maxima along the basin axis in Tournaisian and Visean rocks reflecting anoxic conditions. Mixed layer minerals are dominated by illite. Their presence in samples from depth exceeding 5 km reflects the low thermal overprint of Paleozoic rocks in the north-western Dniepr-Donets-Basin.

Shale Gas Well, Hydraulic Fracturing, and Formation Data to Support Modeling of Gas and Water Flow in Shale Formations

NASA Astrophysics Data System (ADS)

Edwards, Ryan W. J.; Celia, Michael A.

2018-04-01

The potential for shale gas development and hydraulic fracturing to cause subsurface water contamination has prompted a number of modeling studies to assess the risk. A significant impediment for conducting robust modeling is the lack of comprehensive publicly available information and data about the properties of shale formations, shale wells, the process of hydraulic fracturing, and properties of the hydraulic fractures. We have collated a substantial amount of these data that are relevant for modeling multiphase flow of water and gas in shale gas formations. We summarize these data and their sources in tabulated form.

Mixed integer simulation optimization for optimal hydraulic fracturing and production of shale gas fields

NASA Astrophysics Data System (ADS)

Li, J. C.; Gong, B.; Wang, H. G.

2016-08-01

Optimal development of shale gas fields involves designing a most productive fracturing network for hydraulic stimulation processes and operating wells appropriately throughout the production time. A hydraulic fracturing network design-determining well placement, number of fracturing stages, and fracture lengths-is defined by specifying a set of integer ordered blocks to drill wells and create fractures in a discrete shale gas reservoir model. The well control variables such as bottom hole pressures or production rates for well operations are real valued. Shale gas development problems, therefore, can be mathematically formulated with mixed-integer optimization models. A shale gas reservoir simulator is used to evaluate the production performance for a hydraulic fracturing and well control plan. To find the optimal fracturing design and well operation is challenging because the problem is a mixed integer optimization problem and entails computationally expensive reservoir simulation. A dynamic simplex interpolation-based alternate subspace (DSIAS) search method is applied for mixed integer optimization problems associated with shale gas development projects. The optimization performance is demonstrated with the example case of the development of the Barnett Shale field. The optimization results of DSIAS are compared with those of a pattern search algorithm.

On the possibility of magnetic nano-markers use for hydraulic fracturing in shale gas mining

NASA Astrophysics Data System (ADS)

Zawadzki, Jaroslaw; Bogacki, Jan

2016-04-01

Recently shale gas production became essential for the global economy, thanks to fast advances in shale fracturing technology. Shale gas extraction can be achieved by drilling techniques coupled with hydraulic fracturing. Further increasing of shale gas production is possible by improving the efficiency of hydraulic fracturing and assessing the spatial distribution of fractures in shale deposits. The latter can be achieved by adding magnetic markers to fracturing fluid or directly to proppant, which keeps the fracture pathways open. After that, the range of hydraulic fracturing can be assessed by measurement of vertical and horizontal component of earth's magnetic field before and after fracturing. The difference in these components caused by the presence of magnetic marker particles may allow to delineate spatial distribution of fractures. Due to the fact, that subterranean geological formations may contain minerals with significant magnetic properties, it is important to provide to the markers excellent magnetic properties which should be also, independent of harsh chemical and geological conditions. On the other hand it is of great significance to produce magnetic markers at an affordable price because of the large quantities of fracturing fluids or proppants used during shale fracturing. Examining the properties of nano-materials, it was found, that they possess clearly superior magnetic properties, as compared to the same structure but having a larger particle size. It should be then possible, to use lower amount of magnetic marker, to obtain the same effect. Although a research on properties of new magnetic nano-materials is very intensive, cheap magnetic nano-materials are not yet produced on a scale appropriate for shale gas mining. In this work we overview, in detail, geological, technological and economic aspects of using magnetic nano-markers in shale gas mining. Acknowledgment This work was supported by the NCBiR under Grant "Electromagnetic method to estimate penetration of proppant in the fracturing process".

Petrographic maturity parameters of a Devonian shale maturation series, Appalachian Basin, USA. ICCP Thermal Indices Working Group interlaboratory exercise

USGS Publications Warehouse

Araujo, Carla Viviane; Borrego, Angeles G.; Cardott, Brian; das Chagas, Renata Brenand A.; Flores, Deolinda; Goncalves, Paula; Hackley, Paul C.; Hower, James C.; Kern, Marcio Luciano; Kus, Jolanta; Mastalerz, Maria; Filho, João Graciano Mendonça; de Oliveira Mendonça, Joalice; Rego Menezes, Taissa; Newman, Jane; Suarez-Ruiz, Isabel; Sobrinho da Silva, Frederico; Viegas de Souza, Igor

2014-01-01

This paper presents results of an interlaboratory exercise on organic matter optical maturity parameters using a natural maturation series comprised by three Devonian shale samples (Huron Member, Ohio Shale) from the Appalachian Basin, USA. This work was conducted by the Thermal Indices Working Group of the International Committee for Coal and Organic Petrology (ICCP) Commission II (Geological Applications of Organic Petrology). This study aimed to compare: 1. maturation predicted by different types of petrographic parameters (vitrinite reflectance and spectral fluorescence of telalginite), 2. reproducibility of the results for these maturation parameters obtained by different laboratories, and 3. improvements in the spectral fluorescence measurement obtained using modern detection systems in comparison with the results from historical round robin exercises.Mean random vitrinite reflectance measurements presented the highest level of reproducibility (group standard deviation 0.05) for low maturity and reproducibility diminished with increasing maturation (group standard deviation 0.12).Corrected fluorescence spectra, provided by 14 participants, showed a fair to good correspondence. Standard deviation of the mean values for spectral parameters was lowest for the low maturity sample but was also fairly low for higher maturity samples.A significant improvement in the reproducibility of corrected spectral fluorescence curves was obtained in the current exercise compared to a previous investigation of Toarcian organic matter spectra in a maturation series from the Paris Basin. This improvement is demonstrated by lower values of standard deviation and is interpreted to reflect better performance of newer photo-optical measuring systems.Fluorescence parameters measured here are in good agreement with vitrinite reflectance values for the least mature shale but indicate higher maturity than shown by vitrinite reflectance for the two more mature shales. This red shift in λmax beyond 0.65% vitrinite reflectance was also observed in studies of Devonian shale in other basins, suggesting that the accepted correlation for these two petrographic thermal maturity parameters needs to be re-evaluated.A good linear correlation between λmax and Tmax for this maturation series was observed and λmax 600 nm corresponds to Tmax of 440 °C. Nevertheless if a larger set of Devonian samples is included, the correlation is polynomial with a jump in λmax ranging from 540 to 570 nm. Up to 440 °C of Tmax, the λmax, mostly, reaches up to 500 nm; beyond a Tmax of 440 °C, λmax is in the range of 580–600 nm. This relationship places the “red shift” when the onset of the oil window is reached at Tmax of 440 °C. Moreover, the correlation between HI and λmax (r2 = 0.70) shows a striking inflection and decrease in HI above a λmax of 600 nm, coincident with the approximate onset of hydrocarbon generation in these rocks.

Laboratory investigation of shale rock to identify fracture propagation in vertical direction to bedding

NASA Astrophysics Data System (ADS)

Peng, Tan; Yan, Jin; Bing, Hou; Yingcao, Zhou; Ruxin, Zhang; Zhi, Chang; Meng, Fan

2018-06-01

Affected by beddings and natural fractures, fracture geometry in the vertical plane is complex in shale formation, which differs from a simple fracture in homogeneous sandstone reservoirs. However, the propagation mechanism of a hydraulic fracture in the vertical plane has not been well understood. In this paper, a true tri-axial pressure machine was deployed for shale horizontal well fracturing simulation experiments of shale outcrops. The effects of multiple factors on hydraulic fracture vertical propagation were studied. The results revealed that hydraulic fracture initiation and propagation displayed four basic patterns in the vertical plane of laminated shale formation. A hydraulic fracture would cross the beddings under the high vertical stress difference between a vertical stress and horizontal minimum stress of 12 MPa, while a hydraulic fracture propagates along the beddings under a low vertical stress difference of 3 MPa. Four kinds of fracture geometry, including a single main fracture, a nonplanar fracture, a complex fracture, and a complex fracture network, were observed due to the combined effects of flow rate and viscosity. Due to the influence of binding strength (or cementing strength) on the fracture communication effects between a hydraulic fracture and the beddings, the opening region of the beddings takes the shape of an ellipse.

Discovering Fossils--A Hands-on Lab.

ERIC Educational Resources Information Center

Goldstein, Alan

2002-01-01

Describes fossil investigations developed and provided by the Falls of the Ohio State Park near Louisville, Kentucky. The Devonian shale beds contain representatives of over 600 species including corals, sponges, brachiopods, mollusks, and echinoderms. Rather than focusing on identification, the activities emphasize the past ecological…

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.

Fractures system within Qusaiba shale outcrop and its relationship to the lithological properties, Qasim area, Central Saudi Arabia

NASA Astrophysics Data System (ADS)

Ibrahim, Mohamed I. M.; Hariri, Mustafa M.; Abdullatif, Osman M.; Makkawi, Mohammad H.; Elzain, Hussam

2017-09-01

The basal Qusaiba hot shale member of Qalibah Formation is considered to be an important source rock in the Paleozoic petroleum system of Saudi Arabia and an exploration target for tight shale as one of the Unconventional resources of petroleum. This work has been carried out to understand the fractures network of Qusaiba shale member in outcrops located to the west of Qusayba' village in Al-Qasim area, Central Saudi Arabia. The main objective of this study is to understand the distribution of natural fractures over different lithological units. Description data sheets were used for the detailed lithological description of Qusaiba shale member on two outcrops. Spot-7 and Landsat ETM+ satellite images were used for lineament mapping and analyses on a regional scale in a GIS environment. Fractures characterization in outcrop-scale was conducted by using linear scanline method. Qusaiba shale member in the study area consists of 5 main lithofacies, divided based on their sedimentary structures and petrographical properties, from base to top in the outcrops, the lithofacies are; fissile shale, very fine-grained micaceous siltstone, bioturbated mudstone, very fine to fine-grained hummocky cross-stratified sandstone, and fine to medium-grained low/high angle cross-stratified sandstone lithofacies. Lineaments interpretation of the Spot-7 and Landsat ETM+ satellite images showed two major directions in the study area; 320° that could be related to Najd fault system and 20° that could be related to the extensional activities which took place after Amar collision. Fractures are much denser in the fissile shale and mudstone lithofacies than sandstones lithofacies, and average spacing is smaller in the fissile shale and mudstone lithofacies than sandstones lithofacies. Lineaments and large-scale fractures are Non-Stratabound fractures and they deal with the area as one big mechanical unit, but small-scale fractures are Stratabound fractures that propose different mechanical units within Qusaiba shale member in the study area. The fractures network in the study area has a wide range of properties related to fractures density, length, spacing, height, and termination degree. The conceptual multi-scale model divides the fractures in the study area into 4 orders depending on the available data that have been observed from satellite images and field. The multi-scale fractures model that was generated in this study could help to understand the distribution of stratigraphically controlled fractures when integrated with flow simulation models. Overall, this work could have a significant contribution to tight shale exploration plans in the subsurface by providing some knowledge about the fractures mechanical behavior of the lower part of Qusaiba shale member of Qalibah Formation.

Mineral Reactions in Shale Gas Reservoirs: Barite Scale Formation from Reusing Produced Water As Hydraulic Fracturing Fluid.

PubMed

Paukert Vankeuren, Amelia N; Hakala, J Alexandra; Jarvis, Karl; Moore, Johnathan E

2017-08-15

Hydraulic fracturing for gas production is now ubiquitous in shale plays, but relatively little is known about shale-hydraulic fracturing fluid (HFF) reactions within the reservoir. To investigate reactions during the shut-in period of hydraulic fracturing, experiments were conducted flowing different HFFs through fractured Marcellus shale cores at reservoir temperature and pressure (66 °C, 20 MPa) for one week. Results indicate HFFs with hydrochloric acid cause substantial dissolution of carbonate minerals, as expected, increasing effective fracture volume (fracture volume + near-fracture matrix porosity) by 56-65%. HFFs with reused produced water composition cause precipitation of secondary minerals, particularly barite, decreasing effective fracture volume by 1-3%. Barite precipitation occurs despite the presence of antiscalants in experiments with and without shale contact and is driven in part by addition of dissolved sulfate from the decomposition of persulfate breakers in HFF at reservoir conditions. The overall effect of mineral changes on the reservoir has yet to be quantified, but the significant amount of barite scale formed by HFFs with reused produced water composition could reduce effective fracture volume. Further study is required to extrapolate experimental results to reservoir-scale and to explore the effect that mineral changes from HFF interaction with shale might have on gas production.

4D synchrotron X-ray imaging to understand porosity development in shales during exposure to hydraulic fracturing fluid

NASA Astrophysics Data System (ADS)

Kiss, A. M.; Bargar, J.; Kohli, A. H.; Harrison, A. L.; Jew, A. D.; Lim, J. H.; Liu, Y.; Maher, K.; Zoback, M. D.; Brown, G. E.

2016-12-01

Unconventional (shale) reservoirs have emerged as the most important source of petroleum resources in the United States and represent a two-fold decrease in greenhouse gas emissions compared to coal. Despite recent progress, hydraulic fracturing operations present substantial technical, economic, and environmental challenges, including inefficient recovery, wastewater production and disposal, contaminant and greenhouse gas pollution, and induced seismicity. A relatively unexplored facet of hydraulic fracturing operations is the fluid-rock interface, where hydraulic fracturing fluid (HFF) contacts shale along faults and fractures. Widely used, water-based fracturing fluids contain oxidants and acid, which react strongly with shale minerals. Consequently, fluid injection and soaking induces a host of fluid-rock interactions, most notably the dissolution of carbonates and sulfides, producing enhanced or "secondary" porosity networks, as well as mineral precipitation. The competition between these mechanisms determines how HFF affects reactive surface area and permeability of the shale matrix. The resultant microstructural and chemical changes may also create capillary barriers that can trap hydrocarbons and water. A mechanistic understanding of the microstructure and chemistry of the shale-HFF interface is needed to design new methodologies and fracturing fluids. Shales were imaged using synchrotron micro-X-ray computed tomography before, during, and after exposure to HFF to characterize changes to the initial 3D structure. CT reconstructions reveal how the secondary porosity networks advance into the shale matrix. Shale samples span a range of lithologies from siliceous to calcareous to organic-rich. By testing shales of different lithologies, we have obtained insights into the mineralogic controls on secondary pore network development and the morphologies at the shale-HFF interface and the ultimate composition of produced water from different facies. These results show that mineral texture is a major control over secondary porosity network morphology.

Causes of the great mass extinction of marine organisms in the Late Devonian

NASA Astrophysics Data System (ADS)

Barash, M. S.

2016-11-01

The second of the five great mass extinctions of the Phanerozoic occurred in the Late Devonian. The number of species decreased by 70-82%. Major crises occurred at the Frasnian-Famennian and Devonian-Carboniferous boundary. The lithological and geochemical compositions of sediments, volcanic deposits, impactites, carbon and oxygen isotope ratios, evidence of climate variability, and sea level changes reflect the processes that led the critical conditions. Critical intervals are marked by layers of black shales, which were deposited in euxinic or anoxic environments. These conditions were the main direct causes of the extinctions. The Late Devonian mass extinction was determined by a combination of impact events and extensive volcanism. They produced similar effects: emissions of harmful chemical compounds and aerosols to cause greenhouse warming; darkening of the atmosphere, which prevented photosynthesis; and stagnation of oceans and development of anoxia. Food chains collapsed and biological productivity decreased. As a result, all vital processes were disturbed and a large portion of the biota became extinct.

Coupled Fracture and Flow in Shale in Hydraulic Fracturing

NASA Astrophysics Data System (ADS)

Carey, J. W.; Mori, H.; Viswanathan, H.

2014-12-01

Production of hydrocarbon from shale requires creation and maintenance of fracture permeability in an otherwise impermeable shale matrix. In this study, we use a combination of triaxial coreflood experiments and x-ray tomography characterization to investigate the fracture-permeability behavior of Utica shale at in situ reservoir conditions (25-50 oC and 35-120 bars). Initially impermeable shale core was placed between flat anvils (compression) or between split anvils (pure shear) and loaded until failure in the triaxial device. Permeability was monitored continuously during this process. Significant deformation (>1%) was required to generate a transmissive fracture system. Permeability generally peaked at the point of a distinct failure event and then dropped by a factor of 2-6 when the system returned to hydrostatic failure. Permeability was very small in compression experiments (< 1 mD), possibly because of limited fracture connectivity through the anvils. In pure share experiments, shale with bedding planes perpendicular to shear loading developed complex fracture networks with narrow apertures and peak permeability of 30 mD. Shale with bedding planes parallel to shear loading developed simple fractures with large apertures and a peak permeability as high as 1 D. Fracture systems held at static conditions for periods of several hours showed little change in effective permeability at hydrostatic conditions as high as 140 bars. However, permeability of fractured systems was a function of hydrostatic pressure, declining in a pseudo-linear, exponential fashion as pressure increased. We also observed that permeability decreased with increasing fluid flow rate indicating that flow did not follow Darcy's Law, possibly due to non-laminar flow conditions, and conformed to Forscheimer's law. The coupled deformation and flow behavior of Utica shale, particularly the large deformation required to initiate flow, indicates the probable importance of activation of existing fractures in hydraulic fracturing and that these fractures can have adequate permeability for the production of hydrocarbon.

Enhanced recovery of unconventional gas. Volume II. The program. [Tight gas basins; Devonian shale; coal seams; geopressured aquifers

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

Kuuskraa, V.A.; Brashear, J.P.; Doscher, T.M.

1978-10-01

This study was conducted to assist public decision-makers in selecting among many choices to obtain new gas supplies by addressing 2 questions: 1) how severe is the need for additional future supplies of natural gas, and what is the economic potential of providing part of future supply through enhanced recovery from unconventional natural gas resources. The study also serves to assist the DOE in designing a cost-effective R and D program to stimulate industry to recover this unconventional gas and to produce it sooner. Tight gas basins, Devonian shale, methane from coal seams, and methane from geopressured aquifers are considered.more » It is concluded that unconventional sources, already providing about 1 Tcf per year, could provide from 3 to 4 Tcf in 1985 and from 6 to 8 Tcf in 1990 (at $1.75 and $3.00 per Mcf, respectively). However, even with these additions to supply, gas supply is projected to remain below 1977 usage levels. (DLC)« less

Petrology and sedimentology of the Horlick Formation (Lower Devonian), Ohio Range, Transantarctic Mountains

USGS Publications Warehouse

McCartan, Lucy; Bradshaw, Margaret A.

1987-01-01

The Horlick Formation of Early Devonian age is as thick as 50 m and consists of subhorizontal, interbedded subarkosic sandstone and chloritic shale and mudstone. The Horlick overlies an erosion surface cut into Ordovician granitic rocks and is, in turn, overlain by Carboniferous and Permian glacial and periglacial deposits. Textures, sedimentary structures, and ubiquitous marine body fossils and animal traces suggest that the Horlick was deposited on a shallow shelf having moderate wave energy and a moderate tidal range. The source terrane probably lay to the north, and longshore transport was toward the west.

A Theoretical Investigation of Radial Lateral Wells with Shockwave Completion in Shale Gas Reservoirs

NASA Astrophysics Data System (ADS)

Shan, Jia

As its role in satisfying the energy demand of the U.S. and as a clean fuel has become more significant than ever, the shale gas production in the U.S. has gained increasing momentum over recent years. Thus, effective and environmentally friendly methods to extract shale gas are critical. Hydraulic fracturing has been proven to be efficient in the production of shale gas. However, environmental issues such as underground water contamination and high usage of water make this technology controversial. A potential technology to eliminate the environmental issues concerning water usage and contamination is to use blast fracturing, which uses explosives to create fractures. It can be further aided by HEGF and multi-pulse pressure loading technology, which causes less crushing effect near the wellbore and induces longer fractures. Radial drilling is another relatively new technology that can bypass damage zones due to drilling and create a larger drainage area through drilling horizontal wellbores. Blast fracturing and radial drilling both have the advantage of cost saving. The successful combination of blast fracturing and radial drilling has a great potential for improving U.S. shale gas production. An analytical productivity model was built in this study, considering linear flow from the reservoir rock to the fracture face, to analyze factors affecting shale gas production from radial lateral wells with shockwave completion. Based on the model analyses, the number of fractures per lateral is concluded to be the most effective factor controlling the productivity index of blast-fractured radial lateral wells. This model can be used for feasibility studies of replacing hydraulic fracturing by blast fracturing in shale gas well completions. Prediction of fracture geometry is recommended for future studies.

Microfractures in bed-parallel veins (beef) as predictors of vertical macrofractures in shale: Vaca Muerta Formation, Agrio Fold-and-Thrust Belt, Argentina

NASA Astrophysics Data System (ADS)

Ukar, Estibalitz; Lopez, Ramiro G.; Laubach, Stephen E.; Gale, Julia F. W.; Manceda, René; Marrett, Randall

2017-11-01

Shales of the Upper Jurassic-Lower Cretaceous Vaca Muerta Formation are the main source rock for petroleum in the Neuquén Basin, Argentina and an important unconventional exploration target. Folded Vaca Muerta Formation is well exposed in the Agrio Fold-and-Thrust belt where an arid climate and rapid erosion reveal relatively unweathered shale strata accessible along creek beds at Arroyo Mulichinco and in 10+ m-tall cliffs at Puesto. Widespread within these organic-rich shales are several cm-thick, prominent bed-parallel veins (BPVs) of fibrous calcite (beef) that are cut by multiple sets of vertical calcite lined or filled fractures having apertures unaffected by near-surface stress release. Similar, and probably contemporaneous fractures are present within horizons of interbedded dolomitic rock. Evidence that vertical fractures in BPVs and dolomitic horizons continue into shale beds suggests that in-depth analysis of vertical fractures within BPVs and dolomitic horizons allows fracture set and orientation identification and size population measurements-primarily aperture distributions-that circumvent some of the limitations of shale outcrops. At Arroyo Mulichinco, four main fracture sets are present separable by orientation and crosscutting relations. An E-W set is oldest, followed by successively younger NE-SW, NW-SE, and N-S sets. At Puesto, the E-W and N-S sets are the most prominent and show opposite cross-cutting relationships (E-W set is youngest) indicating a possible episode of younger E-W fractures. The E-W set shows the highest micro-and macrofracture intensity at both localities. The intensity of N-S micro- and macrofractures is similar at both outcrops away from faults, but macrofracture intensity increases closer to faults. While macrofracture abundance is similar in BPVs and in shale, microfractures having apertures smaller than ∼0.1 mm are mostly absent in shale and dolomitic layers but are abundant cutting BPVs. Thus, microfractures are BPV-bounded and only fractures wider than ∼0.05 mm are tall enough to cut into shale. Nevertheless, using size distributions of microfractures in BPVs that are absent in shale accurately predicts the abundance of macrofractures in nearby shale, either because microfractures in organic shale have annealed, or because of only small differences in fracture strain for fractures of different sizes across different rocks types. Microfractures in readily sampled BPVs may be a practical way to diagnose or predict attributes of macrofractures in adjacent shale.

Continuous TDEM for monitoring shale hydraulic fracturing

NASA Astrophysics Data System (ADS)

Yan, Liang-Jun; Chen, Xiao-Xiong; Tang, Hao; Xie, Xing-Bing; Zhou, Lei; Hu, Wen-Bao; Wang, Zhong-Xin

2018-03-01

Monitoring and delineating the spatial distribution of shale fracturing is fundamentally important to shale gas production. Standard monitoring methods, such as time-lapse seismic, cross-well seismic and micro-seismic methods, are expensive, timeconsuming, and do not show the changes in the formation with time. The resistivities of hydraulic fracturing fluid and reservoir rocks were measured. The results suggest that the injection fluid and consequently the injected reservoir are characterized by very low resistivity and high chargeability. This allows using of the controlled-source electromagnetic method (CSEM) to monitor shale gas hydraulic fracturing. Based on the geoelectrical model which was proposed according to the well-log and seismic data in the test area the change rule of the reacted electrical field was studied to account for the change of shale resistivity, and then the normalized residual resistivity method for time lapse processing was given. The time-domain electromagnetic method (TDEM) was used to continuously monitor the shale gas fracturing at the Fulin shale gas field in southern China. A high-power transmitter and multi-channel transient electromagnetic receiver array were adopted. 9 h time series of Ex component of 224 sites which were laid out on the surface and over three fracturing stages of a horizontal well at 2800 m depth was recorded. After data processing and calculation of the normalized resistivity residuals, the changes in the Ex signal were determined and a dynamic 3D image of the change in resistivity was constructed. This allows modeling the spatial distribution of the fracturing fluid. The model results suggest that TDEM is promising for monitoring hydraulic fracturing of shale.

Where Does Water Go During Hydraulic Fracturing?

PubMed

O'Malley, D; Karra, S; Currier, R P; Makedonska, N; Hyman, J D; Viswanathan, H S

2016-07-01

During hydraulic fracturing millions of gallons of water are typically injected at high pressure into deep shale formations. This water can be housed in fractures, within the shale matrix, and can potentially migrate beyond the shale formation via fractures and/or faults raising environmental concerns. We describe a generic framework for producing estimates of the volume available in fractures and undamaged shale matrix where water injected into a representative shale site could reside during hydraulic fracturing, and apply it to a representative site that incorporates available field data. The amount of water that can be stored in the fractures is estimated by calculating the volume of all the fractures associated with a discrete fracture network (DFN) based on real data and using probability theory to estimate the volume of smaller fractures that are below the lower cutoff for the fracture radius in the DFN. The amount of water stored in the matrix is estimated utilizing two distinct methods-one using a two-phase model at the pore-scale and the other using a single-phase model at the continuum scale. Based on these calculations, it appears that most of the water resides in the matrix with a lesser amount in the fractures. Published 2015. This article is a U.S. Government work and is in the public domain in the USA.

Experimental Study and Numerical Modeling of Fracture Propagation in Shale Rocks During Brazilian Disk Test

NASA Astrophysics Data System (ADS)

Mousavi Nezhad, Mohaddeseh; Fisher, Quentin J.; Gironacci, Elia; Rezania, Mohammad

2018-06-01

Reliable prediction of fracture process in shale-gas rocks remains one of the most significant challenges for establishing sustained economic oil and gas production. This paper presents a modeling framework for simulation of crack propagation in heterogeneous shale rocks. The framework is on the basis of a variational approach, consistent with Griffith's theory. The modeling framework is used to reproduce the fracture propagation process in shale rock samples under standard Brazilian disk test conditions. Data collected from the experiments are employed to determine the testing specimens' tensile strength and fracture toughness. To incorporate the effects of shale formation heterogeneity in the simulation of crack paths, fracture properties of the specimens are defined as spatially random fields. A computational strategy on the basis of stochastic finite element theory is developed that allows to incorporate the effects of heterogeneity of shale rocks on the fracture evolution. A parametric study has been carried out to better understand how anisotropy and heterogeneity of the mechanical properties affect both direction of cracks and rock strength.

Effects of Salinity and Confining Pressure on Hydration-Induced Fracture Propagation and Permeability of Mancos Shale

NASA Astrophysics Data System (ADS)

Zhang, Shifeng; Sheng, James J.

2017-11-01

Low-salinity water imbibition was considered an enhanced recovery method in shale oil/gas reservoirs due to the resulting hydration-induced fractures, as observed at ambient conditions. To study the effect of confining pressure and salinity on hydration-induced fractures, time-elapsed computerized tomography (CT) was used to obtain cross-sectional images of shale cores. Based on the CT data of these cross-sectional images, cut faces parallel to the core axial in the middle of the core and 3D fracture images were also reconstructed. To study the effects of confining pressure and salinity on shale pore fluid flowing, shale permeability was measured with Nitrogen (N2), distilled water, 4% KCl solution, and 8% KCl solution. With confining pressures increased to 2 MPa or more, either in distilled water or in KCl solutions of different salinities, fractures were observed to close instead to propagate at the end of the tests. The intrinsic permeabilities of #1 and #2 Mancos shale cores were 60.0 and 7000 nD, respectively. When tested with distilled water, the permeability of #1 shale sample with 20.0 MPa confining pressure loaded, and #2 shale sample with 2.5 MPa confining pressure loaded, decreased to 0.45 and 15 nD, respectively. Using KCl can partly mitigate shale permeability degradation. Compared to 4% KCl, 8% KCl can decrease more permeability damage. From this point of view, high salinity KCl solution should be required for the water-based fracturing fluid.

Regional stratigraphy and petroleum potential, Ghadames basin, Algeria

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

Emme, J.J.; Sunderland, B.L.

1991-03-01

The Ghadames basin in east-central Algeria extends over 65,000 km{sup 2} (25,000 mi{sup 2}), of which 90% is covered by dunes of the eastern Erg. This intracratonic basin consists of up to 6000 m (20,000 ft) of dominantly clastic Paleozoic through Mesozoic strata. The Ghadames basin is part of a larger, composite basin complex (Ilizzi-Ghadames-Triassic basins) where Paleozoic strata have been truncated during a Hercynian erosional event and subsequently overlain by a northward-thickening wedge of Mesozoic sediments. Major reservoir rocks include Triassic sandstones that produce oil, gas, and condensate in the western Ghadames basin, Siluro-Devonian sandstones that produce mostly oilmore » in the shallower Ilizzi basin to the south, and Cambro-Ordovician orthoquartzites that produce oil at Hassi Messaoud to the northwest. Organic shales of the Silurian and Middle-Upper Devonian are considered primary source rocks. Paleozoic shales and Triassic evaporite/red bed sequences act as seals for hydrocarbon accumulations. The central Ghadames basin is underexplored, with less than one wildcat well/1700 km{sup 2} (one well/420,000 ac). Recent Devonian and Triassic oil discoveries below 3500 m (11,500 ft) indicate that deep oil potential exists. Exploration to date has concentrated on structural traps. Subcrop and facies trends indicate that potential for giant stratigraphic or combination traps exists for both Siluro-Devonian and Triassic intervals. Modern seismic acquisition and processing techniques in high dune areas can be used to successfully identify critical unconformity-bound sequences with significant stratigraphic trap potential. Advances in seismic and drilling technology combined with creative exploration should result in major petroleum discoveries in the Ghadames basin.« less

Fracture Anisotropy and Toughness in the Mancos Shale: Implications for crack-growth geometry

NASA Astrophysics Data System (ADS)

Chandler, M. R.; Meredith, P. G.; Brantut, N.; Crawford, B. R.

2013-12-01

The hydraulic fracturing of gas-shales has drawn attention to the fundamental fracture properties of shales. Fracture propagation is dependent on a combination of the in-situ stress field, the fracturing fluid and pressure, and the mechanical properties of the shale. However, shales are strongly anisotropic, and there is a general paucity of available experimental data on the anisotropic mechanical properties of shales in the scientific literature. The mode-I stress intensity factor, KI, quantifies the concentration of stress at crack tips. The Fracture Toughness of a linear elastic material is then defined as the critical value of this stress intensity factor; KIc, beyond which rapid catastrophic crack growth occurs. However, shales display significant non-linearity, which produces hysteresis during experimental cyclic loading. This allows for the calculation of a ductility coefficient using the residual displacement after successive loading cycles. From this coefficient, a ductility corrected Fracture Toughness value, KIcc can be determined. In the Mancos Shale this ductility correction can be as large as 60%, giving a Divider orientation KIcc value of 0.8 MPa.m0.5. Tensile strength and mode-I Fracture Toughness have been experimentally determined for the Mancos Shale using the Brazil Disk and Short-Rod methodologies respectively. The three principal fracture orientations; Arrester, Divider and Short-Transverse were all analysed. A significant anisotropy is observed in the tensile strength, with the Arrester value being 1.5 times higher than the Short-Transverse value. Even larger anisotropy is observed in the Fracture Toughness, with KIcc in the Divider and Arrester orientations being around 1.8 times that in the Short-Transverse orientation. For both tensile strength and fracture toughness, the Short-Transverse orientation, where the fracture propagates in the bedding plane in a direction parallel to the bedding, is found to have significantly lower values than the other two orientations. This anisotropy and variability in fracture properties is seen to cause deviation of the fracture direction during experiments on Arrester and Short-Transverse oriented samples, and can be expected to influence the geometry of propagating fractures. A comparison between the anisotropic tensile strength of the material and the crack-tip stress field in a transversely isotropic material has been used to develop a crack-tip deflection criterion in terms of the elasticity theory of cracks. This criterion suggests that a small perturbation in the incident angle of a mode-I crack propagating perpendicular to the bedding is likely to lead to a substantial deflection towards bedding-parallel (Short-Transverse) propagation. Further experimental work is currently underway on anisotropic Fracture Toughness measurements at elevated pressures and temperatures, simulating conditions in Shale Gas reservoirs at depths up to around 4km.

Study on fracture identification of shale reservoir based on electrical imaging logging

NASA Astrophysics Data System (ADS)

Yu, Zhou; Lai, Fuqiang; Xu, Lei; Liu, Lin; Yu, Tong; Chen, Junyu; Zhu, Yuantong

2017-05-01

In recent years, shale gas exploration has made important development, access to a major breakthrough, in which the study of mud shale fractures is extremely important. The development of fractures has an important role in the development of gas reservoirs. Based on the core observation and the analysis of laboratory flakes and laboratory materials, this paper divides the lithology of the shale reservoirs of the XX well in Zhanhua Depression. Based on the response of the mudstone fractures in the logging curve, the fracture development and logging Response to the relationship between the conventional logging and electrical imaging logging to identify the fractures in the work, the final completion of the type of fractures in the area to determine and quantify the calculation of fractures. It is concluded that the fracture type of the study area is high and the microstructures are developed from the analysis of the XX wells in Zhanhua Depression. The shape of the fractures can be clearly seen by imaging logging technology to determine its type.

The Shear Mechanisms of Natural Fractures during the Hydraulic Stimulation of Shale Gas Reservoirs.

PubMed

Zhang, Zhaobin; Li, Xiao

2016-08-23

The shearing of natural fractures is important in the permeability enhancement of shale gas reservoirs during hydraulic fracturing treatment. In this work, the shearing mechanisms of natural fractures are analyzed using a newly proposed numerical model based on the displacement discontinuities method. The fluid-rock coupling system of the model is carefully designed to calculate the shearing of fractures. Both a single fracture and a complex fracture network are used to investigate the shear mechanisms. The investigation based on a single fracture shows that the non-ignorable shearing length of a natural fracture could be formed before the natural fracture is filled by pressurized fluid. Therefore, for the hydraulic fracturing treatment of the naturally fractured shale gas reservoirs, the shear strength of shale is generally more important than the tensile strength. The fluid-rock coupling propagation processes of a complex fracture network are simulated under different crustal stress conditions and the results agree well with those of the single fracture. The propagation processes of complex fracture network show that a smaller crustal stress difference is unfavorable to the shearing of natural fractures, but is favorable to the formation of complex fracture network.

The Shear Mechanisms of Natural Fractures during the Hydraulic Stimulation of Shale Gas Reservoirs

PubMed Central

Zhang, Zhaobin; Li, Xiao

2016-01-01

The shearing of natural fractures is important in the permeability enhancement of shale gas reservoirs during hydraulic fracturing treatment. In this work, the shearing mechanisms of natural fractures are analyzed using a newly proposed numerical model based on the displacement discontinuities method. The fluid-rock coupling system of the model is carefully designed to calculate the shearing of fractures. Both a single fracture and a complex fracture network are used to investigate the shear mechanisms. The investigation based on a single fracture shows that the non-ignorable shearing length of a natural fracture could be formed before the natural fracture is filled by pressurized fluid. Therefore, for the hydraulic fracturing treatment of the naturally fractured shale gas reservoirs, the shear strength of shale is generally more important than the tensile strength. The fluid-rock coupling propagation processes of a complex fracture network are simulated under different crustal stress conditions and the results agree well with those of the single fracture. The propagation processes of complex fracture network show that a smaller crustal stress difference is unfavorable to the shearing of natural fractures, but is favorable to the formation of complex fracture network. PMID:28773834

Sulfur-, oxygen-, and carbon-isotope studies of Ag-Pb-Zn vein-breccia occurrences, sulfide-bearing concretions, and barite deposits in the north-central Brooks Range, with comparisons to shale-hosted stratiform massive sulfide deposits: A section in Geologic studies in Alaska by the U.S. Geological Survey, 1998

USGS Publications Warehouse

Kelley, Karen D.; Leach, David L.; Johnson, Craig A.

2000-01-01

Stratiform shale-hosted massive sulfide deposits, sulfidebearing concretions and vein breccias, and barite deposits are widespread in sedimentary rocks of Late Devonian to Permian age in the northern Brooks Range. All of the sulfide-bearing concretions and vein breccias are hosted in mixed continental-marine clastic rocks of the Upper Devonian to Lower Mississippian Endicott Group. The clastic rocks and associated sulfide occurrences underlie chert and shale of Mississippian-Pennsylvanian(?) age that contain large stratiform massive sulfide deposits like that at Red Dog. The relative stratigraphic position of the vein breccias, as well as previously published mineralogical, geochemical, and lead-isotope data, suggest that the vein breccias formed coevally with overlying shale-hosted massive sulfide deposits and that they may represent pathways of oreforming hydrothermal fluids. Barite deposits are hosted either in Mississippian chert and limestone (at essentially the same stratigraphic position as the shale-hosted massive sulfide deposits) or Permian chert and shale. Although most barite deposits have no associated base-metal mineralization, barite occurs with massive sulfide deposits at the Red Dog deposit.Galena and sphalerite from most vein breccias have δ34S values from –7.3 to –0.7‰ (per mil) and –5.1 to 3.6‰, respectively; sphalerite from sulfide-bearing concretions have δ34S values of 0.7 and 4.7‰. This overall range in δ34S values largely overlaps with the range previously determined for galena and sphalerite from shale-hosted massive sulfide deposits at Red Dog and Drenchwater. The Kady vein-breccia occurrence is unusual in having higher δ34S values for sphalerite (12.1 to 12.9‰) and pyrite (11.3‰), consistent with previously published values for the shale-hosted Lik deposit. The correspondence in sulfur isotopic compositions between the stratiform and vein-breccia deposits suggests that they share a common source of reduced sulfur, or derived reduced sulfur by similar geochemical processes. Most likely, the reduced sulfur was derived by biogenic sulfate reduction (BSR) or thermochemical sulfate reduction (TSR) of seawater sulfate during Devonian-Mississippian time.The δ18O values of quartz from the vein breccias are between 16.6 and 19.9‰. Using the sphalerite-galena sulfur isotopic temperature of 188°±25°C, the calulated hydrothermal fluids had δ18O values of 4.2 to 7.5‰. The calculated range of δ18O values of the fluids is similar to that of pore fluids in equilibrium with sedimentary rocks during diagenesis at 100°– 190°C.

Dissolution of cemented fractures in gas bearing shales in the context of CO2 sequestration

NASA Astrophysics Data System (ADS)

Kwiatkowski, Kamil; Szymczak, Piotr

2016-04-01

Carbon dioxide has a stronger binding than methane to the organic matter contained in the matrix of shale rocks [1]. Thus, the injection of CO2 into shale formation may enhance the production rate and total amount of produced methane, and simultaneously permanently store pumped CO2. Carbon dioxide can be injected during the initial fracking stage as CO2 based hydraulic fracturing, and/or later, as a part of enhanced gas recovery (EGR) [2]. Economic and environmental benefits makes CO2 sequestration in shales potentially very for industrial-scale operation [3]. However, the effective process requires large area of fracture-matrix interface, where CO2 and CH4 can be exchanged. Usually natural fractures, existing in shale formation, are preferentially reactivated during hydraulic fracturing, thus they considerably contribute to the flow paths in the resulting fracture system [4]. Unfortunately, very often these natural fractures are sealed by calcite [5]. Consequently the layer of calcite coating surfaces impedes exchange of gases, both CO2 and CH4, between shale matrix and fracture. In this communication we address the question whether carbonic acid, formed when CO2 is mixed with brine, is able to effectively dissolve a calcite layer present in the natural fractures. We investigate numerically fluid flow and dissolution of calcite coating in natural shale fractures, with CO2-brine mixture as a reactive fluid. Moreover, we discuss the differences between slow dissolution (driven by carbonic acid) and fast dissolution (driven by stronger hydrochloric acid) of calcite layer. We compare an impact of the flow rate and geometry of the fracture on the parameters of practical importance: available surface area, morphology of dissolution front, time scale of the dissolution, and the penetration length. We investigate whether the dissolution is sufficiently non-uniform to retain the fracture permeability, even in the absence of the proppant. The sizes of analysed fractures varying from 0.2 x 0.2 m2 up to 4 x 4 m2, together with discussion of a further upscaling, make the study relevant to the industrial applications. While the results of this study should be applicable to different shale formations throughout the world, we discuss them in the context of preparation to gas-production from Pomeranian shale basin, located in the northern Poland. [1] Mosher, K., He, J., Liu, Y., Rupp, E., & Wilcox, J. Molecular simulation of methane adsorption in micro-and mesoporous carbons with applications to coal and gas shale systems. International Journal of Coal Geology, 109, 36-44 (2013) [2] Grieser, W. V., Wheaton, W. E., Magness, W. D., Blauch, M. E., & Loghry, R, "Surface Reactive Fluid's Effect on Shale." Proceedings of the Production and Operations Symposium, 31 March-3 April 2007, Oklahoma City (SPE-106815-MS) [3] Tao, Z. and Clarens, A., Estimating the carbon sequestration capacity of shale formations using methane production rates, Environmental Science and Technology, 47, 11318-11325 (2013). [4] Zhang, X., Jeffrey, R. G., & Thiercelin, M. (2009). Mechanics of fluid-driven fracture growth in naturally fractured reservoirs with simple network geometries. Journal of Geophysical Research: Solid Earth, 114, B12406 (2009) [5] Gale, J.F., Laubach, S.E., Olson, J.E., Eichhubl, P., Fall, A. Natural fractures in shale: A review and new observations. AAPG Bulletin 98(11):2165-2216 (2014)

18 CFR 270.201 - Applicability.

Code of Federal Regulations, 2010 CFR

2010-04-01

... jurisdictional agencies for tight formation gas, occluded natural gas produced from coal seams, and natural gas produced from Devonian shale that is produced through: (1) A well the surface drilling of which began after... recompletion commenced after December 31, 1979, but before January 1, 1993, where such gas could not have been...

18 CFR 270.201 - Applicability.

Code of Federal Regulations, 2013 CFR

2013-04-01

... jurisdictional agencies for tight formation gas, occluded natural gas produced from coal seams, and natural gas produced from Devonian shale that is produced through: (1) A well the surface drilling of which began after... recompletion commenced after December 31, 1979, but before January 1, 1993, where such gas could not have been...

18 CFR 270.201 - Applicability.

Code of Federal Regulations, 2011 CFR

2011-04-01

... jurisdictional agencies for tight formation gas, occluded natural gas produced from coal seams, and natural gas produced from Devonian shale that is produced through: (1) A well the surface drilling of which began after... recompletion commenced after December 31, 1979, but before January 1, 1993, where such gas could not have been...

18 CFR 270.201 - Applicability.

Code of Federal Regulations, 2014 CFR

2014-04-01

... jurisdictional agencies for tight formation gas, occluded natural gas produced from coal seams, and natural gas produced from Devonian shale that is produced through: (1) A well the surface drilling of which began after... recompletion commenced after December 31, 1979, but before January 1, 1993, where such gas could not have been...

18 CFR 270.201 - Applicability.

Code of Federal Regulations, 2012 CFR

2012-04-01

... jurisdictional agencies for tight formation gas, occluded natural gas produced from coal seams, and natural gas produced from Devonian shale that is produced through: (1) A well the surface drilling of which began after... recompletion commenced after December 31, 1979, but before January 1, 1993, where such gas could not have been...

Observations of the release of non-methane hydrocarbons from fractured shale.

PubMed

Sommariva, Roberto; Blake, Robert S; Cuss, Robert J; Cordell, Rebecca L; Harrington, Jon F; White, Iain R; Monks, Paul S

2014-01-01

The organic content of shale has become of commercial interest as a source of hydrocarbons, owing to the development of hydraulic fracturing ("fracking"). While the main focus is on the extraction of methane, shale also contains significant amounts of non-methane hydrocarbons (NMHCs). We describe the first real-time observations of the release of NMHCs from a fractured shale. Samples from the Bowland-Hodder formation (England) were analyzed under different conditions using mass spectrometry, with the objective of understanding the dynamic process of gas release upon fracturing of the shale. A wide range of NMHCs (alkanes, cycloalkanes, aromatics, and bicyclic hydrocarbons) are released at parts per million or parts per billion level with temperature- and humidity-dependent release rates, which can be rationalized in terms of the physicochemical characteristics of different hydrocarbon classes. Our results indicate that higher energy inputs (i.e., temperatures) significantly increase the amount of NMHCs released from shale, while humidity tends to suppress it; additionally, a large fraction of the gas is released within the first hour after the shale has been fractured. These findings suggest that other hydrocarbons of commercial interest may be extracted from shale and open the possibility to optimize the "fracking" process, improving gas yields and reducing environmental impacts.

Synchrotron quantification of fracturing during maturation of shales

NASA Astrophysics Data System (ADS)

Figueroa Pilz, Fernando; Fauchille, Anne-Laure; Dowey, Patrick; Courtois, Loic; Bay, Brian; Ma, Lin; Taylor, Kevin; Mecklenburgh, Julian; Lee, Peter

2017-04-01

To understand both the hydrocarbon migration within and from shale rocks, and during hydraulic fracturing, is needed to evaluate and predict its environmental footprint. As a consequence, the time characterization of fracture networks in shale is particularly important. Time resolved synchrotron X-ray tomography was used to quantify the initiation and propagation of fractures during the simulated maturation of an organic-rich Kimmeridge Clay shale from the µm to mm scales. Scanning electron microscopy (SEM) observations were performed before and after maturation in order to compare the microstructure evolution and better understand the fracture location. Fracture and strain development during heating was quantified in 3D by Digital Volume Correlation (DVC) (Bay et al., 1999). The combination of DVC, X-Ray tomography and SEM obtained direct 4D strain measurements of the anisotropic mechanical behaviour of Kimmeridge shale with the temperature during an accelerated thermal maturation (Figueroa Pilz et al.). Such a combination has rarely been investigated in 4D at these scales in the past. In the study conditions, the results demonstrated the anisotropy in thermal expansion and the aperture fracture pathways through organic matter and clay matrix.

Comparison of organic geochemistry and metal enrichment in two black shales: Cambrian Alum Shale of Sweden and Devonian Chattanooga Shale of United States

USGS Publications Warehouse

Leventhal, J.S.

1991-01-01

In most black shales, such as the Chattanooga Shale and related shales of the eastern interior United States, increased metal and metalloid contents are generally related to increased organic carbon content, decreased sedimentation rate, organic matter type, or position in the basin. In areas where the stratigraphic equivalents of the Chattanooga Shale are deeply buried and and the organic material is thermally mature, metal contents are essentially the same as in unheated areas and correlate with organic C or S contents. This paradigm does not hold for the Cambrian Alum Shale Formation of Sweden where increased metal content does not necessarily correlate with organic matter content nor is metal enrichment necessarily related to land derived humic material because this organic matter is all of marine source. In southcentral Sweden the elements U, Mo, V, Ni, Zn, Cd and Pb are all enriched relative to average black shales but only U and Mo correlate to organic matter content. Tectonically disturbed and metamorphosed allochthonous samples of Alum Shale on the Caledonian front in western Sweden have even higher amounts for some metals (V, Ni, Zn and Ba) relative to the autochthonous shales in this area and those in southern Sweden. ?? 1991 Springer-Verlag.

Chemical analysis and geochemical associations in Devonian black shale core samples from Martin County, Kentucky; Carroll and Washington counties, Ohio; Wise County, Virginia; and Overton County, Tennessee

USGS Publications Warehouse

Leventhal, Joel S.

1979-01-01

Core samples from Devonian shales from five localities in the Appalachian Basin have been analyzed for major, minor, and trace constituents. The contents of major elements are rather similar; however, the minor constituents, organic C, S, PO4, and CO3, show variations by a factor of 10. Trace elements Mo, Ni, Cu, V, Co, U, Zn, Hg, As, and Mn show variations that can be related graphically and statistically to the minor constituents. Down-hole plots show the relationships most clearly. Mn is associated with CO3 content, the other trace elements are strongly Controlled by organic C. Amounts of organic C are generally in the range of 3-6 percent, and S is in the range of 2-5 percent. Trace-element amounts show the following general ranges (ppm, parts per million)- Co, 20-40; Cu,40-70; U, 10-40; As, 20-40, V, 150-300; Ni, 80-150; high values are as much as twice these values. The organic C was probably the concentrating agent, whereas the organic C and sulfide S created an environment for preservation or immobilization of trace elements. Closely spaced samples showing an abrupt transition in color from black to gray and gray to black shale show similar effects of trace-element changes, that is, black shale contains enhanced amounts of organic C and trace elements. Ratios of trace elements to organic C or sulfide S were relatively constant even though deposition rates varied from 10 to 300 meters in 5 million years.

Munsell color value as related to organic carbon in Devonian shale of Appalachian basin

USGS Publications Warehouse

Hosterman, J.W.; Whitlow, S.I.

1981-01-01

Comparison of Munsell color value with organic carbon content of 880 samples from 50 drill holes in Appalachian basin shows that a power curve is the best fit for the data. A color value below 3 to 3.5 indicates the presence of organic carbon but is meaningless in determining the organic carbon content because a large increase in amount of organic carbon causes only a minor decrease in color value. Above 4, the color value is one of the factors that can be used in calculating the organic content. For samples containing equal amounts of organic carbon, calcareous shale containing more than 5% calcite is darker than shale containing less than 5% calcite.-Authors

Hydraulic fracturing in shales: the spark that created an oil and gas boom

NASA Astrophysics Data System (ADS)

Olson, J. E.

2017-12-01

In the oil and gas business, one of the valued properties of a shale was its lack of flow capacity (its sealing integrity) and its propensity to provide mechanical barriers to hydraulic fracture height growth when exploiting oil and gas bearing sandstones. The other important property was the high organic content that made shale a potential source rock for oil and gas, commodities which migrated elsewhere to be produced. Technological advancements in horizontal drilling and hydraulic fracturing have turned this perspective on its head, making shale (or other ultra-low permeability rocks that are described with this catch-all term) the most prized reservoir rock in US onshore operations. Field and laboratory results have changed our view of how hydraulic fracturing works, suggesting heterogeneities like bedding planes and natural fractures can cause significant complexity in hydraulic fracture growth, resulting in induced networks of fractures whose details are controlled by factors including in situ stress contrasts, ductility contrasts in the stratigraphy, the orientation and strength of pre-existing natural fractures, injection fluid viscosity, perforation cluster spacing and effective mechanical layer thickness. The stress shadowing and stress relief concepts that structural geologists have long used to explain joint spacing and orthogonal fracture pattern development in stratified sequences are key to understanding optimal injection point spacing and promotion of more uniform length development in induced hydraulic fractures. Also, fracture interaction criterion to interpret abutting vs crossing natural fracture relationships in natural fracture systems are key to modeling hydraulic fracture propagation within natural fractured reservoirs such as shale. Scaled physical experiments provide constraints on models where the physics is uncertain. Numerous interesting technical questions remain to be answered, and the field is particularly appealing in that better geologic understanding of the stratigraphic heterogeneity and material property attributes of shale can have a direct effect on the engineering design of wellbores and stimulation treatments.

The estimation of CO2 storage potential of gas-bearing shale complex at the early stage of reservoir characterization: the case of Baltic Basin (Poland).

NASA Astrophysics Data System (ADS)

Wójcicki, Adam; Jarosiński, Marek

2017-04-01

For the stage of shale gas production, like in the USA, prediction of the CO2 storage potential in shale reservoir can be performed by dynamic modeling. We have made an attempt to estimate this potential at an early stage of shale gas exploration in the Lower Paleozoic Baltic Basin, based on data from 3,800 m deep vertical well (without hydraulic fracking stimulation), supplemented with additional information from neighboring boreholes. Such an attempt makes a sense as a first guess forecast for company that explores a new basin. In our approach, the storage capacity is build by: (1) sorption potential of organic matter, (2) open pore space and (3) potential fracture space. the sequence. our estimation is done for 120 m long shale sequence including three shale intervals enriched with organic mater. Such an interval is possible to be fracked from a single horizontal borehole as known from hydraulic fracture treatment in the other boreholes in this region. The potential for adsorbed CO2 is determined from Langmuir isotherm parameters taken from laboratory measurements in case of both CH4 and CO2 adsorption, as well as shale density and volume. CO2 has approximately three times higher sorption capacity than methane to the organic matter contained in the Baltic Basin shales. Finally, due to low permeability of shale we adopt the common assumption for the USA shale basins that the CO2 will be able to reach effectively only 10% of theoretical total sorption volume. The pore space capacity was estimated by utilizing results of laboratory measurements of dynamic capacity for pores bigger than 10 nm. It is assumed for smaller pores adsorption prevails over free gas. Similarly to solution for sorption, we have assumed that only 10 % of the tight pore space will be reached by CO2. For fracture space we have considered separately natural (tectonic-origin) and technological (potentially produced by hydraulic fracturing treatment) fractures. From fracture density profile and typical permeability of fractures under lithostatic stress we inferred negligible open space of natural fractures. Technological fracture space was calculated as an potential for hydraulic stimulation of vertical fractures until, due to elastic expansion of reservoir, the horizontal minimum stress equals the vertical one. In such a case, horizontal fractures start to open and the stimulation process gets to fail. Based on elastic anisotropy and tectonic stress differentiation, the maximum hydraulic horizontal extension was calculated for separated shale complexes. For further storage capacity we assumed that technological fracture space create primary pathway for CO2 transport is entirely accessible for the CO2. In general, the CO2 sorption capacity makes the predominant contribution and fracture space capacity is comparable or smaller than pore space contribution. When compare this with the best recognized Marcellus shale basin we can see that our calculations for the 35 m depth interval comprising formations with the higher TOC content show a slightly lower value than in the case of Marcellus.

Peeking out of the basins: looking for the Late Devonian Kellwasser Event in the open ocean in the Central Asian Orogenic Belt, southwestern Mongolia

NASA Astrophysics Data System (ADS)

Thomas, R. M., Jr.; Carmichael, S. K.; Waters, J. A.; Batchelor, C. J.

2017-12-01

Two of the top five most devastating mass extinctions in Earth's history occurred during the Late Devonian (419.2 Ma - 358.9 Ma), and are commonly associated with the black shale deposits of the Kellwasser and Hangenberg ocean anoxia events. Our understanding of these extinction events is incomplete partly due to sample bias, as 95% of the field sites studying the Late Devonian are limited to continental shelves and continental marine basins, and 77% of these sites are derived from the Euramerican paleocontinent. The Samnuuruul Formation at the Hoshoot Shiveetiin Gol locality (HSG), located in southwestern Mongolia, offers a unique opportunity to better understand global oceanic conditions during the Late Devonian. The HSG locality shows a continuous sequence of terrestrial to marine sediments on the East Junggar arc; an isolated, open-ocean island arc within the Central Asian Orogenic Belt (CAOB). Samples from this near shore locality consist of volcanogenic silts, sands and immature conglomerates as well as calc-alkalic basalt lava flows. Offshore sections contain numerous limestones with Late Devonian fossil assemblages. Preliminary biostratigraphy of the associated marine and terrestrial sequences can only constrain the section to a general Late Devonian age, but TIMS analysis of detrital zircons from volcanogenic sediments from the Samnuuruul Formation in localities 8-50 km from the site suggests a late Frasnian age (375, 376 Ma). To provide a more precise radiometric age of the HSG locality, zircon geochronology using laser ablation inductively coupled plasma mass spectrometry (LA-ICPMS) will be performed at UNC-Chapel Hill. If the HSG section crosses the Frasnian-Famennian boundary, geochemical, mineralogical, and ichnological signatures of the Kellwasser Event are expected to be preserved, if the Kellwasser Event was indeed global in scope (as suggested by Carmichael et al. (2014) for analogous sites on the West Junggar arc in the CAOB). Black shale accumulation anywhere in the CAOB would be unlikely due to the paleoenvironment and arc topography, so additional multiproxy techniques are required for recognition of the Kellwasser Event in regions such as the HSG, which are outside of the basins where they have historically been studied. Carmichael et al. (2014) Paleo3 399, 394-403.

The Impact of Mineralogy on the Geochemical Alteration of Shales During Hydraulic Fracturing Operations

NASA Astrophysics Data System (ADS)

Maher, K.; Harrison, A. L.; Jew, A. D.; Dustin, M. K.; Kiss, A. M.; Kohli, A. H.; Thomas, D.; Joe-Wong, C. M.; Brown, G. E.; Bargar, J.

2016-12-01

The extraction of oil and gas resources from low permeability shale reservoirs using hydraulic fracturing techniques has increased significantly in recent years. During hydraulic fracturing, large volumes of fluid are injected into subsurface shale formations, which drives substantial fluid-rock interaction that can release contaminants and alter rock permeability. Here, a combined experimental, imaging, and modeling approach was employed to systematically evaluate the impact of shale mineralogy on its physical and chemical alteration when exposed to fracturing fluids of different composition. Batch reactor experiments contained different shales with unique mineralogical compositions that were exposed to simulated hydraulic fracturing fluid. Experiments revealed that the balance between fluid acidity and acid neutralizing capacity of the rock was the strongest control on the evolution of fluid and rock chemistry. Carbonate mineral-rich shales rapidly recovered solution pH to circum-neutral conditions, whereas fluids in contact with carbonate mineral-poor shales remained acidic. The dissolution of shale minerals released metal contaminants, yet the precipitation of Fe(III)-bearing secondary phases helped to attenuate their release via co-precipitation or sorption. Post-reaction imaging illustrated that selective dissolution of carbonate minerals generated secondary porosity, the connectivity of which was dictated by initial carbonate distribution. Conversely, the precipitation of secondary Al- and Fe-bearing phases may occlude porosity, potentially inhibiting transport of water, contaminants, and hydrocarbons. The maturation of secondary Fe-bearing phases from amorphous to crystalline over time suggests that porosity will continue to evolve even after oxidation reactions have effectively ceased. These experiments reveal that the relative abundance and distribution of carbonate minerals is the master variable dictating both porosity alteration and contaminant release from shale formations, implying that the response of a reservoir to hydraulic fracturing can be better assessed using robust mineralogical data.

A Numerical Study of Factors Affecting Fracture-Fluid Cleanup and Produced Gas/Water in Marcellus Shale: Part II

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

Seales, Maxian B.; Dilmore, Robert; Ertekin, Turgay

Horizontal wells combined with successful multistage-hydraulic-fracture treatments are currently the most-established method for effectively stimulating and enabling economic development of gas-bearing organic-rich shale formations. Fracture cleanup in the stimulated reservoir volume (SRV) is critical to stimulation effectiveness and long-term well performance. But, fluid cleanup is often hampered by formation damage, and post-fracture well performance frequently falls to less than expectations. A systematic study of the factors that hinder fracture-fluid cleanup in shale formations can help optimize fracture treatments and better quantify long-term volumes of produced water and gas. Fracture-fluid cleanup is a complex process influenced by mutliphase flow through porousmore » media (relative permeability hysteresis, capillary pressure), reservoir-rock and -fluid properties, fracture-fluid properties, proppant placement, fracture-treatment parameters, and subsequent flowback and field operations. Changing SRV and fracture conductivity as production progresses further adds to the complexity of this problem. Numerical simulation is the best and most-practical approach to investigate such a complicated blend of mechanisms, parameters, their interactions, and subsequent effect on fracture-fluid cleanup and well deliverability. Here, a 3D, two-phase, dual-porosity model was used to investigate the effect of mutliphase flow, proppant crushing, proppant diagenesis, shut-in time, reservoir-rock compaction, gas slippage, and gas desorption on fracture-fluid cleanup and well performance in Marcellus Shale. Our findings have shed light on the factors that substantially constrain efficient fracture-fluid cleanup in gas shales, and we have provided guidelines for improved fracture-treatment designs and water management.« less

A Numerical Study of Factors Affecting Fracture-Fluid Cleanup and Produced Gas/Water in Marcellus Shale: Part II

DOE PAGES

Seales, Maxian B.; Dilmore, Robert; Ertekin, Turgay; ...

2017-04-01

Horizontal wells combined with successful multistage-hydraulic-fracture treatments are currently the most-established method for effectively stimulating and enabling economic development of gas-bearing organic-rich shale formations. Fracture cleanup in the stimulated reservoir volume (SRV) is critical to stimulation effectiveness and long-term well performance. But, fluid cleanup is often hampered by formation damage, and post-fracture well performance frequently falls to less than expectations. A systematic study of the factors that hinder fracture-fluid cleanup in shale formations can help optimize fracture treatments and better quantify long-term volumes of produced water and gas. Fracture-fluid cleanup is a complex process influenced by mutliphase flow through porousmore » media (relative permeability hysteresis, capillary pressure), reservoir-rock and -fluid properties, fracture-fluid properties, proppant placement, fracture-treatment parameters, and subsequent flowback and field operations. Changing SRV and fracture conductivity as production progresses further adds to the complexity of this problem. Numerical simulation is the best and most-practical approach to investigate such a complicated blend of mechanisms, parameters, their interactions, and subsequent effect on fracture-fluid cleanup and well deliverability. Here, a 3D, two-phase, dual-porosity model was used to investigate the effect of mutliphase flow, proppant crushing, proppant diagenesis, shut-in time, reservoir-rock compaction, gas slippage, and gas desorption on fracture-fluid cleanup and well performance in Marcellus Shale. Our findings have shed light on the factors that substantially constrain efficient fracture-fluid cleanup in gas shales, and we have provided guidelines for improved fracture-treatment designs and water management.« less

Frictional stability-permeability relationships for fractures in shales

NASA Astrophysics Data System (ADS)

Fang, Yi; Elsworth, Derek; Wang, Chaoyi; Ishibashi, Takuya; Fitts, Jeffrey P.

2017-03-01

There is wide concern that fluid injection in the subsurface, such as for the stimulation of shale reservoirs or for geological CO2 sequestration (GCS), has the potential to induce seismicity that may change reservoir permeability due to fault slip. However, the impact of induced seismicity on fracture permeability evolution remains unclear due to the spectrum of modes of fault reactivation (e.g., stable versus unstable). As seismicity is controlled by the frictional response of fractures, we explore friction-stability-permeability relationships through the concurrent measurement of frictional and hydraulic properties of artificial fractures in Green River shale (GRS) and Opalinus shale (OPS). We observe that carbonate-rich GRS shows higher frictional strength but weak neutral frictional stability. The GRS fracture permeability declines during shearing while an increased sliding velocity reduces the rate of permeability decline. By comparison, the phyllosilicate-rich OPS has lower friction and strong stability while the fracture permeability is reduced due to the swelling behavior that dominates over the shearing induced permeability reduction. Hence, we conclude that the friction-stability-permeability relationship of a fracture is largely controlled by mineral composition and that shale mineral compositions with strong frictional stability may be particularly subject to permanent permeability reduction during fluid infiltration.

Wrenching and oil migration, Mervine field, Kay County, Oklahoma

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

Davis, H.G.

1985-02-01

Since 1913, Mervine field (T27N, R3E) has produced oil from 11 Mississippian and Pennsylvanian zones, and gas from 2 Permian zones. The field exhibits an impressive asymmetric surface anticline, with the steeper flank dipping 30/sup 0/E maximum. A nearly vertical, basement-involved fault develops immediately beneath the steeper flank of the surface anticline. Three periods of left-lateral wrench faulting account for 93% of all structural growth: 24% in post-Mississippian-pre-Desmoinesian time, 21% in Virgilian time, and 48% in post-Wolfcampian time. In Mesozoic through early Cenozoic times, the Devonian Woodford Shale (and possibly the Desmoinesian Cherokee shales) locally generated oil, which should havemore » been structurally trapped in the Ordovician Bromide sandstone. This oil may have joined oil already trapped in the Bromide, which had migrated to the Mervine area in the Early Pennsylvanian from a distant source. Intense post-Wolfcampian movement(s) fractured the competent pre-Pennsylvanian rocks, allowing Bromide brine and entrained oil to migrate vertically up the master fault, finally accumulating in younger reservoirs. Pressure, temperature, and salinity anomalies attest to vertical fluid migration continuing at the present time at Mervine field. Consequently, pressure, temperature, and salinity mapping should be considered as valuable supplements to structural and lithologic mapping when prospecting for structural hydrocarbon accumulations in epicratonic provinces.« less

Shale gas and non-aqueous fracturing fluids: Opportunities and challenges for supercritical CO₂

DOE PAGES

Middleton, Richard S.; Carey, James William; Currier, Robert P.; ...

2015-06-01

Hydraulic fracturing of shale formations in the United States has led to a domestic energy boom. Currently, water is the only fracturing fluid regularly used in commercial shale oil and gas production. Industry and researchers are interested in non-aqueous working fluids due to their potential to increase production, reduce water requirements, and to minimize environmental impacts. Using a combination of new experimental and modeling data at multiple scales, we analyze the benefits and drawbacks of using CO₂ as a working fluid for shale gas production. We theorize and outline potential advantages of CO₂ including enhanced fracturing and fracture propagation, reductionmore » of flow-blocking mechanisms, increased desorption of methane adsorbed in organic-rich parts of the shale, and a reduction or elimination of the deep re-injection of flow-back water that has been linked to induced seismicity and other environmental concerns. We also examine likely disadvantages including costs and safety issues associated with handling large volumes of supercritical CO₂. The advantages could have a significant impact over time leading to substantially increased gas production. In addition, if CO₂ proves to be an effective fracturing fluid, then shale gas formations could become a major utilization option for carbon sequestration.« less

Experimental insights into geochemical changes in hydraulically fractured Marcellus Shale

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

Marcon, Virginia; Joseph, Craig; Carter, Kimberly E.

Hydraulic fracturing applied to organic-rich shales has significantly increased the recoverable volume of methane available for U.S. energy consumption. Fluid-shale reactions in the reservoir may affect long-term reservoir productivity and waste management needs through changes to fracture mineral composition and produced fluid chemical composition. We performed laboratory experiments with Marcellus Shale and lab-generated hydraulic fracturing fluid at elevated pressures and temperatures to evaluate mineral reactions and the release of trace elements into solution. Results from the experiment containing fracturing chemicals show evidence for clay and carbonate dissolution, secondary clay and anhydrite precipitation, and early-stage (24-48 h) fluid enrichment of certainmore » elements followed by depletion in later stages (i.e. Al, Cd, Co, Cr, Cu, Ni, Sc, Zn). Other elements such as As, Fe, Mn, Sr, and Y increased in concentration and remained elevated throughout the duration of the experiment with fracturing fluid. Geochemical modeling of experimental fluid data indicates primary clay dissolution, and secondary formation of smectites and barite, after reaction with fracturing fluid. Changes in aqueous organic composition were observed, indicating organic additives may be chemically transformed or sequestered by the formation after hydraulic fracturing. The NaCl concentrations in our fluids are similar to measured concentrations in Marcellus Shale produced waters, showing that these experiments are representative of reservoir fluid chemistries and can provide insight on geochemical reactions that occur in the field. These results can be applied towards evaluating the evolution of hydraulically-fractured reservoirs, and towards understanding geochemical processes that control the composition of produced water from unconventional shales.« less

Experimental insights into geochemical changes in hydraulically fractured Marcellus Shale

DOE PAGES

Marcon, Virginia; Joseph, Craig; Carter, Kimberly E.; ...

2016-11-09

Hydraulic fracturing applied to organic-rich shales has significantly increased the recoverable volume of methane available for U.S. energy consumption. Fluid-shale reactions in the reservoir may affect long-term reservoir productivity and waste management needs through changes to fracture mineral composition and produced fluid chemical composition. We performed laboratory experiments with Marcellus Shale and lab-generated hydraulic fracturing fluid at elevated pressures and temperatures to evaluate mineral reactions and the release of trace elements into solution. Results from the experiment containing fracturing chemicals show evidence for clay and carbonate dissolution, secondary clay and anhydrite precipitation, and early-stage (24-48 h) fluid enrichment of certainmore » elements followed by depletion in later stages (i.e. Al, Cd, Co, Cr, Cu, Ni, Sc, Zn). Other elements such as As, Fe, Mn, Sr, and Y increased in concentration and remained elevated throughout the duration of the experiment with fracturing fluid. Geochemical modeling of experimental fluid data indicates primary clay dissolution, and secondary formation of smectites and barite, after reaction with fracturing fluid. Changes in aqueous organic composition were observed, indicating organic additives may be chemically transformed or sequestered by the formation after hydraulic fracturing. The NaCl concentrations in our fluids are similar to measured concentrations in Marcellus Shale produced waters, showing that these experiments are representative of reservoir fluid chemistries and can provide insight on geochemical reactions that occur in the field. These results can be applied towards evaluating the evolution of hydraulically-fractured reservoirs, and towards understanding geochemical processes that control the composition of produced water from unconventional shales.« less

Multiscale model reduction for shale gas transport in poroelastic fractured media

NASA Astrophysics Data System (ADS)

Akkutlu, I. Yucel; Efendiev, Yalchin; Vasilyeva, Maria; Wang, Yuhe

2018-01-01

Inherently coupled flow and geomechanics processes in fractured shale media have implications for shale gas production. The system involves highly complex geo-textures comprised of a heterogeneous anisotropic fracture network spatially embedded in an ultra-tight matrix. In addition, nonlinearities due to viscous flow, diffusion, and desorption in the matrix and high velocity gas flow in the fractures complicates the transport. In this paper, we develop a multiscale model reduction approach to couple gas flow and geomechanics in fractured shale media. A Discrete Fracture Model (DFM) is used to treat the complex network of fractures on a fine grid. The coupled flow and geomechanics equations are solved using a fixed stress-splitting scheme by solving the pressure equation using a continuous Galerkin method and the displacement equation using an interior penalty discontinuous Galerkin method. We develop a coarse grid approximation and coupling using the Generalized Multiscale Finite Element Method (GMsFEM). GMsFEM constructs the multiscale basis functions in a systematic way to capture the fracture networks and their interactions with the shale matrix. Numerical results and an error analysis is provided showing that the proposed approach accurately captures the coupled process using a few multiscale basis functions, i.e. a small fraction of the degrees of freedom of the fine-scale problem.

A Comprehensive Model for Real Gas Transport in Shale Formations with Complex Non-planar Fracture Networks

PubMed Central

Yang, Ruiyue; Huang, Zhongwei; Yu, Wei; Li, Gensheng; Ren, Wenxi; Zuo, Lihua; Tan, Xiaosi; Sepehrnoori, Kamy; Tian, Shouceng; Sheng, Mao

2016-01-01

A complex fracture network is generally generated during the hydraulic fracturing treatment in shale gas reservoirs. Numerous efforts have been made to model the flow behavior of such fracture networks. However, it is still challenging to predict the impacts of various gas transport mechanisms on well performance with arbitrary fracture geometry in a computationally efficient manner. We develop a robust and comprehensive model for real gas transport in shales with complex non-planar fracture network. Contributions of gas transport mechanisms and fracture complexity to well productivity and rate transient behavior are systematically analyzed. The major findings are: simple planar fracture can overestimate gas production than non-planar fracture due to less fracture interference. A “hump” that occurs in the transition period and formation linear flow with a slope less than 1/2 can infer the appearance of natural fractures. The sharpness of the “hump” can indicate the complexity and irregularity of the fracture networks. Gas flow mechanisms can extend the transition flow period. The gas desorption could make the “hump” more profound. The Knudsen diffusion and slippage effect play a dominant role in the later production time. Maximizing the fracture complexity through generating large connected networks is an effective way to increase shale gas production. PMID:27819349

A Comprehensive Model for Real Gas Transport in Shale Formations with Complex Non-planar Fracture Networks.

PubMed

Yang, Ruiyue; Huang, Zhongwei; Yu, Wei; Li, Gensheng; Ren, Wenxi; Zuo, Lihua; Tan, Xiaosi; Sepehrnoori, Kamy; Tian, Shouceng; Sheng, Mao

2016-11-07

A complex fracture network is generally generated during the hydraulic fracturing treatment in shale gas reservoirs. Numerous efforts have been made to model the flow behavior of such fracture networks. However, it is still challenging to predict the impacts of various gas transport mechanisms on well performance with arbitrary fracture geometry in a computationally efficient manner. We develop a robust and comprehensive model for real gas transport in shales with complex non-planar fracture network. Contributions of gas transport mechanisms and fracture complexity to well productivity and rate transient behavior are systematically analyzed. The major findings are: simple planar fracture can overestimate gas production than non-planar fracture due to less fracture interference. A "hump" that occurs in the transition period and formation linear flow with a slope less than 1/2 can infer the appearance of natural fractures. The sharpness of the "hump" can indicate the complexity and irregularity of the fracture networks. Gas flow mechanisms can extend the transition flow period. The gas desorption could make the "hump" more profound. The Knudsen diffusion and slippage effect play a dominant role in the later production time. Maximizing the fracture complexity through generating large connected networks is an effective way to increase shale gas production.

Strain Rate Dependency of Fracture Toughness, Energy Release Rate and Geomechanical Attributes of Select Indian Shales

NASA Astrophysics Data System (ADS)

Mahanta, B.; Vishal, V.; Singh, T. N.; Ranjith, P.

2016-12-01

In addition to modern improved technology, it requires detailed understanding of rock fractures for the purpose of enhanced energy extraction through hydraulic fracturing of gas shales and geothermal energy systems. The understanding of rock fracture behavior, patterns and properties such as fracture toughness; energy release rate; strength and deformation attributes during fracturing hold significance. Environmental factors like temperature, pressure, humidity, water vapor and experimental condition such as strain rate influence the estimation of these properties. In this study, the effects of strain rates on fracture toughness, energy release rate as well as geomechanical properties like uniaxial compressive strength, Young's modulus, failure strain, tensile strength, and brittleness index of gas shales were investigated. In addition to the rock-mechanical parameters, the fracture toughness and the energy release rates were measured for three different modes viz. mode I, mixed mode (I-II) and mode II. Petrographic and X-ray diffraction (XRD) analyses were performed to identify the mineral composition of the shale samples. Scanning electron microscope (SEM) analyses were conducted to have an insight about the strain rate effects on micro-structure of the rock. The results suggest that the fracture toughness; the energy release rate as well as other geomechanical properties are a function of strain rates. At high strain rates, the strength and stiffness of shale increases which in turn increases the fracture toughness and the energy release rate of shale that may be due to stress redistribution during grain fracturing. The fracture toughness and the strain energy release rates for all the modes (I/I-II/II) are comparable at lower strain rates, but they vary considerably at higher strain rates. In all the cases, mode I and mode II fracturing requires minimum and maximum applied energy, respectively. Mode I energy release rate is maximum, compared to the other modes.

Shale Gas Geomechanics for Development and Performance of Unconventional Reservoirs

NASA Astrophysics Data System (ADS)

Domonik, Andrzej; Łukaszewski, Paweł; Wilczyński, Przemysław; Dziedzic, Artur; Łukasiak, Dominik; Bobrowska, Alicja

2017-04-01

Mechanical properties of individual shale formations are predominantly determined by their lithology, which reflects sedimentary facies distribution, and subsequent diagenetic and tectonic alterations. Shale rocks may exhibit complex elasto-viscoplastic deformation mechanisms depending on the rate of deformation and the amount of clay minerals, also bearing implications for subcritical crack growth and heterogeneous fracture network development. Thus, geomechanics for unconventional resources differs from conventional reservoirs due to inelastic matrix behavior, stress sensitivity, rock anisotropy and low matrix permeability. Effective horizontal drilling and hydraulic fracturing technologies are required to obtain and maintain high performance. Success of these techniques strongly depends on the geomechanical investigations of shales. An inelastic behavior of shales draws increasing attention of investigators [1], due to its role in stress relaxation between fracturing phases. A strong mechanical anisotropy in the vertical plane and a lower and more variable one in the horizontal plane are characteristic for shale rocks. The horizontal anisotropy plays an important role in determining the direction and effectiveness of propagation of technological hydraulic fractures. Non-standard rock mechanics laboratory experiments are being applied in order to obtain the mechanical properties of shales that have not been previously studied in Poland. Novel laboratory investigations were carried out to assess the creep parameters and to determine time-dependent viscoplastic deformation of shale samples, which can provide a limiting factor to tectonic stresses and control stress change caused by hydraulic fracturing. The study was supported by grant no.: 13-03-00-501-90-472946 "An integrated geomechanical investigation to enhance gas extraction from the Pomeranian shale formations", funded by the National Centre for Research and Development (NCBiR). References: Ch. Chang M. D. Zoback. 2009. Viscous creep in room-dried unconsolidated Gulf of Mexico shale (I): Experimental results. Journal of Petroleum Science and Engineering 69: 239-246.

Unconventional shallow biogenic gas systems

USGS Publications Warehouse

Shurr, G.W.; Ridgley, J.L.

2002-01-01

Unconventional shallow biogenic gas falls into two distinct systems that have different attributes. Early-generation systems have blanketlike geometries, and gas generation begins soon after deposition of reservoir and source rocks. Late-generation systems have ringlike geometries, and long time intervals separate deposition of reservoir and source rocks from gas generation. For both types of systems, the gas is dominantly methane and is associated with source rocks that are not thermally mature. Early-generation biogenic gas systems are typified by production from low-permeability Cretaceous rocks in the northern Great Plains of Alberta, Saskatchewan, and Montana. The main area of production is on the southeastern margin of the Alberta basin and the northwestern margin of the Williston basin. The huge volume of Cretaceous rocks has a generalized regional pattern of thick, non-marine, coarse clastics to the west and thinner, finer grained marine lithologies to the east. Reservoir rocks in the lower part tend to be finer grained and have lower porosity and permeability than those in the upper part. Similarly, source beds in the units have higher values of total organic carbon. Patterns of erosion, deposition, deformation, and production in both the upper and lower units are related to the geometry of lineament-bounded basement blocks. Geochemical studies show that gas and coproduced water are in equilibrium and that the fluids are relatively old, namely, as much as 66 Ma. Other examples of early-generation systems include Cretaceous clastic reservoirs on the southwestern margin of Williston basin and chalks on the eastern margin of the Denver basin. Late-generation biogenic gas systems have as an archetype the Devonian Antrim Shale on the northern margin of the Michigan basin. Reservoir rocks are fractured, organic-rich black shales that also serve as source rocks. Although fractures are important for production, the relationships to specific geologic structures are not clear. Large quantities of water are coproduced with the gas, and geochemical data indicate that the water is fairly fresh and relatively young. Current thinking holds that biogenic gas was generated, and perhaps continues to be, when glacial meltwater descended into the plumbing system provided by fractures. Other examples of late-generation systems include the Devonian New Albany Shale on the eastern margin of the Illinois basin and the Tertiary coalbed methane production on the northwestern margin of the Powder River basin. Both types of biogenic gas systems have a similar resource development history. Initially, little technology is used, and gas is consumed locally; eventually, sweet spots are exploited, widespread unconventional reservoirs are developed, and transport of gas is interstate or international. However, drilling and completion techniques are very different between the two types of systems. Early-generation systems have water-sensitive reservoir rocks, and consequently water is avoided or minimized in drilling and completion. In contrast, water is an important constituent of late-generation systems; gas production is closely tied to dewatering the system during production. Existing production and resource estimates generally range from 10 to 100 tcf for both types of biogenic gas systems. Although both system types are examples of relatively continuous accumulations, the geologic frameworks constrain most-economic production to large geologic structures on the margins of basins. Shallow biogenic gas systems hold important resources to meet the increased domestic and international demands for natural gas.

Experimental Determination of the Fracture Toughness and Brittleness of the Mancos Shale, Utah.

NASA Astrophysics Data System (ADS)

Chandler, Mike; Meredith, Phil; Crawford, Brian

2013-04-01

The hydraulic fracturing of Gas-Shales has become a topic of interest since the US Shale Gas Revolution, and is increasingly being investigated across Europe. A significant issue during hydraulic fracturing is the risk of fractures propagating further than desired into aquifers or faults. This occured at Preese Hall, UK in April and May 2011 when hydraulic fractures propagated into an adjacent fault causing 2.3ML and 1.7ML earthquakes [1]. A rigorous understanding of how hydraulic fractures propagate under in-situ conditions is therefore important for treatment design, both to maximise gas accessed, and to minimise risks due to fracture overextension. Fractures will always propagate along the path of least resistance, but the direction and extent of this path is a complex relationship between the in-situ stress-field, the anisotropic mechanical properties of the rock, and the pore and fracturing pressures [2]. It is possible to estimate the anisotropic in-situ stress field using an isolated-section hydraulic fracture test, and the pore-pressure using well logs. However, the anisotropic mechanical properties of gas-shales remain poorly constrained, with a wide range of reported values. In particular, there is an extreme paucity of published data on the Fracture Toughness of soft sediments such as shales. Mode-I Fracture Toughness is a measure of a material's resistance to dynamic tensile fracture propagation. Defects such as pre-existing microcracks and pores in a material can induce high local stress concentrations, causing fracture propagation and material failure under substantially lower stress than its bulk strength. The mode-I stress intensity factor, KI, quantifies the concentration of stress at the crack tip. For linear elastic materials the Fracture Toughness is defined by the critical value of this stress intensity factor; KIc, beyond which rapid catastrophic crack growth occurs. However, rocks such as shales are relatively ductile and display significant non-linearity. This produces hysteresis during cyclic loading, allowing for the calculation of a brittleness coefficient using the residual displacement after successive loading cycles. This can then be used to define a brittleness corrected Fracture Toughness, KIcc. We report anisotropic KIcc values and a variety of supporting measurements made on the Mancos Shale in the three principle Mode-I crack orientations (Arrester, Divider and Short-Transverse) using a modified Short-Rod sample geometry. The Mancos is an Upper Cretaceous shale from western Colorado and eastern Utah with a relatively high siliclastic content for a gas target formation. The Short-Rod methodology involves the propagation of a crack through a triangular ligament in a chevron-notched cylindrical sample [3]. A very substantial anisotropy is observed in the loading curves and KIcc values for the three crack orientations, with the Divider orientation having KIcc values 25% higher than the other orientations. The measured brittleness for these Mancos shales is in the range 1.5-2.1; higher than for any other rocks we have found in the literature. This implies that the material is extremely non-linear. Increases in KIcc with increasing confining pressure are also investigated, as Shale Gas reservoirs occur at depths where confining pressure may be as high as 35MPa and temperature as high as 100oC. References [1] C.A. Green, P. Styles & B.J. Baptie, "Preese Hall Shale Gas Fracturing", Review & Recommendations for Induced Seismic Mitigation, 2012. [2] N.R. Warpinski & M.B. Smith, "Rock Mechanics and Fracture Geometry", Recent advances in Hydraulic Fracturing, SPE Monograms, Vol. 12, pp. 57-80, 1990. [3] F. Ouchterlony, "International Society for Rock Mechanics Commision on Testing Methods: Suggested Methods for Determining the Fracture Toughness of Rock", International Journal of Rock Mechanics and Mining Science & Geomechanics Abstracts, Vol. 25, 1988.

Germanium and uranium in coalified wood bom upper Devonian black shale

USGS Publications Warehouse

Breger, I.A.; Schopf, J.M.

1955-01-01

Microscopic study of black, vitreous, carbonaceous material occurring in the Chattanooga shale in Tennessee and in the Cleveland member of the Ohio shale in Ohio has revealed coalified woody plant tissue. Some samples have shown sufficient detail to be identified with the genus Cauixylon. Similar material has been reported in the literature as "bituminous" or "asphaltic" stringers. Spectrographic analyses of the ash from the coalified wood have shown unusually high percentages of germanium, uranium, vanadium, and nickel. The inverse relationship between uranium and germanium in the ash and the ash content of various samples shows an association of these elements with the organic constituents of the coal. On the basis of geochemical considerations, it seems most probable that the wood or coalified wood was germanium-bearing at the time logs or woody fragmenta were floated into the basins of deposition of the Chattanooga shale and the Cleveland member of the Ohio shale. Once within the marine environment, the material probably absorbed uranium with the formation of organo-uranium compounds such as exist in coals. It is suggested that a more systematic search for germaniferous coals in the vicinity of the Chattanooga shale and the Cleveland member of the Ohio shale might be rewarding. ?? 1955.

A Numerical Study of Factors Affecting Fracture-Fluid Cleanup and Produced Gas/Water in Marcellus Shale: Part II

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

Seales, Maxian B.; Dilmore, Robert; Ertekin, Turgay

Horizontal wells combined with successful multi-stage hydraulic fracture treatments are currently the most established method for effectively stimulating and enabling economic development of gas bearing organic-rich shale formations. Fracture cleanup in the Stimulated Reservoir Volume (SRV) is critical to stimulation effectiveness and long-term well performance. However, fluid cleanup is often hampered by formation damage, and post-fracture well performance frequently falls below expectations. A systematic study of the factors that hinder fracture fluid cleanup in shale formations can help optimize fracture treatments and better quantify long term volumes of produced water and gas. Fracture fluid cleanup is a complex process influencedmore » by multi-phase flow through porous media (relative permeability hysteresis, capillary pressure etc.), reservoir rock and fluid properties, fracture fluid properties, proppant placement, fracture treatment parameters, and subsequent flowback and field operations. Changing SRV and fracture conductivity as production progresses further adds to the complexity of this problem. Numerical simulation is the best, and most practical approach to investigate such a complicated blend of mechanisms, parameters, their interactions, and subsequent impact on fracture fluid cleanup and well deliverability. In this paper, a 3-dimensional, 2-phase, dual-porosity model was used to investigate the impact of multiphase flow, proppant crushing, proppant diagenesis, shut-in time, reservoir rock compaction, gas slippage, and gas desorption on fracture fluid cleanup, and well performance in Marcellus shale. The research findings have shed light on the factors that substantially constrains efficient fracture fluid cleanup in gas shales, and provided guidelines for improved fracture treatment designs and water management.« less

Discrete fracture modeling of multiphase flow and hydrocarbon production in fractured shale or low permeability reservoirs

NASA Astrophysics Data System (ADS)

Hao, Y.; Settgast, R. R.; Fu, P.; Tompson, A. F. B.; Morris, J.; Ryerson, F. J.

2016-12-01

It has long been recognized that multiphase flow and transport in fractured porous media is very important for various subsurface applications. Hydrocarbon fluid flow and production from hydraulically fractured shale reservoirs is an important and complicated example of multiphase flow in fractured formations. The combination of horizontal drilling and hydraulic fracturing is able to create extensive fracture networks in low permeability shale rocks, leading to increased formation permeability and enhanced hydrocarbon production. However, unconventional wells experience a much faster production decline than conventional hydrocarbon recovery. Maintaining sustainable and economically viable shale gas/oil production requires additional wells and re-fracturing. Excessive fracturing fluid loss during hydraulic fracturing operations may also drive up operation costs and raise potential environmental concerns. Understanding and modeling processes that contribute to decreasing productivity and fracturing fluid loss represent a critical component for unconventional hydrocarbon recovery analysis. Towards this effort we develop a discrete fracture model (DFM) in GEOS (LLNL multi-physics computational code) to simulate multiphase flow and transfer in hydraulically fractured reservoirs. The DFM model is able to explicitly account for both individual fractures and their surrounding rocks, therefore allowing for an accurate prediction of impacts of fracture-matrix interactions on hydrocarbon production. We apply the DFM model to simulate three-phase (water, oil, and gas) flow behaviors in fractured shale rocks as a result of different hydraulic stimulation scenarios. Numerical results show that multiphase flow behaviors at the fracture-matrix interface play a major role in controlling both hydrocarbon production and fracturing fluid recovery rates. The DFM model developed in this study will be coupled with the existing hydro-fracture model to provide a fully integrated geomechanical and reservoir simulation capability for an accurate prediction and assessment of hydrocarbon production and hydraulic fracturing performance. This work was performed under the auspices of the U.S. Department of Energy by Lawrence Livermore National Laboratory under Contract DE-AC52-07NA27344.

Fracturing and brittleness index analyses of shales

NASA Astrophysics Data System (ADS)

Barnhoorn, Auke; Primarini, Mutia; Houben, Maartje

2016-04-01

The formation of a fracture network in rocks has a crucial control on the flow behaviour of fluids. In addition, an existing network of fractures , influences the propagation of new fractures during e.g. hydraulic fracturing or during a seismic event. Understanding of the type and characteristics of the fracture network that will be formed during e.g. hydraulic fracturing is thus crucial to better predict the outcome of a hydraulic fracturing job. For this, knowledge of the rock properties is crucial. The brittleness index is often used as a rock property that can be used to predict the fracturing behaviour of a rock for e.g. hydraulic fracturing of shales. Various terminologies of the brittleness index (BI1, BI2 and BI3) exist based on mineralogy, elastic constants and stress-strain behaviour (Jin et al., 2014, Jarvie et al., 2007 and Holt et al., 2011). A maximum brittleness index of 1 predicts very good and efficient fracturing behaviour while a minimum brittleness index of 0 predicts a much more ductile shale behaviour. Here, we have performed systematic petrophysical, acoustic and geomechanical analyses on a set of shale samples from Whitby (UK) and we have determined the three different brittleness indices on each sample by performing all the analyses on each of the samples. We show that each of the three brittleness indices are very different for the same sample and as such it can be concluded that the brittleness index is not a good predictor of the fracturing behaviour of shales. The brittleness index based on the acoustic data (BI1) all lie around values of 0.5, while the brittleness index based on the stress strain data (BI2) give an average brittleness index around 0.75, whereas the mineralogy brittleness index (BI3) predict values below 0.2. This shows that by using different estimates of the brittleness index different decisions can be made for hydraulic fracturing. If we would rely on the mineralogy (BI3), the Whitby mudstone is not a suitable candidate for hydraulic fracturing while if we would rely on stress-strain data (BI2) the Whitby mudstone would be a very good candidate. We are aiming to perform these kind of measurements on a wide variety of shales with varying compositions and origins etc. and compare all results and come up with a better brittleness index, as well as link the brittleness indices to the fracturing behaviour seen in the samples. References: Holt, R., Fjaer, E., Nes, O. & Alassi, H., 2011. A shaly look at brittleness. 45th U.S. Rock Mechanics / Geomechanics Symposium, ARMA-11-366 Jarvie, D., Hill, J., Ruble, T. & Pollastro, R., 2007. Unconventional shale-gas system: The Mississippian Barnett Shale of North-Central Texas as one model for thermogenic shale-gas assessment. AAPG, 91(doi: 10.1306/12190606068), pp. 475-499. Jin, X., Shah, S. N., Rogiers, J.-C. & Zhang, B., 2014. Fraccability Evaluation in Shale Reservoirs - An Integrated Petrophysics and Geomechanics Approach. Woodlands, Texas, SPE.

Frictional stability-permeability relationships for fractures in shales: Friction-Permeability Relationships

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

Fang, Yi; Elsworth, Derek; Wang, Chaoyi

There is wide concern that fluid injection in the subsurface, such as for the stimulation of shale reservoirs or for geological CO 2 sequestration (GCS), has the potential to induce seismicity that may change reservoir permeability due to fault slip. However, the impact of induced seismicity on fracture permeability evolution remains unclear due to the spectrum of modes of fault reactivation (e.g., stable versus unstable). As seismicity is controlled by the frictional response of fractures, we explore friction-stability-permeability relationships through the concurrent measurement of frictional and hydraulic properties of artificial fractures in Green River shale (GRS) and Opalinus shale (OPS).more » We observe that carbonate-rich GRS shows higher frictional strength but weak neutral frictional stability. The GRS fracture permeability declines during shearing while an increased sliding velocity reduces the rate of permeability decline. By comparison, the phyllosilicate-rich OPS has lower friction and strong stability while the fracture permeability is reduced due to the swelling behavior that dominates over the shearing induced permeability reduction. Hence, we conclude that the friction-stability-permeability relationship of a fracture is largely controlled by mineral composition and that shale mineral compositions with strong frictional stability may be particularly subject to permanent permeability reduction during fluid infiltration.« less

Empirically assessing the potential release of rare earth elements from black shale under simulated hydraulic fracturing conditions

DOE PAGES

Yang, Jon; Verba, Circe; Torres, Marta; ...

2018-02-01

Rare earth elements (REEs) are economically important to modern society and the rapid growth of technologies dependent on REEs has placed considerable economic pressure on their sourcing. This study addresses whether REEs could be released as a byproduct of natural gas extraction from a series of experiments that were designed to simulate hydraulic fracturing of black shale under various pressure (25 and 27.5 MPa) and temperature (50, 90, 130 °C) conditions. The dissolved REEs in the reacted fluids displayed no propensity for the REEs to be released from black shale under high pressure and temperature conditions, a result that ismore » consistent across the different types of fluids investigated. Overall, there was a net loss of REEs from the fluid. These changes in dissolved REEs were greatest at the moment the fluids first contacted the shale and before the high temperature and high pressure conditions were imposed, although the magnitude of these changes (10 -4 μg/g) were small compared to the magnitude of the total REE content present in the solid shale samples (10 2 μg/g). These results highlight the variability and complexity of hydraulic fracturing systems and indicate that REE may not serve as robust tracers for fracturing fluid-shale reactions. Additionally, the results suggest that significant quantities of REEs may not be byproducts of hydraulically fractured shales.« less

Empirically assessing the potential release of rare earth elements from black shale under simulated hydraulic fracturing conditions

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

Yang, Jon; Verba, Circe; Torres, Marta

Rare earth elements (REEs) are economically important to modern society and the rapid growth of technologies dependent on REEs has placed considerable economic pressure on their sourcing. This study addresses whether REEs could be released as a byproduct of natural gas extraction from a series of experiments that were designed to simulate hydraulic fracturing of black shale under various pressure (25 and 27.5 MPa) and temperature (50, 90, 130 °C) conditions. The dissolved REEs in the reacted fluids displayed no propensity for the REEs to be released from black shale under high pressure and temperature conditions, a result that ismore » consistent across the different types of fluids investigated. Overall, there was a net loss of REEs from the fluid. These changes in dissolved REEs were greatest at the moment the fluids first contacted the shale and before the high temperature and high pressure conditions were imposed, although the magnitude of these changes (10 -4 μg/g) were small compared to the magnitude of the total REE content present in the solid shale samples (10 2 μg/g). These results highlight the variability and complexity of hydraulic fracturing systems and indicate that REE may not serve as robust tracers for fracturing fluid-shale reactions. Additionally, the results suggest that significant quantities of REEs may not be byproducts of hydraulically fractured shales.« less

Experimental and Model Studies on Loading Path-Dependent and Nonlinear Gas Flow Behavior in Shale Fractures

NASA Astrophysics Data System (ADS)

Li, Honglian; Lu, Yiyu; Zhou, Lei; Tang, Jiren; Han, Shuaibin; Ao, Xiang

2018-01-01

Interest in shale gas as an energy source is growing worldwide. Because the rock's natural fracture system can contribute to gas production, it is important to understand the flow behavior of natural fractures in shale. Previous studies on the flow characteristics in shale fractures were limited and did not consider the effect of nonlinearity. To understand the basic mechanics of the gas flow behavior in shale fractures, laboratory investigations with consideration of the fluid pressure gradient, the confining stress, the loading history and the fracture geometry were conducted in this paper. Izbash's equation was used to analyze the nonlinearity of the flow. The results show that the behavior of the friction factors is similar to that shown in flow tests in smooth and rough pipes. The increase of the confining stress and the irreversible damage to the shale decreased the hydraulic aperture and increased the relative roughness. Thus, turbulent flow could appear at a low Reynolds number, resulting in a significant pressure loss. The limits of the cubic law and the existing correction factor for transmissivity are discussed. It is found that the previous friction models overestimate the friction factor in the laminar regime and underestimate the friction factor in the turbulent regime. For this reason, a new friction model based on a linear combination of the Reynolds number and the relative roughness was developed.

Fracking in Tight Shales: What Is It, What Does It Accomplish, and What Are Its Consequences?

NASA Astrophysics Data System (ADS)

Norris, J. Quinn; Turcotte, Donald L.; Moores, Eldridge M.; Brodsky, Emily E.; Rundle, John B.

2016-06-01

Fracking is a popular term referring to hydraulic fracturing when it is used to extract hydrocarbons. We distinguish between low-volume traditional fracking and the high-volume modern fracking used to recover large volumes of hydrocarbons from shales. Shales are fine-grained rocks with low granular permeabilities. During the formation of oil and gas, large fluid pressures are generated. These pressures result in natural fracking, and the resulting fracture permeability allows oil and gas to escape, reducing the fluid pressures. These fractures may subsequently be sealed by mineral deposition, resulting in tight shale formations. The objective of modern fracking is to reopen these fractures and/or create new fractures on a wide range of scales. Modern fracking has had a major impact on the availability of oil and gas globally; however, there are serious environmental objections to modern fracking, which should be weighed carefully against its benefits.

A Case History of Tracking Water Movement Through Fracture Systems in the Barnett Shale, March 10-11, 2011

EPA Pesticide Factsheets

Technical Presentation Session 6: Monitoring slides to presentation by Denbury on tracking water movement through fracture systems in the Barnett shale. This includes information on micro-seismic well evaluation, well plans, and a fracture map.

Multilayer geospatial analysis of water availability for shale resources development in Mexico

NASA Astrophysics Data System (ADS)

Galdeano, C.; Cook, M. A.; Webber, M. E.

2017-08-01

Mexico’s government enacted an energy reform in 2013 that aims to foster competitiveness and private investment throughout the energy sector value chain. As part of this reform, it is expected that extraction of oil and gas via hydraulic fracturing will increase in five shale basins (e.g. Burgos, Sabinas, Tampico, Tuxpan, and Veracruz). Because hydraulic fracturing is a water-intensive activity, it is relevant to assess the potential water availability for this activity in Mexico. This research aims to quantify the water availability for hydraulic fracturing in Mexico and identify its spatial distribution along the five shale basins. The methodology consisted of a multilayer geospatial analysis that overlays the water availability in the watersheds and aquifers with the different types of shale resources areas (e.g. oil and associated gas, wet gas and condensate, and dry gas) in the five shale basins. The aquifers and watersheds in Mexico are classified in four zones depending on average annual water availability. Three scenarios were examined based on different impact level on watersheds and aquifers from hydraulic fracturing. For the most conservative scenario analyzed, the results showed that the water available could be used to extract between 8.15 and 70.42 Quadrillion British thermal units (Quads) of energy in the typical 20-30 year lifetime of the hydraulic fracturing wells that could be supplied with the annual water availability overlaying the shale areas, with an average across estimates of around 18.05 Quads. However, geographic variation in water availability could represent a challenge for extracting the shale reserves. Most of the water available is located closer to the Gulf of Mexico, but the areas with the larger recoverable shale reserves coincide with less water availability in Northern Mexico. New water management techniques (such as recycling and re-use), more efficient fracturing methods, shifts in usage patterns, or other water sources need to be identified to allocate water for hydraulic fracturing without affecting current users (e.g. municipal, irrigation, industrial, and environmental flows).

Field and Lab-Based Microbiological Investigations of the Marcellus Shale

NASA Astrophysics Data System (ADS)

Wishart, J. R.; Neumann, K.; Edenborn, H. M.; Hakala, A.; Yang, J.; Torres, M. E.; Colwell, F. S.

2013-12-01

The recent exploration of shales for natural gas resources has provided the opportunity to study their subsurface geochemistry and microbiology. Evidence indicates that shale environments are marked by extreme conditions such as high temperature and pressure, low porosity, permeability and connectivity, and the presence of heavy metals and radionuclides. It has been postulated that many of these shales are naturally sterile due to the high pressure and temperature conditions under which they were formed. However, it has been shown in the Antrim and New Albany shales that microbial communities do exist in these environments. Here we review geochemical and microbiological evidence for the possible habitation of the Marcellus shale by microorganisms and compare these conditions to other shales in the U.S. Furthermore, we describe the development of sampling and analysis techniques used to evaluate microbial communities present in the Marcellus shale and associated hydraulic fracturing fluid. Sampling techniques thus far have consisted of collecting flowback fluids from wells and water impoundments and collecting core material from previous drilling expeditions. Furthermore, DNA extraction was performed on Marcellus shale sub-core with a MoBio PowerSoil kit to determine its efficiency. Assessment of the Marcellus shale indicates that it has low porosity and permeability that are not conducive to dense microbial populations; however, moderate temperatures and a natural fracture network may support a microbial community especially in zones where the Marcellus intersects more porous geologic formations. Also, hydraulic fracturing extends this fracture network providing more environments where microbial communities can exist. Previous research which collected flowback fluids has revealed a diverse microbial community that may be derived from hydrofrac fluid production or from the subsurface. DNA extraction from 10 g samples of Marcellus shale sub-core were unsuccessful even when samples were spiked with 8x108 cells/g of shale. This indicated that constituents of shale such as high levels of carbonates, humic acids and metals likely inhibited components of the PowerSoil kit. Future research is focused on refining sample collection and analyses to gain a full understanding of the microbiology of the Marcellus shale and associated flowback fluids. This includes the development of an in situ osmosampler, which will collect temporally relevant fluid and colonized substrate samples. The design of the osmosampler for hydraulic fracturing wells is being adapted from those used to sample marine environments. Furthermore, incubation experiments are underway to study interactions between microbial communities associated with hydraulic fracturing fluid and Marcellus shale samples. In conclusion, evidence suggests that the Marcellus shale is a possible component of the subsurface biosphere. Future studies will be valuable in determining the microbial community structure and function in relation to the geochemistry of the Marcellus shale and its future development as a natural gas resource.

The astronomical rhythm of Late-Devonian climate change (Kowala section, Holy Cross Mountains, Poland)

NASA Astrophysics Data System (ADS)

De Vleeschouwer, David; Rakociński, Michał; Racki, Grzegorz; Bond, David P. G.; Sobień, Katarzyna; Claeys, Philippe

2013-03-01

Rhythmical alternations between limestone and shales or marls characterize the famous Kowala section, Holy Cross Mountains, Poland. Two intervals of this section were studied for evidence of orbital cyclostratigraphy. The oldest interval spans the Frasnian-Famennian boundary, deposited under one of the hottest greenhouse climates of the Phanerozoic. The youngest interval encompasses the Devonian-Carboniferous (D-C) boundary, a pivotal moment in Earth's climatic history that saw a transition from greenhouse to icehouse. For the Frasnian-Famennian sequence, lithological variations are consistent with 405-kyr and 100-kyr eccentricity forcing and a cyclostratigraphic floating time-scale is presented. The interpretation of observed lithological rhythms as eccentricity cycles is confirmed by amplitude modulation patterns in agreement with astronomical theory and by the recognition of precession cycles in high-resolution stable isotope records. The resulting relative time-scale suggests that ˜800 kyr separate the Lower and Upper Kellwasser Events (LKE and UKE, respectively), two periods of anoxia that culminated in massive biodiversity loss at the end of the Frasnian. Th/U and pyrite framboid analyses indicate that during the UKE, oxygen levels remained low for 400 kyr and δ13Corg measurements demonstrate that more than 600 kyr elapsed before the carbon cycle reached a steady state after a +3‰ UKE excursion. The Famennian-Tournaisian (D-C) interval also reveals eccentricity and precession-related lithological variations. Precession-related alternations clearly demonstrate grouping into 100-kyr bundles. The Famennian part of this interval is characterized by several distinctive anoxic black shales, including the Annulata, Dasberg and Hangenberg shales. Our high-resolution cyclostratigraphic framework indicates that those shales were deposited at 2.2 and 2.4 Myr intervals respectively. These durations strongly suggest a link between the long-period (˜2.4 Myr) eccentricity cycle and the development of the Annulata, Dasberg and Hangenberg anoxic shales. It is assumed that these black shales form under transgressive conditions, when extremely high eccentricity promoted the collapse of small continental ice-sheets at the most austral latitudes of western Gondwana.

A comprehensive method for the fracability evaluation of shale combined with brittleness and stress sensitivity

NASA Astrophysics Data System (ADS)

Wang, Xiaoqiong; Ge, Hongkui; Wang, Daobing; Wang, Jianbo; Chen, Hao

2017-12-01

An effective fracability evaluation on the fracture network is key to the whole process of shale gas exploitation. At present, neither a standard criteria nor a generally accepted evaluation method exist. Well log and laboratory results have shown that the commonly used brittleness index calculated from the mineralogy composition is not entirely consistent with that obtained from the elastic modulus of the rock, and is sometimes even contradictory. The brittle mineral reflects the brittleness of the rock matrix, and the stress sensitivity of the wave velocity reflects the development degree of the natural fracture system. They are both key factors in controlling the propagating fracture morphology. Thus, in this study, a novel fracability evaluation method of shale was developed combining brittleness and stress sensitivity. Based on this method, the fracability of three shale gas plays were evaluated. The cored cylindrical samples were loaded under uniaxial stress up to 30 MPa and the compressional wave velocities were obtained along the axis stress direction at each MPa stress. From the stress velocity evolution, the stress sensitivity coefficients could be obtained. Our results showed that the fracability of Niutitang shale is better than that of Lujiaping shale, and the fracability of Lujiaping shale is better than Longmaxi shale. This result is in good agreement with acoustic emission activity measurements. The new fracability evaluation method enables a comprehensive reflection of the characteristics of rock matrix brittleness and the natural fracture system. This work is valuable for the evaluation of hydraulic fracturing effects in unconventional oil and gas reservoirs in the future.

The Role of the Rock on Hydraulic Fracturing of Tight Shales

NASA Astrophysics Data System (ADS)

Suarez-Rivera, R.; Green, S.; Stanchits, S.; Yang, Y.

2011-12-01

Successful economic production of oil and gas from nano-darcy-range permeability, tight shale reservoirs, is achieved via massive hydraulic fracturing. This is so despite their limited hydrocarbon in place, on per unit rock volume basis. As a reference, consider a typical average porosity of 6% and an average hydrocarbon saturation of 50% to 75%. The importance of tight shales results from their large areal extent and vertical thickness. For example, the areal extent of the Anwar field in Saudi Arabia of 3230 square miles (and 300 ft thick), while the Marcellus shale alone is over 100,000 square miles (and 70 to 150 ft thick). The low permeability of the rock matrix, the predominantly mineralized rock fabric, and the high capillary forces to both brines and hydrocarbons, restrict the mobility of pore fluids in these reservoirs. Thus, one anticipates that fluids do not move very far within tight shales. Successful production, therefore results from maximizing the surface area of contact with the reservoir by massive hydraulic fracturing from horizontal bore holes. This was the conceptual breakthrough of the previous decade and the one that triggered the emergence of gas shales, and recently oily shales, as important economic sources of energy. It is now understood that the process can be made substantially more efficient, more sustainable, and more cost effective by understanding the rock. This will be the breakthrough of this decade. Microseismic monitoring, mass balance calculations, and laboratory experiments of hydraulic fracturing on tight shales indicate the development of fracture complexity and fracture propagation that can not be explained in detail in this layered heterogeneous media. It is now clear that in tight shales the large-scale formation fabric is responsible for fracture complexity. For example, the presence and pervasiveness of mineralized fractures, bed interfaces, lithologic contacts, and other types of discontinuities, and their orientation in relation to the in-situ stresses, have a dominant role in promoting fracture branching and abrupt changes in direction. In general, the problem can be conceptualized as a competition between the effect of stresses (traditional mechanics of homogeneous media) and the effect of rock fabric (the mechanics of heterogeneous media). When the stress difference is low and the rock fabric pronounced, the rock fabric defines the direction of propagation. When the stress difference is high and the fabric is weak, the stress contrast dominates the process. In real systems, both effects compete and result in the complexity that we infer from indirect observations. In this paper we discuss the role of rock fabric on fracture complexity during hydraulic fracture propagation. We show that understanding the far field stresses is not enough to understand fracture propagation and complexity. Understanding the rock-specifically the larger-scale textural features that define the reservoir fabric-is fundamental to understand fracture complexity and fracture containment. We use laboratory experiments with acoustic emission localization to monitor fracturing and making inferences about the large-scale rock behavior. We also show that the fracture geometry, even for the same connected surface area, has significant well production and reservoir recovery implications.

Geology and hydrocarbon potential of the Hamada and Murzuq basins in western Libya

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

Kirmani, K.U.; Elhaj, F.

1988-08-01

The Hamada and Murzuq intracratonic basins of western Libya form a continuation of the Saharan basin which stretches from Algeria eastward into Tunisia and Libya. The tectonics and sedimentology of this region have been greatly influenced by the Caledonian and Hercynian orogenies. Northwest- and northeast-trending faults are characteristic of the broad, shallow basins. The Cambrian-Ordovician sediments are fluvial to shallow marine. The Silurian constitutes a complete sedimentary cycle, ranging from deep marine shales to shallow marine and deltaic sediments. The Devonian occupies a unique position between two major orogenies. The Mesozoic strata are relatively thin. The Triassic consists of well-developedmore » continental sands, whereas the Jurassic and Cretaceous sediments are mainly lagoonal dolomites, evaporites, and shales. Silurian shales are the primary source rock in the area. The quality of the source rock appears to be better in the deeper part of the basin than on its periphery. The Paleozoic has the best hydrocarbon potential. Hydrocarbons have also been encountered in the Triassic and Carboniferous. In the Hamada basin, the best-known field is the El Hamra, with reserves estimated at 155 million bbl from the Devonian. Significant accumulations of oil have been found in the Silurian. Tlacsin and Tigi are two fields with Silurian production. In the Murzuq basin the Cambrian-Ordovician has the best production capability. However, substantial reserves need to be established before developing any field in this basin. Large areas still remain unexplored in western Libya.« less

Discourse over a contested technology on Twitter: A case study of hydraulic fracturing.

PubMed

Hopke, Jill E; Simis, Molly

2015-10-04

High-volume hydraulic fracturing, a drilling simulation technique commonly referred to as "fracking," is a contested technology. In this article, we explore discourse over hydraulic fracturing and the shale industry on the social media platform Twitter during a period of heightened public contention regarding the application of the technology. We study the relative prominence of negative messaging about shale development in relation to pro-shale messaging on Twitter across five hashtags (#fracking, #globalfrackdown, #natgas, #shale, and #shalegas). We analyze the top actors tweeting using the #fracking hashtag and receiving @mentions with the hashtag. Results show statistically significant differences in the sentiment about hydraulic fracturing and shale development across the five hashtags. In addition, results show that the discourse on the main contested hashtag #fracking is dominated by activists, both individual activists and organizations. The highest proportion of tweeters, those posting messages using the hashtag #fracking, were individual activists, while the highest proportion of @mention references went to activist organizations. © The Author(s) 2015.

Palaeoecology and sedimentology of the dysaerobic Bedford fauna (late Devonian), Ohio and Kentucky (USA)

USGS Publications Warehouse

Pashin, J.C.; Ettensohn, F.R.

1992-01-01

Oxygen-deficient biofacies models rely on lithologic and paleontologic attributes to identify distinctive biofacies interpreted to reflect levels of oxygenation in anaerobic, dysaerobic, and aerobic parts of a stratified water column. This study of the Bedford fauna from the Bedford Shale of Ohio and Kentucky and from adjacent black-shale units reports faunal distributions different from those predicted by the accepted models. This study suggests that, although oxygenation was an important factor that determined the taxonomic makeup of the fauna, bacterially mediated nutrient recycling and substrate characteristics were more important than oxygenation in determining faunal distribution in the dysaerobic zone. ?? 1992.

Computerized X-ray Microtomography Observations and Fluid Flow Measurements of the Effect of Effective Stress on Fractured Reservoir Seal Shale

NASA Astrophysics Data System (ADS)

Welch, N.; Crawshaw, J.; Boek, E.

2014-12-01

The successful storage of carbon dioxide in geologic formations requires an in-depth understanding of all reservoir characteristics and morphologies. An intact and substantial seal formation above a storage reservoir is required for a significant portion of the initial sealing mechanisms believed to occur during carbon dioxide storage operations. Shales are a common seal formation rock types found above numerous hydrocarbon reservoirs, as well as potential saline aquifer storage locations. Shales commonly have very low permeability, however they also have the tendency to be quite fissile, and the formation of fractures within these seals can have a significant detrimental effect on the sealing potential of a reservoir and amount to large areas of high permeability and low capillary pressures compared to the surrounding intact rock. Fractured shales also have an increased current interest due to the increasing development of shale gas reservoirs using hydraulic fracturing techniques. This work shows the observed changes that occur within fractured pieces of reservoir seal shale samples, along with quarry analogues, using an in-situ micro-CT fluid flow imaging apparatus with a Hassler type core holder. Changes within the preferential flow path under different stress regimes as well as physical changes to the fracture geometry are reported. Lattice Boltzmann flow simulations were then performed on the extracted flow paths and compared to experiment permeability measurements. The preferential flow path of carbon dioxide through the fracture network is also observed and compared to the results two-phase Lattice Boltzmann fluid flow simulations.

The effect of deformation on two-phase flow through proppant-packed fractured shale samples: A micro-scale experimental investigation

NASA Astrophysics Data System (ADS)

Arshadi, Maziar; Zolfaghari, Arsalan; Piri, Mohammad; Al-Muntasheri, Ghaithan A.; Sayed, Mohammed

2017-07-01

We present the results of an extensive micro-scale experimental investigation of two-phase flow through miniature, fractured reservoir shale samples that contained different packings of proppant grains. We investigated permeability reduction in the samples by conducting experiments under a wide range of net confining pressures. Three different proppant grain distributions in three individual fractured shale samples were studied: i) multi-layer, ii) uniform mono-layer, and iii) non-uniform mono-layer. We performed oil-displacing-brine (drainage) and brine-displacing-oil (imbibition) flow experiments in the proppant packs under net confining pressures ranging from 200 to 6000 psi. The flow experiments were performed using a state-of-the-art miniature core-flooding apparatus integrated with a high-resolution, X-ray microtomography system. We visualized fluid occupancies, proppant embedment, and shale deformation under different flow and stress conditions. We examined deformation of pore space within the proppant packs and its impact on permeability and residual trapping, proppant embedment due to changes in net confining stress, shale surface deformation, and disintegration of proppant grains at high stress conditions. In particular, geometrical deformation and two-phase flow effects within the proppant pack impacting hydraulic conductivity of the medium were probed. A significant reduction in effective oil permeability at irreducible water saturation was observed due to increase in confining pressure. We propose different mechanisms responsible for the observed permeability reduction in different fracture packings. Samples with dissimilar proppant grain distributions showed significantly different proppant embedment behavior. Thinner proppant layer increased embedment significantly and lowered the onset confining pressure of embedment. As confining stress was increased, small embedments caused the surface of the shale to fracture. The produced shale fragments were then entrained by the flow and partially blocked pore-throat connections within the proppant pack. Deformation of proppant packs resulted in significant changes in waterflood residual oil saturation. In-situ contact angles measured using micro-CT images showed that proppant grains had experienced a drastic alteration of wettability (from strong water-wet to weakly oil-wet) after the medium had been subjected to flow of oil and brine for multiple weeks. Nanometer resolution SEM images captured nano-fractures induced in the shale surfaces during the experiments with mono-layer proppant packing. These fractures improved the effective permeability of the medium and shale/fracture interactions.

Formation resistivity as an indicator of oil generation in black shales

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

Hester, T.C.; Schmoker, J.W.

1987-08-01

Black, organic-rich shales of Late Devonian-Early Mississippi age are present in many basins of the North American craton and, where mature, have significant economic importance as hydrocarbon source rocks. Examples drawn from the upper and lower shale members of the Bakken Formation, Williston basin, North Dakota, and the Woodford Shale, Anadarko basin, Oklahoma, demonstrate the utility of formation resistivity as a direct in-situ indicator of oil generation in black shales. With the onset of oil generation, nonconductive hydrocarbons begin to replace conductive pore water, and the resistivity of a given black-shale interval increases from low levels associated with thermal immaturitymore » to values approaching infinity. Crossplots of a thermal-maturity index (R/sub 0/ or TTI) versus formation resistivity define two populations representing immature shales and shales that have generated oil. A resistivity of 35 ohm-m marks the boundary between immature and mature source rocks for each of the three shales studied. Thermal maturity-resistivity crossplots make possible a straightforward determination of thermal maturity at the onset of oil generation, and are sufficiently precise to detect subtle differences in source-rock properties. For example, the threshold of oil generation in the upper Bakken shale occurs at R/sub 0/ = 0.43-0.45% (TTI = 10-12). The threshold increases to R/sub 0/ = 0.48-0.51% (TTI = 20-26) in the lower Bakken shale, and to R/sub 0/ = 0.56-0.57% (TTI = 33-48) in the most resistive Woodford interval.« less

Detection of cretaceous incised-valley shale for resource play, Miano gas field, SW Pakistan: Spectral decomposition using continuous wavelet transform

NASA Astrophysics Data System (ADS)

Naseer, Muhammad Tayyab; Asim, Shazia

2017-10-01

Unconventional resource shales can play a critical role in economic growth throughout the world. The hydrocarbon potential of faults/fractured shales is the most significant challenge for unconventional prospect generation. The continuous wavelet transforms (CWT) of spectral decomposition (SD) technology is applied for shale gas prospects on high-resolution 3D seismic data from the Miano area in the Indus platform, SW Pakistan. Schmoker' technique reveals high-quality shales with total organic carbon (TOC) of 9.2% distributed in the western regions. The seismic amplitude, root-mean-square (RMS), and most positive curvature attributes show limited ability to resolve the prospective fractured shale components. The CWT is used to identify the hydrocarbon-bearing faulted/fractured compartments encased within the non-hydrocarbon bearing shale units. The hydrocarbon-bearing shales experience higher amplitudes (4694 dB and 3439 dB) than the non-reservoir shales (3290 dB). Cross plots between sweetness, 22 Hz spectral decomposition, and the seismic amplitudes are found more effective tools than the conventional seismic attribute mapping for discriminating the seal and reservoir elements within the incised-valley petroleum system. Rock physics distinguish the productive sediments from the non-productive sediments, suggesting the potential for future shale play exploration.

Review of the scientific evidence to support environmental risk assessment of shale gas development in the UK.

PubMed

Prpich, George; Coulon, Frédéric; Anthony, Edward J

2016-09-01

Interest in the development of shale gas resources using hydraulic fracturing techniques is increasing worldwide despite concerns about the environmental risks associated with this activity. In the United Kingdom (UK), early attempts to hydraulically fracture a shale gas well resulted in a seismic event that led to the suspension of all hydraulic fracturing operations. In response to this occurrence, UK regulators have requested that future shale gas operations that use hydraulic fracturing should be accompanied by a high-level environmental risk assessment (ERA). Completion of an ERA can demonstrate competency, communicate understanding, and ultimately build trust that environmental risks are being managed properly, however, this assessment requires a scientific evidence base. In this paper we discuss how the ERA became a preferred assessment technique to understand the risks related to shale gas development in the UK, and how it can be used to communicate information between stakeholders. We also provide a review of the evidence base that describes the environmental risks related to shale gas operations, which could be used to support an ERA. Finally, we conclude with an update of the current environmental risks associated with shale gas development in the UK and present recommendations for further research. Copyright © 2015 Elsevier B.V. All rights reserved.

How microfracture roughness can be used to distinguish between exhumed cracks and in-situ flow paths in shales

NASA Astrophysics Data System (ADS)

Pluymakers, Anne; Kobchenko, Maya; Renard, François

2017-01-01

Flow through fractures in shales is of importance to many geoengineering purposes. Shales are not only caprocks to hydrocarbon reservoirs and nuclear waste or CO2 storage sites, but also potential source and reservoir rocks for hydrocarbons. The presence of microfractures in shales controls their permeability and transport properties. Using X-ray micro-tomography and white light interferometry we scanned borehole samples obtained from 4 km depth in the Pomeranian shales in Poland. These samples contain open exhumation/drying cracks as well as intact vein-rock interfaces plus one striated slip surface. At micron resolution and above tensile drying cracks exhibit a power-law roughness with a scaling exponent, called the Hurst exponent H, of 0.3. At sub-micron resolution we capture the properties of the clay interface only, with H = 0.6. In contrast, the in-situ formed veins and slip surface exhibit H = 0.4-0.5, which is deemed representative for in-situ fractures. These results are discussed in relation to the shale microstructure and linear elastic fracture mechanics theory. The data imply that the Hurst roughness exponent can be used as a microstructural criterion to distinguish between exhumation and in-situ fractures, providing a step forward towards the characterization of potential flow paths at depth in shales.

Crack deflection in brittle media with heterogeneous interfaces and its application in shale fracking

NASA Astrophysics Data System (ADS)

Zeng, Xiaguang; Wei, Yujie

Driven by the rapid progress in exploiting unconventional energy resources such as shale gas, there is growing interest in hydraulic fracture of brittle yet heterogeneous shales. In particular, how hydraulic cracks interact with natural weak zones in sedimentary rocks to form permeable cracking networks is of significance in engineering practice. Such a process is typically influenced by crack deflection, material anisotropy, crack-surface friction, crustal stresses, and so on. In this work, we extend the He-Hutchinson theory (He and Hutchinson, 1989) to give the closed-form formulae of the strain energy release rate of a hydraulic crack with arbitrary angles with respect to the crustal stress. The critical conditions in which the hydraulic crack deflects into weak interfaces and exhibits a dependence on crack-surface friction and crustal stress anisotropy are given in explicit formulae. We reveal analytically that, with increasing pressure, hydraulic fracture in shales may sequentially undergo friction locking, mode II fracture, and mixed mode fracture. Mode II fracture dominates the hydraulic fracturing process and the impinging angle between the hydraulic crack and the weak interface is the determining factor that accounts for crack deflection; the lower friction coefficient between cracked planes and the greater crustal stress difference favor hydraulic fracturing. In addition to shale fracking, the analytical solution of crack deflection could be used in failure analysis of other brittle media.

Late Devonian conodonts and event stratigraphy in northwestern Algerian Sahara

NASA Astrophysics Data System (ADS)

Mahboubi, Abdessamed; Gatovsky, Yury

2015-01-01

Conodonts recovered from the Late Devonian South Marhouma section comprise 5 genera with 31 species (3 undetermined). The fauna establishes the presence of MN Zones 5, undifferentiated 6/7, 8/10 for the Middle Frasnian, the MN Zones 11, 12, 13 for the Upper Frasnian as well as the Early through Late triangularis Zones in the basal Famennian. The outcropping lithological succession is one of mostly nodular calcilutites alternating with numerous marly and shaly deposits, which, in the lower and upper part, comprise several dysoxic dark shale intervals. Among these the Upper Kellwasser horizon can be precisely dated and as such the presence of the terminal Frasnian Kellwasser Event is recognized for the first time in Algeria. Both the Middlesex and Rhinestreet Events cannot yet be precisely located, but supposedly occur among the dark shale horizons in the lower part of the section. However, their assignment to a precise level has so far not been established. Though poor in conodont abundance the South Marhouma section provides first evidence of the presence of several Montagne Noire conodont zones within the so far widely unstudied Frasnian of the Ougarta Chain. As such it is considered representative for the northwestern Algerian Saoura region.

Visual classification of very fine-grained sediments: Evaluation through univariate and multivariate statistics

USGS Publications Warehouse

Hohn, M. Ed; Nuhfer, E.B.; Vinopal, R.J.; Klanderman, D.S.

1980-01-01

Classifying very fine-grained rocks through fabric elements provides information about depositional environments, but is subject to the biases of visual taxonomy. To evaluate the statistical significance of an empirical classification of very fine-grained rocks, samples from Devonian shales in four cored wells in West Virginia and Virginia were measured for 15 variables: quartz, illite, pyrite and expandable clays determined by X-ray diffraction; total sulfur, organic content, inorganic carbon, matrix density, bulk density, porosity, silt, as well as density, sonic travel time, resistivity, and ??-ray response measured from well logs. The four lithologic types comprised: (1) sharply banded shale, (2) thinly laminated shale, (3) lenticularly laminated shale, and (4) nonbanded shale. Univariate and multivariate analyses of variance showed that the lithologic classification reflects significant differences for the variables measured, difference that can be detected independently of stratigraphic effects. Little-known statistical methods found useful in this work included: the multivariate analysis of variance with more than one effect, simultaneous plotting of samples and variables on canonical variates, and the use of parametric ANOVA and MANOVA on ranked data. ?? 1980 Plenum Publishing Corporation.

Influence of Mineralogy, Pressure, Temperature and Stress on Mechanical roperties of shale Rocks

NASA Astrophysics Data System (ADS)

Herrmann, J.; Rybacki, E.; Sone, H.; Dresen, G. H.

2017-12-01

The production of hydrocarbons from unconventional reservoirs, like tight shale plays increased tremendously over the past decade. Hydraulic fracturing is a common method to increase the productivity of a well drilled in these reservoirs. Unfortunately, the production rate decreases over time presumably due to fracture healing. The healing rate induced by proppant embedment depends on pressure (p), temperature (T), stress (σ) - conditions and on shale composition. To improve understanding of the influence of these parameters on fracture healing, we conducted constant strain rate experiments (p = 50 - 100 MPa, T = 50 - 125 °C, ɛ/t = 5 * 10-4 - 5 * 10-6 s-1) on porous ( 8 %), quartz - rich ( 72 vol %) Bowland shale (UK) and on low porosity ( 3 %), clay - rich ( 33 vol %) Posidonia shale (GER), deformed perpendicular to bedding and with as-is water content. Bowland shale showed mainly brittle behaviour with predominantly elastic deformation before failure and a high strength (280 - 350 MPa). In contrast, Posidonia shale deformed semibrittle with pronounced inelastic deformation and low peak strength (165 - 220 MPa). For both shale rocks, static Young's moduli vary between 12 - 18 GPa. In addition, we performed a series of constant stress tests on both shales at p = 30 - 115 MPa, T = 75 - 150 °C and σ = 160 - 450 MPa. Samples showed transient (primary) creep with increasing strain rates for increasing temperature and stress and decreasing pressure. An empirical power law in the form of ɛ = A*tm is used to describe the observed relation between inelastic strain (ɛ) and time (t), where the constant A is mainly affected by temperature and stress and the exponent m accounts for the influence of pressure. Compared to quartz - rich, strong Bowland shale, the creep behaviour of clay - rich, weak Posidonia shale is much more sensitive to changes in pressure, temperature and stress. Electron microscopy suggests that creep was mainly accommodated by deformation of weak phases (TOC, clay, mica). Our results suggest a low fracture healing rate of Bowland shale, whereas fractures within the Posidonia formation tend to close faster.

Cracking mechanism of shale cracks during fracturing

NASA Astrophysics Data System (ADS)

Zhao, X. J.; Zhan, Q.; Fan, H.; Zhao, H. B.; An, F. J.

2018-06-01

In this paper, we set up a model for calculating the shale fracture pressure on the basis of Huang’s model by the theory of elastic-plastic mechanics, rock mechanics and the application of the maximum tensile stress criterion, which takes into account such factors as the crustal stress field, chemical field, temperature field, tectonic stress field, the porosity of shale and seepage of drilling fluid and so on. Combined with the experimental data of field fracturing and the experimental results of three axis compression of shale core with different water contents, the results show that the error between the present study and the measured value is 3.85%, so the present study can provide technical support for drilling engineering.

Defining the natural fracture network in a shale gas play and its cover succession: The case of the Utica Shale in eastern Canada

NASA Astrophysics Data System (ADS)

Ladevèze, P.; Séjourné, S.; Rivard, C.; Lavoie, D.; Lefebvre, R.; Rouleau, A.

2018-03-01

In the St. Lawrence sedimentary platform (eastern Canada), very little data are available between shallow fresh water aquifers and deep geological hydrocarbon reservoir units (here referred to as the intermediate zone). Characterization of this intermediate zone is crucial, as the latter controls aquifer vulnerability to operations carried out at depth. In this paper, the natural fracture networks in shallow aquifers and in the Utica shale gas reservoir are documented in an attempt to indirectly characterize the intermediate zone. This study used structural data from outcrops, shallow observation well logs and deep shale gas well logs to propose a conceptual model of the natural fracture network. Shallow and deep fractures were categorized into three sets of steeply-dipping fractures and into a set of bedding-parallel fractures. Some lithological and structural controls on fracture distribution were identified. The regional geologic history and similarities between the shallow and deep fracture datasets allowed the extrapolation of the fracture network characterization to the intermediate zone. This study thus highlights the benefits of using both datasets simultaneously, while they are generally interpreted separately. Recommendations are also proposed for future environmental assessment studies in which the existence of preferential flow pathways and potential upward fluid migration toward shallow aquifers need to be identified.

Double torsion fracture mechanics testing of shales under chemically reactive conditions

NASA Astrophysics Data System (ADS)

Chen, X.; Callahan, O. A.; Holder, J. T.; Olson, J. E.; Eichhubl, P.

2015-12-01

Fracture properties of shales is vital for applications such as shale and tight gas development, and seal performance of carbon storage reservoirs. We analyze the fracture behavior from samples of Marcellus, Woodford, and Mancos shales using double-torsion (DT) load relaxation fracture tests. The DT test allows the determination of mode-I fracture toughness (KIC), subcritical crack growth index (SCI), and the stress-intensity factor vs crack velocity (K-V) curves. Samples are tested at ambient air and aqueous conditions with variable ionic concentrations of NaCl and CaCl2, and temperatures up to 70 to determine the effects of chemical/environmental conditions on fracture. Under ambient air condition, KIC determined from DT tests is 1.51±0.32, 0.85±0.25, 1.08±0.17 MPam1/2 for Marcellus, Woodford, and Mancos shales, respectively. Tests under water showed considerable change of KIC compared to ambient condition, with 10.6% increase for Marcellus, 36.5% decrease for Woodford, and 6.7% decrease for Mancos shales. SCI under ambient air condition is between 56 and 80 for the shales tested. The presence of water results in a significant reduction of the SCI from 70% to 85% compared to air condition. Tests under chemically reactive solutions are currently being performed with temperature control. K-V curves under ambient air conditions are linear with stable SCI throughout the load-relaxation period. However, tests conducted under water result in an initial cracking period with SCI values comparable to ambient air tests, which then gradually transition into stable but significantly lower SCI values of 10-20. The non-linear K-V curves reveal that crack propagation in shales is initially limited by the transport of chemical agents due to their low permeability. Only after the initial cracking do interactions at the crack tip lead to cracking controlled by faster stress corrosion reactions. The decrease of SCI in water indicates higher crack propagation velocity due to faster stress corrosion rate in water than in ambient air. The experimental results are applicable for the prediction of fracture initiation based on KIC, modeling fracture pattern based on SCI, and the estimation of dynamic fracture propagation such as crack growth velocity and crack re-initiation.

In-situ laser retorting of oil shale

NASA Technical Reports Server (NTRS)

Bloomfield, H. S. (Inventor)

1977-01-01

Oil shale formations are retorted in situ and gaseous hydrocarbon products are recovered by drilling two or more wells into an oil shale formation underneath the surface of the ground. A high energy laser beam is directed into the well and fractures the region of the shale formation. A compressed gas is forced into the well that supports combustion in the flame front ignited by the laser beam, thereby retorting the oil shale. Gaseous hydrocarbon products which permeate through the fractured region are recovered from one of the wells that were not exposed to the laser system.

Subcritical fracturing of shales under chemically reactive conditions

NASA Astrophysics Data System (ADS)

Chen, X.; Callahan, O. A.; Eichhubl, P.; Olson, J. E.

2016-12-01

Growth of opening-mode fractures under chemically reactive subsurface conditions is potentially relevant for seal integrity in subsurface CO2 storage and hazardous waste disposal. Using double-torsion load relaxation tests we determine mode-I fracture toughness (KIC), subcritical index (SCI), and the stress-intensity factor vs fracture velocity (K-V) behavior of Marcellus, Woodford, and Mancos shales. Samples are tested under ambient air and aqueous conditions with variable NaCl and KCl concentrations, variable pH, and temperatures of up to 70. Under ambient air condition, KIC determined from double torsion tests is 1.3, 0.6, and 1.1 MPam1/2 for Marcellus, Woodford, and Mancos shales, respectively. SCI under ambient air condition is between 55 and 90 for the shales tested. Tests in aqueous solutions show a significant drop of KIC compared to ambient air condition. For tests in deionized water, KIC reduction is 18.5% for Marcellus and 47.0% for Woodford. The presence of aqueous fluids also results in a reduction of the SCI up to 85% compared to ambient condition. K-V curves generally obey a power-law relation throughout the load-relaxation period. However, aqueous-based tests on samples result in K-V curves deviating from the power-law relation, with the SCI values gradually decreasing with time during the relaxation period. This non-power-law behavior is obvious in Woodford and Mancos, but negligible in Marcellus. We find that the shales interact with the aqueous solution both at the fracture tip and within the rock matrix during subcritical fracturing. For Marcellus shale, water mainly interacts with the fracture tip on both tests due to low matrix permeability and less reactive mineral composition. However, Woodford and Mancos react strongly with water causing significant sample degradation. The competition between degradation and fracture growth results in the time-dependent SCI: at lower fracture velocities, the tip interacts longer with the chemically altered area around the tip; at higher fracture velocities, the fracture propagates through the altered area before significant degradation. Our results display strong weakening effects of chemically reactive fluids on subcritical fracture properties with implications on subsurface storage seal performance.

Experimental study of CO2 effect on shale mechanical properties in the processes of complete strain-stress and post-failure tests

NASA Astrophysics Data System (ADS)

Wang, Y.; Ji, J.; Li, M.

2017-12-01

CO2 enhanced shale gas recovery has proved to be one of the most efficient methods to extract shale gas, and represent a mutually beneficial approach to mitigate greenhouse gas emission into the atmosphere. During the processes of most CO2 enhanced shale gas recovery, liquid CO2 is injected into reservoirs, fracturing the shale, making competitive adsorption with shale gas and displacing the shale gas at multi-scale to the production well. Hydraulic and mechanical coupling actions between the shale and fluid media are expected to play important roles in affecting fracture propagation, CO2 adsorption and shale gas desorption, multi-scale fluid flow, plume development, and CO2 storage. In this study, four reservoir shale samples were selected to carry out triaxial compression experiments of complete strain-stress and post failure tests. Two fluid media, CO2 and N2, were used to flow through the samples and produce the pore pressure. All of the above four compression experiments were conducted under the same confining and pore pressures, and loaded the axial pressure with the same loading path. Permeability, strain-stress, and pore volumetric change were measured and recorded over time. The results show that, compared to N2, CO2 appeared to lower the peak strength and elastic modulus of shale samples, and increase the permeability up two to six orders of magnitudes after the sample failure. Furthermore, the shale samples were dilated by CO2 much more than N2, and retained the volume of CO2 2.6 times more than N2. Results from this study indicate that the CO2 can embrittle the shale formation so as to form fracture net easily to enhance the shale gas recovery. Meanwhile, part of the remaining CO2 might be adsorbed on the surface of shale matrix and the rest of the CO2 be in the pore and fracture spaces, implying that CO2 can be effectively geo-stored in the shale formation.

Reconnaissance of ground-water resources in the Eastern Coal Field Region, Kentucky

USGS Publications Warehouse

Price, William E.; Mull, D.S.; Kilburn, Chabot

1962-01-01

In the Eastern Coal Field region of Kentucky, water is obtained from consolidated sedimentary rocks ranging in age from Devonian to Pennsylvanian and from unconsolidated sediments of Quaternary age. About 95 percent of the area is underlain by shale, sandstone, and coal of Pennsylvanian age. Principal factors governing the availability of water in the region are depth, topographic location, and the lithology of the aquifer penetrated. In general, the yield of the well increases as the depth increases. Wells drilled in topographic lows, such as valleys, are likely to yield more water than wells drilled on topographic highs, such as hills. Sand and gravel, present in thick beds in the alluvium along the Ohio River, form the most productive aquifer in the Eastern Coal Field. Of the consolidated rocks in the region sandstone strata are the best aquifers chiefly because joints, openings along bedding planes, and intergranular pore spaces are best developed in them. Shale also supplies water to many wells in the region, chiefly from joints and openings along bedding planes. Coal constitutes a very small part of the sedimentary section, but it yields water from fractures to many wells. Limestone yields water readily from solution cavities developed along joint and bedding-plane openings. The availability of water in different parts of the region was determined chiefly by analyzing well data collected during the reconnaissance. The resulting water-availability maps, published as hydrologic investigations atlases (Price and others, 1961 a, b; Kilburn and others, 1961) were designed to be used in conjunction with this report. The maps were constructed by dividing the region into 5 physiographic areas, into 10 subareas based chiefly on lithologic facies, and, in the case of the Kanawha section, into 2 quality-of-water areas. The 5 physiographic areas are the Knobs, Mississippian Plateau, Cumberland Plateau section, Kanawha section, and Cumberland Mountain section. The 10 subareas are as follows: 1. The Chattanooga shale. This black shale yields only enough water for a minimum domestic supply-100 to 500 gpd (gallons per day). 2. Mississippian-Devonian rocks exposed along Pine Mountain. These rocks consist of shale, limestone, and sandstone. The limestone yields water to springs, and faulted limestone and sandstone lying below drainage may yield several hundred gallons per minute to wells. 3. Mississippian rocks exposed along the western margin of the region. These rocks consist of thick limestone underlain by shale. The limestone yields enough water for a modern domestic supply (more than 500 gpd) , and discharges as much as 100 gpm (gallons per minute) to springs. The shale yields only enough water for a minimum domestic supply. 4. Subarea 1 of the Lee formation of Pennsylvanian age. The thin shaly rocks of this subarea generally yield only enough water for a minimum domestic supply. 5. Subarea 2 of the Lee formation of Pennsylvanian age. This subarea is predominantly underlain by massive sandstones; it generally yields enough water for a modern domestic supply, and in some places, enough water for small public and industrial supplies. 6. Subarea 1 of the Breathitt and Conemaugh formations of Pennsylvanian age. Rocks in this subarea contain more shale than sandstone. Wells in this subarea range from adequate for a minimum domestic supply to adequate for a modern domestic supply. 7. Subarea 2 of the Breathitt formation of Pennsylvanian age and undifferentiated post-Lee Pennsylvanian rocks. Wells in this subarea yield enough water for a modern domestic supply, and in many places, enough water for small public and industrial supplies. 8. Alluvium along the Ohio River. Mostly composed of glacial outwash sand and gravel, the alluvium is reported to yield as much as 360 gpm to wells. 9. Alluvium along the Big Sandy River and lower reaches of its Tug and Levisa Forks. Where consisting mostly of sand,

Stratigraphic and palaeoenvironmental summary of the south-east Georgia Embayment: a correlation of exploratory wells

USGS Publications Warehouse

Poppe, L.J.; Popenoe, P.; Poag, C.W.; Swift, B.A.

1995-01-01

A Continental Offshore Stratigraphic Test (COST) well and six exploratory wells have been drilled in the south-east Georgia embayment. The oldest rocks penetrated are weakly metamorphosed Lower Ordovician quartz arenites and Silurian shales and argillites in the Transco 1005-1 well and Upper Devonian argillites in the COST GE-1 well. The Palaeozoic strata are unconformably overlain by interbedded non-marine Jurassic sandstones and shales and marginal marine Lower Cretaceous rocks. Together, these rocks are stratigraphically equivalent to the onshore Fort Pierce and Cotton Valley(?) Formations and rocks of the Lower Cretaceous Comanchean Provincial Series. The Upper Cretaceous part of the section is composed mainly of neritic calcareous shales and shaley limestones stratigraphically equivalent to the primarily marginal marine facies of the onshore Atkinson, Cape Fear and Middendorf Formations and Black Creek Group, and to limestones and shales of the Lawson Limestone and Peedee Formations. Cenozoic strata are also described. -from Authors

School and Community Impacts of Hydraulic Fracturing within Pennsylvania's Marcellus Shale Region, and the Dilemmas of Educational Leadership in Gasfield Boomtowns

ERIC Educational Resources Information Center

Schafft, Kai A.; Biddle, Catharine

2014-01-01

Innovations associated with gas and oil drilling technology, including new hydraulic fracturing and horizontal drilling techniques, have recently led to dramatic boomtown development in many rural areas that have endured extended periods of economic decline. The Marcellus Shale play, one of the world's largest gas-bearing shale formations, lies…

Germanium and uranium in coalified wood from Upper Devonian black shale

USGS Publications Warehouse

Breger, Irving A.; Schopf, James M.

1954-01-01

Microscopic study of black, vitreous, carbonaceous material occurring in the Chattanooga shale in Tennessee and in the Cleveland member of the Ohio shale in Ohio has revealed coalified woody plant tissue. Some samples have shown sufficient detail to be identified with the genus Callixylon. Similar material has been reported in the literature as "bituminous" or "asphaltic" stringers. Spectrographic analyses of the ash from the coalified wood have shown unusually high percentages of germanium, uranium, vanadium, and nickel. The inverse relationship between uranium and germanium in the ash and the ash content of various samples shows an association of these elements with the organic constituents of the coal. On the basis of geochemical considerations, it seems most probable that the wood or coalified wood was germanium-bearing at the time logs or woody fragments were floated into the basins of deposition of the Chattanooga shale and the Cleveland member of the Ohio shale. Once within the marine environment, the material probably absorbed uranium with the formation of organo-uranium compounds such as have been found to exist in coals. It is suggested that a more systematic search for germaniferous coals in the vicinity of the Chattanooga shale and the Cleveland member of the Ohio shale might be rewarding.

Understanding public perception of hydraulic fracturing: a case study in Spain.

PubMed

Costa, D; Pereira, V; Góis, J; Danko, A; Fiúza, A

2017-12-15

Public acceptance is crucial for the implementation of energy technologies. Hydraulic fracturing is a technology widely used in the USA for natural gas production from shale formations, but currently finds strong public opposition worldwide, especially in Europe. Shale gas exploitation and exploration have the potential to significantly reduce import dependency in several countries, including Spain. To better understand public opinion on this issue, this article reports a survey targeting both the entire Spanish population and the inhabitants of the province of Burgos, the location where shale gas exploration permits have already been issued. Results demonstrate that half of the Spanish population opposes shale gas, and this opposition increases in autonomous communities that are closer to possible exploration sites. The results also show that socio-demographic aspects are not strong predictors of opposition. In addition, Burgos' population show different behaviours toward shale gas that demonstrates that proximity and prospect of shale gas development affects opinion. Finally, there is still a great level of unfamiliarity with high volume hydraulic fracturing and shale gas in both populations sampled. Copyright © 2017 Elsevier Ltd. All rights reserved.

Impact of ductility on hydraulic fracturing in shales

NASA Astrophysics Data System (ADS)

Auton, Lucy; MacMinn, Chris

2015-11-01

Hydraulic fracturing is a method for extracting natural gas and oil from low-permeability rocks such as shale via the injection of fluid at high pressure. This creates fractures in the rock, providing hydraulic access deeper into the reservoir and enabling gas to be collected from a larger region of the rock. Fracture is the tensile failure of a brittle material upon reaching a threshold tensile stress, but some shales have a high clay content and may yield plastically before fracturing. Plastic deformation is the shear failure of a ductile material, during which stress relaxes through irreversible rearrangements of the particles of the material. Here, we investigate the impact of the ductility of shales on hydraulic fracturing. We consider a simple, axisymmetric model for radially outward fluid injection from a wellbore into a ductile porous rock. We solve the model semi-analytically at steady state, and numerically in general. We find that plastic deformation greatly reduces the maximum tensile stress, and that this maximum stress does not always occur at the wellbore. These results imply that hydraulic fracturing may fail in ductile rocks, or that the required injection rate for fracking may be much larger than the rate predicted from purely elastic models.

The three-zone composite productivity model for a multi-fractured horizontal shale gas well

NASA Astrophysics Data System (ADS)

Qi, Qian; Zhu, Weiyao

2018-02-01

Due to the nano-micro pore structures and the massive multi-stage multi-cluster hydraulic fracturing in shale gas reservoirs, the multi-scale seepage flows are much more complicated than in most other conventional reservoirs, and are crucial for the economic development of shale gas. In this study, a new multi-scale non-linear flow model was established and simplified, based on different diffusion and slip correction coefficients. Due to the fact that different flow laws existed between the fracture network and matrix zone, a three-zone composite model was proposed. Then, according to the conformal transformation combined with the law of equivalent percolation resistance, the productivity equation of a horizontal fractured well, with consideration given to diffusion, slip, desorption, and absorption, was built. Also, an analytic solution was derived, and the interference of the multi-cluster fractures was analyzed. The results indicated that the diffusion of the shale gas was mainly in the transition and Fick diffusion regions. The matrix permeability was found to be influenced by slippage and diffusion, which was determined by the pore pressure and diameter according to the Knudsen number. It was determined that, with the increased half-lengths of the fracture clusters, flow conductivity of the fractures, and permeability of the fracture network, the productivity of the fractured well also increased. Meanwhile, with the increased number of fractures, the distance between the fractures decreased, and the productivity slowly increased due to the mutual interfere of the fractures.

Accumulation of organic matter in the in the Rome trough of the Appalachian basin and its subsequent thermal history

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

Curtis, J.B.; Faure, G.

1997-03-01

We used geochemical data to examine the origin and preservation of organic matter contained in the lower part of the Huron Member of the Ohio Shale formation and the Rhinestreet Shale Member of the West Falls Formation (Devonian) in Kentucky, Ohio, West Virginia, and Virginia. The thermal history of the organic matter was determined by relating relative temperatures experienced by the organic matter to the geologic setting. The organic matter in these formations is predominantly marine in origin and was most probably derived largely from algal organisms. Although the rate of production of marine organic matter may have been uniformmore » within the basin, its preservation apparently was controlled by the existence of a set of fault-bounded anoxic subbasins associated with the Rome trough, a Cambrian structural complex. These subbasins apparently were anoxic because they limited oxygen recharge by circulating waters. Preservation of organic matter was also enhanced by periodic blooms of the alga Tasmanites and similar organisms in the waters above the subbasins during both early Huron and Rhinestreet deposition. A significant negative correlation was identified between the vitrinite reflectance peak temperature, and integrated measure of the thermal history of a rock, and the hydrogen index, a measure of the remaining hydrocarbon-generation potential of kerogen. Although peak temperatures were controlled by burial depth, excess heating occurred locally, perhaps by hot brines rising from depth through fractures associated with major structures in the study area.« less

Understanding hydraulic fracturing: a multi-scale problem.

PubMed

Hyman, J D; Jiménez-Martínez, J; Viswanathan, H S; Carey, J W; Porter, M L; Rougier, E; Karra, S; Kang, Q; Frash, L; Chen, L; Lei, Z; O'Malley, D; Makedonska, N

2016-10-13

Despite the impact that hydraulic fracturing has had on the energy sector, the physical mechanisms that control its efficiency and environmental impacts remain poorly understood in part because the length scales involved range from nanometres to kilometres. We characterize flow and transport in shale formations across and between these scales using integrated computational, theoretical and experimental efforts/methods. At the field scale, we use discrete fracture network modelling to simulate production of a hydraulically fractured well from a fracture network that is based on the site characterization of a shale gas reservoir. At the core scale, we use triaxial fracture experiments and a finite-discrete element model to study dynamic fracture/crack propagation in low permeability shale. We use lattice Boltzmann pore-scale simulations and microfluidic experiments in both synthetic and shale rock micromodels to study pore-scale flow and transport phenomena, including multi-phase flow and fluids mixing. A mechanistic description and integration of these multiple scales is required for accurate predictions of production and the eventual optimization of hydrocarbon extraction from unconventional reservoirs. Finally, we discuss the potential of CO2 as an alternative working fluid, both in fracturing and re-stimulating activities, beyond its environmental advantages.This article is part of the themed issue 'Energy and the subsurface'. © 2016 The Author(s).

Understanding hydraulic fracturing: a multi-scale problem

PubMed Central

Hyman, J. D.; Jiménez-Martínez, J.; Viswanathan, H. S.; Carey, J. W.; Porter, M. L.; Rougier, E.; Karra, S.; Kang, Q.; Frash, L.; Chen, L.; Lei, Z.; O’Malley, D.; Makedonska, N.

2016-01-01

Despite the impact that hydraulic fracturing has had on the energy sector, the physical mechanisms that control its efficiency and environmental impacts remain poorly understood in part because the length scales involved range from nanometres to kilometres. We characterize flow and transport in shale formations across and between these scales using integrated computational, theoretical and experimental efforts/methods. At the field scale, we use discrete fracture network modelling to simulate production of a hydraulically fractured well from a fracture network that is based on the site characterization of a shale gas reservoir. At the core scale, we use triaxial fracture experiments and a finite-discrete element model to study dynamic fracture/crack propagation in low permeability shale. We use lattice Boltzmann pore-scale simulations and microfluidic experiments in both synthetic and shale rock micromodels to study pore-scale flow and transport phenomena, including multi-phase flow and fluids mixing. A mechanistic description and integration of these multiple scales is required for accurate predictions of production and the eventual optimization of hydrocarbon extraction from unconventional reservoirs. Finally, we discuss the potential of CO2 as an alternative working fluid, both in fracturing and re-stimulating activities, beyond its environmental advantages. This article is part of the themed issue ‘Energy and the subsurface’. PMID:27597789

187Re - 187Os nuclear geochronometry: age dating with permil precision

NASA Astrophysics Data System (ADS)

Roller, Goetz

2016-04-01

Recently, 187Re - 187Os nuclear geochronometry, a new dating method combining ideas of nuclear astrophysics with geochronology, has successfully been used to calculate two-point-isochron (TPI) ages for Devonian black gas shales using the isotopic signature of an r-process geochronometer as one data point in a TPI diagram [1]. Based upon a nuclear production ratio 187Re/188Os = 5.873, TPI ages were calculated for 12 SDO-1 (Devonian Ohio Shale, Appalachian Basin) aliquants, for which repeated Re-Os measurements are reported in the literature [2]. TPI ages range from 384.5 ± 2.7 Ma (187Os/188Osi = 0.29413 ± 0.00023) to 387.7 ± 2.1 Ma (187Os/188Osi = 0.29407 ± 0.00019) with a mean of 386.67 ± 1.79 Ma). The result is consistent with the isochronous age from the 12 aliquants alone (386 ± 16 Ma, 187Os/188Osi = 0.31±0.31), which is bracketed by U-Pb ages for the Belpre Ash (381.1 ± 3.3 Ma) and the Tioga Ash bed (390.0 ± 2.5 Ma) [3] from the Appalachian Basin. Hence, SDO-1 can be assigned to the Givetian stage (varcus-zone) of the Middle Devonian, close to the Eifelian/Givetian boundary (using the time-scale of [3] or [4]). If an age is calculated from an isochron diagram for the 12 aliquants including the nuclear geochronometer, a permil precision can be achieved, an interesting feature with respect to any effort towards calibrating the Geologic Timescale. Additionally, a Th/U evolution (or: Th/U-time) diagram can be plotted using U-Pb zircon age data and Th/U ratios from volcanic rocks and ashes reported in the literature [3] for specific Devonian samples from the Appalachian Basin. Since the Re-Os age obtained for SDO-1 can also be connected to its Th/U ratio, it turns out, that Th/U ratios might be helpful age indicators, as demonstrated for the Devonian using the U-Pb and Re-Os datasets. [1] Roller (2015), GSA Abstr. with Programs 47, #248-14. [2] Du Vivier et al. (2014), Earth Planet. Sci. Lett. 389, 23 - 33. [3] Tucker et al. (1998), Earth Planet. Sci. Lett. 158, 175 - 186. [4] Kaufmann (2006), Earth-Sci. Revs. 76, 175 - 190.

Organic Substances from Unconventional Oil and Gas Production in Shale

NASA Astrophysics Data System (ADS)

Orem, W. H.; Varonka, M.; Crosby, L.; Schell, T.; Bates, A.; Engle, M.

2014-12-01

Unconventional oil and gas (UOG) production has emerged as an important element in the US and world energy mix. Technological innovations in the oil and gas industry, especially horizontal drilling and hydraulic fracturing, allow for the enhanced release of oil and natural gas from shale compared to conventional oil and gas production. This has made commercial exploitation possible on a large scale. Although UOG is enormously successful, there is surprisingly little known about the effects of this technology on the targeted shale formation and on environmental impacts of oil and gas production at the surface. We examined water samples from both conventional and UOG shale wells to determine the composition, source and fate of organic substances present. Extraction of hydrocarbon from shale plays involves the creation and expansion of fractures through the hydraulic fracturing process. This process involves the injection of large volumes of a water-sand mix treated with organic and inorganic chemicals to assist the process and prop open the fractures created. Formation water from a well in the New Albany Shale that was not hydraulically fractured (no injected chemicals) had total organic carbon (TOC) levels that averaged 8 mg/L, and organic substances that included: long-chain fatty acids, alkanes, polycyclic aromatic hydrocarbons, heterocyclic compounds, alkyl benzenes, and alkyl phenols. In contrast, water from UOG production in the Marcellus Shale had TOC levels as high as 5,500 mg/L, and contained a range of organic chemicals including, solvents, biocides, scale inhibitors, and other organic chemicals at thousands of μg/L for individual compounds. These chemicals and TOC decreased rapidly over the first 20 days of water recovery as injected fluids were recovered, but residual organic compounds (some naturally-occurring) remained up to 250 days after the start of water recovery (TOC 10-30 mg/L). Results show how hydraulic fracturing changes the organic composition of shale formation water, and that some injected organic substances are retained on the shale and slowly released. Thus, appropriate safe disposal of produced water is needed long into production. Changes in organic substances in formation water may impact microbial communities. Current work is focused on UOG production in the Permian Basin, Texas.

Feasibility Assessment of CO2 Sequestration and Enhanced Recovery in Gas Shale Reservoirs

NASA Astrophysics Data System (ADS)

Vermylen, J. P.; Hagin, P. N.; Zoback, M. D.

2008-12-01

CO2 sequestration and enhanced methane recovery may be feasible in unconventional, organic-rich, gas shale reservoirs in which the methane is stored as an adsorbed phase. Previous studies have shown that organic-rich, Appalachian Devonian shales adsorb approximately five times more carbon dioxide than methane at reservoir conditions. However, the enhanced recovery and sequestration concept has not yet been tested for gas shale reservoirs under realistic flow and production conditions. Using the lessons learned from previous studies on enhanced coalbed methane (ECBM) as a starting point, we are conducting laboratory experiments, reservoir modeling, and fluid flow simulations to test the feasibility of sequestration and enhanced recovery in gas shales. Our laboratory work investigates both adsorption and mechanical properties of shale samples to use as inputs for fluid flow simulation. Static and dynamic mechanical properties of shale samples are measured using a triaxial press under realistic reservoir conditions with varying gas saturations and compositions. Adsorption is simultaneously measured using standard, static, volumetric techniques. Permeability is measured using pulse decay methods calibrated to standard Darcy flow measurements. Fluid flow simulations are conducted using the reservoir simulator GEM that has successfully modeled enhanced recovery in coal. The results of the flow simulation are combined with the laboratory results to determine if enhanced recovery and CO2 sequestration is feasible in gas shale reservoirs.

Draft Genome Sequence of Pseudomonas sp. BDAL1 Reconstructed from a Bakken Shale Hydraulic Fracturing-Produced Water Storage Tank Metagenome

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

Lipus, Daniel; Ross, Daniel; Bibby, Kyle

We report the 5,425,832 bp draft genome ofPseudomonassp. strain BDAL1, recovered from a Bakken shale hydraulic fracturing-produced water tank metagenome. Genome annotation revealed several key biofilm formation genes and osmotic stress response mechanisms necessary for survival in hydraulic fracturing-produced water.

Draft Genome Sequence of Pseudomonas sp. BDAL1 Reconstructed from a Bakken Shale Hydraulic Fracturing-Produced Water Storage Tank Metagenome

DOE PAGES

Lipus, Daniel; Ross, Daniel; Bibby, Kyle; ...

2017-03-16

We report the 5,425,832 bp draft genome ofPseudomonassp. strain BDAL1, recovered from a Bakken shale hydraulic fracturing-produced water tank metagenome. Genome annotation revealed several key biofilm formation genes and osmotic stress response mechanisms necessary for survival in hydraulic fracturing-produced water.

The water footprint of hydraulic fracturing in Sichuan Basin, China.

PubMed

Zou, Caineng; Ni, Yunyan; Li, Jian; Kondash, Andrew; Coyte, Rachel; Lauer, Nancy; Cui, Huiying; Liao, Fengrong; Vengosh, Avner

2018-07-15

Shale gas is likely to play a major role in China's transition away from coal. In addition to technological and infrastructural constraints, the main challenges to China's sustainable shale gas development are sufficient shale gas production, water availability, and adequate wastewater management. Here we present, for the first time, actual data of shale gas production and its water footprint from the Weiyuan gas field, one of the major gas fields in Sichuan Basin. We show that shale gas production rates during the first 12 months (24 million m 3 per well) are similar to gas production rates in U.S. shale basins. The amount of water used for hydraulic fracturing (34,000 m 3 per well) and the volume of flowback and produced (FP) water in the first 12 months (19,800 m 3 per well) in Sichuan Basin are also similar to the current water footprints of hydraulic fracturing in U.S. basins. We present salinity data of the FP water (5000 to 40,000 mgCl/L) in Sichuan Basin and the treatment operations, which include sedimentation, dilution with fresh water, and recycling of the FP water for hydraulic fracturing. We utilize the water use data, empirical decline rates of shale gas and FP water productions in Sichuan Basin to generate two prediction models for water use for hydraulic fracturing and FP water production upon achieving China's goals to generate 100 billion m 3 of shale gas by 2030. The first model utilizes the current water use and FP production data, and the second assumes a yearly 5% intensification of the hydraulic fracturing process. The predicted water use for hydraulic fracturing in 2030 (50-65 million m 3 per year), FP water production (50-55 million m 3 per year), and fresh water dilution of FP water (25 million m 3 per year) constitute a water footprint that is much smaller than current water consumption and wastewater generation for coal mining, but higher than those of conventional gas production in China. Given estimates for water availability in Sichuan Basin, our predictions suggest that water might not be a limiting factor for future large-scale shale gas development in Sichuan Basin. Copyright © 2018 Elsevier B.V. All rights reserved.

Quantitative prediction of fractures using the finite element method: A case study of the lower Silurian Longmaxi Formation in northern Guizhou, South China

NASA Astrophysics Data System (ADS)

Liu, Jingshou; Ding, Wenlong; Yang, Haimeng; Jiu, Kai; Wang, Zhe; Li, Ang

2018-04-01

Natural fractures have long been considered important factors in the production of gas from shale reservoirs because they can connect pore spaces and enlarge transport channels, thereby influencing the migration, accumulation and preservation of shale gas. Industrial-level shale gas production has been initiated in the lower Silurian Longmaxi Formation in northern Guizhou, South China. However, it is important to quantitatively predict the distribution of natural fractures in the lower Silurian shale reservoirs to locate additional 'sweet spots' in northern Guizhou. In this study, data obtained from outcrops, cores, thin sections, field-emission scanning electron microscope (FE-SEM) images and X-ray diffraction (XRD) were used to determine the developmental characteristics and controlling factors of these fractures. Correlation analysis indicated that the mechanical parameters of the Longmaxi shale are mainly related to the total organic carbon (TOC), quartz, clay, calcite and dolomite contents. The spatial variations in the mechanical parameters of the Longmaxi shale were determined based on the spatial variations in the TOC and mineral contents. Then, a heterogeneous geomechanical model of the study area was established based on interpretations of the fault systems derived from seismic data and acoustic emission (AE) experiments performed on samples of the relevant rocks. The paleotectonic stress fields during the Yanshanian period were obtained using the finite element method (FEM). Finally, a fracture density calculation model was established to analyze the quantitative development of fractures, and the effects of faults and mechanical parameters on the development of fractures were determined. The results suggest that the main developmental period of tectonic fractures in the Longmaxi Formation was the Early Yanshanian period. During this time, the horizontal principal stress conditions were dominated by a SE-NW-trending (135-315°) compressional stress field, and the Longmaxi Formation experienced a maximum tectonic stress of 110-120 MPa. This simulated paleotectonic stress field was mainly controlled by faults and the contents of TOC, quartz, clay, calcite and dolomite; at different positions along the same fault, the degree of fracture development varies significantly. Overall, the distribution of fractures in the Longmaxi Formation can be used to optimize well deployment and provides a basis for the future exploration of shale gas.

Geological and petrological considerations relevant to the disposal of radioactive wastes by hydraulic fracturing: an example at the US Department of Energy's Oak Ridge National Laboratory. [Pumpkin Valley shales

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

Haase, C.S.

1982-01-01

At Oak Ridge National Laboratory the Pumpkin Valley Shale is used as a host formation for hydraulic-fracturing waste disposal. Determination of the relationships between the distribution of different lithologies and porosity-permeability trends within this host formation allows these properties, important to hydraulic-fracturing operations, to be related to measurable and mappable geological and petrological parameters. It also permits extrapolation of such patterns to little-studied portions of the Pumpkin Valley Shale. Such knowledge better allows for the satisfactory operation and assessment of the hydraulic fracturing at Oak Ridge National Laboratory.

A critical review of the risks to water resources from unconventional shale gas development and hydraulic fracturing in the United States.

PubMed

Vengosh, Avner; Jackson, Robert B; Warner, Nathaniel; Darrah, Thomas H; Kondash, Andrew

2014-01-01

The rapid rise of shale gas development through horizontal drilling and high volume hydraulic fracturing has expanded the extraction of hydrocarbon resources in the U.S. The rise of shale gas development has triggered an intense public debate regarding the potential environmental and human health effects from hydraulic fracturing. This paper provides a critical review of the potential risks that shale gas operations pose to water resources, with an emphasis on case studies mostly from the U.S. Four potential risks for water resources are identified: (1) the contamination of shallow aquifers with fugitive hydrocarbon gases (i.e., stray gas contamination), which can also potentially lead to the salinization of shallow groundwater through leaking natural gas wells and subsurface flow; (2) the contamination of surface water and shallow groundwater from spills, leaks, and/or the disposal of inadequately treated shale gas wastewater; (3) the accumulation of toxic and radioactive elements in soil or stream sediments near disposal or spill sites; and (4) the overextraction of water resources for high-volume hydraulic fracturing that could induce water shortages or conflicts with other water users, particularly in water-scarce areas. Analysis of published data (through January 2014) reveals evidence for stray gas contamination, surface water impacts in areas of intensive shale gas development, and the accumulation of radium isotopes in some disposal and spill sites. The direct contamination of shallow groundwater from hydraulic fracturing fluids and deep formation waters by hydraulic fracturing itself, however, remains controversial.

A dual-porosity model for simulating solute transport in oil shale

USGS Publications Warehouse

Glover, K.C.

1987-01-01

A model is described for simulating three-dimensional groundwater flow and solute transport in oil shale and associated geohydrologic units. The model treats oil shale as a dual-porosity medium by simulating flow and transport within fractures using the finite-element method. Diffusion of solute between fractures and the essentially static water of the shale matrix is simulated by including an analytical solution that acts as a source-sink term to the differential equation of solute transport. While knowledge of fracture orientation and spacing is needed to effectively use the model, it is not necessary to map the locations of individual fractures. The computer program listed in the report incorporates many of the features of previous dual-porosity models while retaining a practical approach to solving field problems. As a result the theory of solute transport is not extended in any appreciable way. The emphasis is on bringing together various aspects of solute transport theory in a manner that is particularly suited to the unusual groundwater flow and solute transport characteristics of oil shale systems. (Author 's abstract)

Aquifer Characteristics Data Report for the Weldon Spring Site chemical plant/raffinate pits and vicinity properties for the Weldon Spring Site Remedial Action Project, Weldon Spring, Missouri

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

Not Available

1990-11-01

This report describes the procedures and methods used, and presents the results of physical testing performed, to characterize the hydraulic properties of the shallow Mississippian-Devonian aquifer beneath the Weldon Spring chemical plant, raffinate pits, and vicinity properties. The aquifer of concern is composed of saturated rocks of the Burlington-Keokuk Limestone which constitutes the upper portion of the Mississippian-Devonian aquifer. This aquifer is a heterogeneous anisotropic medium which can be described in terms of diffuse Darcian flow overlain by high porosity discrete flow zones and conduits. Average hydraulic conductivity for all wells tested is 9.6E-02 meters/day (3.1E-01 feet/day). High hydraulic conductivitymore » values are representative of discrete flow in the fractured and weathered zones in the upper Burlington-Keokuk Limestone. They indicate heterogeneities within the Mississippian-Devonian aquifer. Aquifer heterogeneity in the horizontal plane is believed to be randomly distributed and is a function of fracture spacing, solution voids, and preglacial weathering phenomena. Relatively high hydraulic conductivities in deeper portions of the aquifer are though to be due to the presence of widely spaced fractures. 44 refs., 27 figs., 9 tabs.« less

Shale Frac Sequential Flowback Analyses and Reuse Implications, March 30, 2011

EPA Pesticide Factsheets

Water re-use challenges and solutions have direct and indirect influences in the design of hydraulic fracturing fluid systems and products used in High Volume, High Rate (HVHR) hydraulic fracturing of shale wells (1,2).

Eastern gas shales bibliography selected annotations: gas, oil, uranium, etc. Citations in bituminous shales worldwide

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

Hall, V.S.

1980-06-01

This bibliography contains 2702 citations, most of which are annotated. They are arranged by author in numerical order with a geographical index following the listing. The work is international in scope and covers the early geological literature, continuing through 1979 with a few 1980 citations in Addendum II. Addendum I contains a listing of the reports, well logs and symposiums of the Unconventional Gas Recovery Program (UGR) through August 1979. There is an author-subject index for these publications following the listing. The second part of Addendum I is a listing of the UGR maps which also has a subject-author indexmore » following the map listing. Addendum II includes several important new titles on the Devonian shale as well as a few older citations which were not found until after the bibliography had been numbered and essentially completed. A geographic index for these citations follows this listing.« less

Introduction to special section: China shale gas and shale oil plays

USGS Publications Warehouse

Jiang, Shu; Zeng, Hongliu; Zhang, Jinchuan; Fishman, Neil; Bai, Baojun; Xiao, Xianming; Zhang, Tongwei; Ellis, Geoffrey S.; Li, Xinjing; Richards-McClung, Bryony; Cai, Dongsheng; Ma, Yongsheng

2015-01-01

Even though China shale gas and shale oil exploration is still in an early stage, limited data are already available. We are pleased to have selected eight high-quality papers from fifteen submitted manuscripts for this timely section on the topic of China shale gas and shale oil plays. These selected papers discuss various subject areas including regional geology, resource potentials, integrated and multidisciplinary characterization of China shale reservoirs (geology, geophysics, geochemistry, and petrophysics) China shale property measurement using new techniques, case studies for marine, lacustrine, and transitional shale deposits in China, and hydraulic fracturing. One paper summarizes the regional geology and different tectonic and depositional settings of the major prospective shale oil and gas plays in China. Four papers concentrate on the geology, geochemistry, reservoir characterization, lithologic heterogeneity, and sweet spot identification in the Silurian Longmaxi marine shale in the Sichuan Basin in southwest China, which is currently the primary focus of shale gas exploration in China. One paper discusses the Ordovician Salgan Shale in the Tarim Basin in northwest China, and two papers focus on the reservoir characterization and hydraulic fracturing of Triassic lacustrine shale in the Ordos Basin in northern China. Each paper discusses a specific area.

Productivity Contribution of Paleozoic Woodlands to the Formation of Shale-Hosted Massive Sulfide Deposits in the Iberian Pyrite Belt (Tharsis, Spain)

NASA Astrophysics Data System (ADS)

Fernández-Remolar, David C.; Harir, Mourad; Carrizo, Daniel; Schmitt-Kopplin, Philippe; Amils, Ricardo

2018-03-01

The geological materials produced during catastrophic and destructive events are an essential source of paleobiological knowledge. The paleobiological information recorded by such events can be rich in information on the size, diversity, and structure of paleocommunities. In this regard, the geobiological study of late Devonian organic matter sampled in Tharsis (Iberian Pyrite Belt) provided some new insights into a Paleozoic woodland community, which was recorded as massive sulfides and black shale deposits affected by a catastrophic event. Sample analysis using TOF-SIMS (Time of Flight Secondary Ion Mass Spectrometer), and complemented by GC/MS (Gas Chromatrograph/Mass Spectrometer) identified organic compounds showing a very distinct distribution in the rock. While phytochemical compounds occur homogeneously in the sample matrix that is composed of black shale, the microbial-derived organics are more abundant in the sulfide nodules. The cooccurrence of sulfur bacteria compounds and the overwhelming presence of phytochemicals provide support for the hypothesis that the formation of the massive sulfides resulted from a high rate of vegetal debris production and its oxidation through sulfate reduction under suboxic to anoxic conditions. A continuous supply of iron from hydrothermal activity coupled with microbial activity was strictly necessary to produce this massive orebody. A rough estimate of the woodland biomass was made possible by accounting for the microbial sulfur production activity recorded in the metallic sulfide. As a result, the biomass size of the late Devonian woodland community was comparable to modern woodlands like the Amazon or Congo rainforests.

Ichnology applied to sequence stratigraphic analysis of Siluro-Devonian mud-dominated shelf deposits, Paraná Basin, Brazil

NASA Astrophysics Data System (ADS)

Sedorko, Daniel; Netto, Renata G.; Savrda, Charles E.

2018-04-01

Previous studies of the Paraná Supersequence (Furnas and Ponta Grossa formations) of the Paraná Basin in southern Brazil have yielded disparate sequence stratigraphic interpretations. An integrated sedimentological, paleontological, and ichnological model was created to establish a refined sequence stratigraphic framework for this succession, focusing on the Ponta Grossa Formation. Twenty-nine ichnotaxa are recognized in the Ponta Grossa Formation, recurring assemblages of which define five trace fossil suites that represent various expressions of the Skolithos, Glossifungites and Cruziana ichnofacies. Physical sedimentologic characteristics and associated softground ichnofacies provide the basis for recognizing seven facies that reflect a passive relationship to bathymetric gradients from shallow marine (shoreface) to offshore deposition. The vertical distribution of facies provides the basis for dividing the Ponta Grossa Formation into three major (3rd-order) depositional sequences- Siluro-Devonian and Devonian I and II-each containing a record of three to seven higher-order relative sea-level cycles. Major sequence boundaries, commonly coinciding with hiatuses recognized from previously published biostratigraphic data, are locally marked by firmground Glossifungites Ichnofacies associated with submarine erosion. Maximum transgressive horizons are prominently marked by unbioturbated or weakly bioturbated black shales. By integrating observations of the Ponta Grossa Formation with those recently made on the underlying marginal- to shallow-marine Furnas Formation, the entire Paraná Supersequence can be divided into four disconformity-bound sequences: a Lower Silurian (Llandovery-Wenlock) sequence, corresponding to lower and middle units of the Furnas; a Siluro-Devonian sequence (?Pridoli-Early Emsian), and Devonian sequences I (Late Emsian-Late Eifelian) and II (Late Eifelian-Early Givetian). Stratigraphic positions of sequence boundaries generally coincide with regressive phases on established global sea-level curves for the Silurian-Devonian.

Draft Genome Sequence of Pseudomonas sp. BDAL1 Reconstructed from a Bakken Shale Hydraulic Fracturing-Produced Water Storage Tank Metagenome

PubMed Central

Lipus, Daniel; Ross, Daniel

2017-01-01

ABSTRACT We report the 5,425,832 bp draft genome of Pseudomonas sp. strain BDAL1, recovered from a Bakken shale hydraulic fracturing-produced water tank metagenome. Genome annotation revealed several key biofilm formation genes and osmotic stress response mechanisms necessary for survival in hydraulic fracturing-produced water. PMID:28302780

Hydro-fracture in the laboratory: matching diagnostic seismic signals to fracture networks

NASA Astrophysics Data System (ADS)

Gehne, S.; Benson, P. M.; Koor, N.; Dobson, K. J.; Enfield, M.; Barber, A.

2017-12-01

Hydraulic fracturing is a key process in both natural (e.g. dyke intrusion) and engineered environments (e.g. shale gas). To better understand this process, we present new data from simulated hydraulic fracturing in a controlled laboratory environment in order to track fracture nucleation (location) and propagation (velocity) in space and time to assess the fracture mechanics and developing fracture network. Fluid overpressure is used to generate a permeable network of micro tensile fractures in an anisotropic sandstone and a highly anisotropic shale. A newly developed technique, using a steel guide arrangement to direct pressurised fluid into a sealed section of an axially drilled conduit, allows the pore fluid to contact the rock directly and to initiate tensile fractures from a pre-defined zone inside the sample. Acoustic emission location is used to record and map the nucleation and development of the micro-fracture network. For both rock types, fractures progresses parallel to the bedding plane (short-transverse) if the bedding plane is aligned with the direction of σ1 requiring breakdown pressures of approximately 7 and 13MPa respectively at a confining pressure of 8MPa. The data also indicates a more ductile behaviour of the shale than expected. We use X-Ray Computed Tomography (CT) to evaluate the evolved fracture network in terms of fracture pattern and aperture. Hydraulic fracturing produces very planar fractures in the shale, with axial fractures over the entire length of the sample broadly following the bedding. In contrast, fractures in the sandstone are more diffuse, linking pore spaces as they propagate. However, secondary micro cracking, branching of the main fracture, are also observed. These new experiments suggest that fracture pattern, fracture propagation trajectories, and fracturing fluid pressures are predominantly controlled by the interaction between the anisotropic mechanical properties of the rock and the anisotropic stress environment.

Study on fracturing flowback fluid treatment technology for shale gas in Yangzhou

NASA Astrophysics Data System (ADS)

Shi, Shengwei; Du, Jiajia; Kang, Dingyu; Chen, Xinjian; Qu, Chengtun; Yu, Tao

2018-02-01

Shale gas fracturing flowback fluid has the characteristics of high viscosity, large displacement, complex components and difficult to deal with. Therefore, it is of great significance for environmental protection to treat and reuse it. In this paper, Yangzhou shale gas is taken as an object to study the treatment of shale gas fracturing flowback fluid. The results shown that the viscosity of the fracturing flowback fluid before treatment was 16.75mPa·s, and when the pH was adjusted to 3.5, with Cerium(III) sulfate and ferrous sulfate as catalyst and the dosage were 60mg/L and 120 mg/L respectively, and hydrogen peroxide dosage was 0.5%, the viscosity of fracturing folwback fluid was reduced from 16.75mPa·s to 1.97mPa·s After the oxidation treatment, adjusting pH to 7.5, and treating it with inorganic flocculant and organic flocculant, the water quality met the reinjection requirement of the average air permeability of less than or equal to 0.01 μm2.

87Sr/ 86Sr Concentrations in the Appalachian Basin: A Review

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

Mordensky, Stanley P.; Lieuallen, A. Erin; Verba, Circe

This document reviews 87Sr/ 86Sr isotope data across the Appalachian Basin from existing literature to show spatial and temporal variation. Isotope geochemistry presents a means of understanding the geochemical effects hydraulic fracturing may have on shallow ground substrates. Isotope fractionation is a naturally occurring phenomenon brought about by physical, chemical, and biological processes that partition isotopes between substances; therefore, stable isotope geochemistry allows geoscientists to understand several processes that shape the natural world. Strontium isotopes can be used as a tool to answer an array of geological and environmental inquiries. In some cases, strontium isotopes are sensitive to the introductionmore » of a non-native fluid into a system. This ability allows strontium isotopes to serve as tracers in certain systems. Recently, it has been demonstrated that strontium isotopes can serve as a monitoring tool for groundwater and surface water systems that may be affected by hydraulic fracturing fluids (Chapman et al., 2013; Kolesar Kohl et al., 2014). These studies demonstrated that 87Sr/ 86Sr values have the potential to monitor subsurface fluid migration in regions where extraction of Marcellus Shale gas is occurring. This document reviews publicly available strontium isotope data from 39 sample locations in the Appalachian Basin (Hamel et al., 2010; Chapman et al., 2012; Osborn et al., 2012; Chapman et al., 2013; Capo et al., 2014; Kolesar Kohl et al., 2014). The data is divided into two sets: stratigraphic (Upper Devonian/Lower Mississippi, Middle Devonian, and Silurian) and groundwater. ArcMap™ (ESRI, Inc.) was used to complete inverse distance weighting (IDW) analyses for each dataset to create interpolated surfaces in an attempt to find regional trends or variations in strontium isotopic values across the Appalachian Basin. 87Sr/ 86Sr varies up to ~ 0.011 across the Appalachian Basin, but the current publicly available data is limited in frequency and regional extent, causing artifacts and high uncertainty when interpolating data for locations far from sampling sites. These factors highlight the need for additional strontium isotope sampling across the region. Identifying potential contamination from hydraulic fracturing fluid in Appalachian Basin groundwater using strontium isotopes would require additional sampling. For a more comprehensive strontium isotope database, samples would need to be collected during prefracturing, syn-fracturing, and post-fracturing stages. This would add a temporal component to the spatial data and make tracing of fluid migration with strontium isotopes more accurate. Future research and modeling that incorporates subsurface geology and watershed data would also serve to increase the accuracy and certainty of the interpolations of these analyses. Prospective geospatial Appalachian Basin isotope studies would also benefit from the integration of geologic mapping because surface and subsurface geology influences observed strontium isotope values.« less

Influence of Composition and Deformation Conditions on the Strength and Brittleness of Shale Rock

NASA Astrophysics Data System (ADS)

Rybacki, E.; Reinicke, A.; Meier, T.; Makasi, M.; Dresen, G. H.

2015-12-01

Stimulation of shale gas reservoirs by hydraulic fracturing operations aims to increase the production rate by increasing the rock surface connected to the borehole. Prospective shales are often believed to display high strength and brittleness to decrease the breakdown pressure required to (re-) initiate a fracture as well as slow healing of natural and hydraulically induced fractures to increase the lifetime of the fracture network. Laboratory deformation tests were performed on several, mainly European black shales with different mineralogical composition, porosity and maturity at ambient and elevated pressures and temperatures. Mechanical properties such as compressive strength and elastic moduli strongly depend on shale composition, porosity, water content, structural anisotropy, and on pressure (P) and temperature (T) conditions, but less on strain rate. We observed a transition from brittle to semibrittle deformation at high P-T conditions, in particular for high porosity shales. At given P-T conditions, the variation of compressive strength and Young's modulus with composition can be roughly estimated from the volumetric proportion of all components including organic matter and pores. We determined also brittleness index values based on pre-failure deformation behavior, Young's modulus and bulk composition. At low P-T conditions, where samples showed pronounced post-failure weakening, brittleness may be empirically estimated from bulk composition or Young's modulus. Similar to strength, at given P-T conditions, brittleness depends on the fraction of all components and not the amount of a specific component, e.g. clays, alone. Beside strength and brittleness, knowledge of the long term creep properties of shales is required to estimate in-situ stress anisotropy and the healing of (propped) hydraulic fractures.

Horizontal drilling potential of the Cane Creek Shale, Paradox Formation, Utah

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

Morgan, C.D.; Chidsey, T.C.

1991-06-01

The Cane Creek shale of the Pennsylvanian Paradox Formation is a well-defined target for horizontal drilling. This unit is naturally fractures and consists of organic-rich marine shale with interbedded dolomitic siltstone and anhydrite. Six fields have produced oil from the Cane Creek shale in the Paradox basin fold-and-fault belt. The regional structural trend is north-northwest with productive fractures occurring along the crest and flanks of both the larger and more subtle smaller anticlines. The Long Canyon, Cane Creek, Bartlett Flat, and Shafer Canyon fields are located on large anticlines, while Lion Mesa and Wilson Canyon fields produce from subtle structuralmore » noses. The Cane Creek shale is similar to the highly productive Bakken Shale in the Williston basin. Both are (1) proven producers of high-gravity oil, (2) highly fractured organic-rich source rocks, (3) overpressured, (4) regionally extensive, and (5) solution-gas driven with little or no associated water. Even though all production from the Cane Creek shale has been from conventional vertical wells, the Long Canyon 1 well has produced nearly 1 million bbl of high-gravity, low-sulfur oil. Horizontal drilling may result in the development of new fields, enhance recovery in producing fields, and revive production in abandoned fields. In addition, several other regionally extensive organic-rich shale beds occur in the Paradox Formation. The Gothic and Chimney Rock shales for example, offer additional potential lying above the Cane Creek shale.« less

Fracture propagation during fluid injection experiments in shale at elevated confining pressures.

NASA Astrophysics Data System (ADS)

Chandler, Mike; Mecklenburgh, Julian; Rutter, Ernest; Fauchille, Anne-Laure; Taylor, Rochelle; Lee, Peter

2017-04-01

The use of hydraulic fracturing to recover shale-gas has focused attention upon the fundamental fracture properties of gas-bearing shales. Fracture propagation trajectories in these materials depend on the interaction between the anisotropic mechanical properties of the shale and the anisotropic in-situ stress field. However, there is a general paucity of available experimental data on their anisotropic mechanical, physical and fluid-flow properties, especially at elevated confining pressures. Here we report the results of laboratory-scale fluid injection experiments, for Whitby mudstone and Mancos shale (an interbedded silt and mudstone), as well as Pennant sandstone (a tight sandstone with permeability similar to shales), which is used an isotropic baseline and tight-gas sandstone analogue. Our injection experiments involved the pressurisation of a blind-ending central hole in an initially dry cylindrical sample. Pressurisation was conducted under constant volume-rate control, using silicone oils of various viscosities. The dependence of breakdown pressure on confining pressure was seen to be dependent on the rock strength, with the significantly stronger Pennant sandstone exhibiting much lower confining-pressure dependence of breakdown pressure than the weaker shales. In most experiments, a small drop in the injection pressure record was observed at what is taken to be fracture initiation, and in the Pennant sandstone this was accompanied by a small burst of acoustic energy. Breakdown was found to be rapid and uncontrollable after initiation if injection is continued, but can be limited to a slower (but still uncontrolled) rate by ceasing the injection of fluid after the breakdown initiation in experiments where it could be identified. A simplified 2-dimensional model for explaining these observations is presented in terms of the stress intensities at the tip of a pressurised crack. Additionally, we present a suite of supporting mechanical, flow and elastic measurements. Mechanical experiments include standard triaxial tests, pressure-dependent permeability experiments and fracture toughness determined using the double-torsion test. Elastic characterisation was determined through ultrasonic velocities determined using a cross-correlation method.

Geochemical and multi-isotopic ( 87Sr/ 86Sr, 143Nd/ 144Nd, 238U/ 235U) perspectives of sediment sources, depositional conditions, and diagenesis of the Marcellus Shale, Appalachian Basin, USA

DOE PAGES

Phan, Thai T.; Gardiner, James B.; Capo, Rosemary C.; ...

2017-10-25

Here, we investigate sediment sources, depositional conditions and diagenetic processes affecting the Middle Devonian Marcellus Shale in the Appalachian Basin, eastern USA, a major target of natural gas exploration. Multiple proxies, including trace metal contents, rare earth elements (REE), the Sm-Nd and Rb-Sr isotope systems, and U isotopes were applied to whole rock digestions and sequentially extracted fractions of the Marcellus shale and adjacent units from two locations in the Appalachian Basin. The narrow range of εNd values (from –7.8 to –6.4 at 390 Ma) is consistent with derivation of the clastic sedimentary component of the Marcellus Shale from amore » well-mixed source of fluvial and eolian material of the Grenville orogenic belt, and indicate minimal post-depositional alteration of the Sm-Nd system. While silicate minerals host >80% of the REE in the shale, data from sequentially extracted fractions reflect post-depositional modifications at the mineralogical scale, which is not observed in whole rock REE patterns.« less

Geochemical and multi-isotopic ( 87Sr/ 86Sr, 143Nd/ 144Nd, 238U/ 235U) perspectives of sediment sources, depositional conditions, and diagenesis of the Marcellus Shale, Appalachian Basin, USA

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

Phan, Thai T.; Gardiner, James B.; Capo, Rosemary C.

Here, we investigate sediment sources, depositional conditions and diagenetic processes affecting the Middle Devonian Marcellus Shale in the Appalachian Basin, eastern USA, a major target of natural gas exploration. Multiple proxies, including trace metal contents, rare earth elements (REE), the Sm-Nd and Rb-Sr isotope systems, and U isotopes were applied to whole rock digestions and sequentially extracted fractions of the Marcellus shale and adjacent units from two locations in the Appalachian Basin. The narrow range of εNd values (from –7.8 to –6.4 at 390 Ma) is consistent with derivation of the clastic sedimentary component of the Marcellus Shale from amore » well-mixed source of fluvial and eolian material of the Grenville orogenic belt, and indicate minimal post-depositional alteration of the Sm-Nd system. While silicate minerals host >80% of the REE in the shale, data from sequentially extracted fractions reflect post-depositional modifications at the mineralogical scale, which is not observed in whole rock REE patterns.« less

Acidization of shales with calcite cemented fractures

NASA Astrophysics Data System (ADS)

Kwiatkowski, Kamil; Szymczak, Piotr; Jarosiński, Marek

2017-04-01

Investigation of cores drilled from shale formations reveals a relatively large number of calcite-cemented fractures. Usually such fractures are reactivated during fracking and can contribute considerably to the permeability of the resulting fracture network. However, calcite coating on their surfaces effectively excludes them from production. Dissolution of the calcite cement by acidic fluids is investigated numerically with focus on the evolution of fracture morphology. Available surface area, breakthrough time, and reactant penetration length are calculated. Natural fractures in cores from Pomeranian shale formation (northern Poland) were analyzed and classified. Representative fractures are relatively thin (0.1 mm), flat and completely sealed with calcite. Next, the morphology evolution of reactivated natural fractures treated with low-pH fluids has been simulated numerically under various operating conditions. Depth-averaged equations for fracture flow and reactant transport has been solved by finite-difference method coupled with sparse-matrix solver. Transport-limited dissolution has been considered, which corresponds to the treatment with strong acids, such as HCl. Calcite coating in reactivated natural fractures dissolves in a highly non-homogeneous manner - a positive feedback between fluid transport and calcite dissolution leads to the spontaneous formation of wormhole-like patterns, in which most of the flow is focused. The wormholes carry reactive fluids deeper inside the system, which dramatically increases the range of the treatment. Non-uniformity of the dissolution patterns provides a way of retaining the fracture permeability even in the absence of the proppant, since the less dissolved regions will act as supports to keep more dissolved regions open. Evolution of fracture morphology is shown to depend strongly on the thickness of calcite layer - the thicker the coating the more pronounced wormholes are observed. However the interaction between wormholes is the strongest when coating thickness is a few times larger than the initial aperture of the fracture. This leads to formation of favorable complex networks of wormholes which provide adequate transport of reactive fluids to fracture surfaces and - at the same time - are capable of supporting fracture surfaces. As a conclusion, acidization of the reactivated fractures with hydrochloric acid seems to be an attractive treatment to apply at fracking stage or later on as EGR. The results contribute to the discussion on the use of acidization to enhance the gas production in the shale reservoirs. This communication stresses the importance of the dissolution of calcite cement in natural fractures in shale formations, which are initially sealed and become reactivated during fracking. While this research is based on the analysis of fractures in the Pomeranian shale basin its results are general enough to be applicable to different formations worldwide.

Pulse fracture simulation in shale rock reservoirs: DEM and FEM-DEM approaches

NASA Astrophysics Data System (ADS)

González, José Manuel; Zárate, Francisco; Oñate, Eugenio

2018-07-01

In this paper we analyze the capabilities of two numerical techniques based on DEM and FEM-DEM approaches for the simulation of fracture in shale rock caused by a pulse of pressure. We have studied the evolution of fracture in several fracture scenarios related to the initial stress state in the soil or the pressure pulse peak. Fracture length and type of failure have been taken as reference for validating the models. The results obtained show a good approximation to FEM results from the literature.

Geochemistry of formation waters from the Wolfcamp and “Cline” shales: Insights into brine origin, reservoir connectivity, and fluid flow in the Permian Basin, USA

USGS Publications Warehouse

Engle, Mark A.; Reyes, Francisco R.; Varonka, Matthew S.; Orem, William H.; Lin, Ma; Ianno, Adam J.; Westphal, Tiffani M.; Xu, Pei; Carroll, Kenneth C.

2016-01-01

Despite being one of the most important oil producing provinces in the United States, information on basinal hydrogeology and fluid flow in the Permian Basin of Texas and New Mexico is lacking. The source and geochemistry of brines from the basin were investigated (Ordovician- to Guadalupian-age reservoirs) by combining previously published data from conventional reservoirs with geochemical results for 39 new produced water samples, with a focus on those from shales. Salinity of the Ca–Cl-type brines in the basin generally increases with depth reaching a maximum in Devonian (median = 154 g/L) reservoirs, followed by decreases in salinity in the Silurian (median = 77 g/L) and Ordovician (median = 70 g/L) reservoirs. Isotopic data for B, O, H, and Sr and ion chemistry indicate three major types of water. Lower salinity fluids (<70 g/L) of meteoric origin in the middle and upper Permian hydrocarbon reservoirs (1.2–2.5 km depth; Guadalupian and Leonardian age) likely represent meteoric waters that infiltrated through and dissolved halite and anhydrite in the overlying evaporite layer. Saline (>100 g/L), isotopically heavy (O and H) water in Leonardian [Permian] to Pennsylvanian reservoirs (2–3.2 km depth) is evaporated, Late Permian seawater. Water from the Permian Wolfcamp and Pennsylvanian “Cline” shales, which are isotopically similar but lower in salinity and enriched in alkalis, appear to have developed their composition due to post-illitization diffusion into the shales. Samples from the “Cline” shale are further enriched with NH4, Br, I and isotopically light B, sourced from the breakdown of marine kerogen in the unit. Lower salinity waters (<100 g/L) in Devonian and deeper reservoirs (>3 km depth), which plot near the modern local meteoric water line, are distinct from the water in overlying reservoirs. We propose that these deep meteoric waters are part of a newly identified hydrogeologic unit: the Deep Basin Meteoric Aquifer System. Chemical, isotopic, and pressure data suggest that despite over-pressuring in the Wolfcamp shale, there is little potential for vertical fluid migration to the surface environment via natural conduits.

Permeability evolution due to dissolution of natural shale fractures reactivated by fracking

NASA Astrophysics Data System (ADS)

Kwiatkowski, Kamil; Kwiatkowski, Tomasz; Szymczak, Piotr

2015-04-01

Investigation of cores drilled from gas-bearing shale formations reveals a relatively large number of calcite-cemented fractures. During fracking, some of these fractures will be reactivated [1-2] and may become important flow paths in the resulting fracture system. In this communication, we investigate numerically the effect of low-pH reactive fluid on such fractures. The low-pH fluids can either be pumped during the initial fracking stage (as suggested e.g. by Grieser et al., [3]) or injected later, as part of enhanced gas recovery (EGR) processes. In particular, it has been suggested that CO2 injection can be considered as a method of EGR [4], which is attractive as it can potentially be combined with simultaneous CO2 sequestration. However, when mixed with brine, CO2 becomes acidic and thus can be a dissolving agent for the carbonate cement in the fractures. The dissolution of the cement leads to the enhancement of permeability and interconnectivity of the fracture network and, as a result, increases the overall capacity of the reservoir. Importantly, we show that the dissolution of such fractures proceeds in a highly non-homogeneous manner - a positive feedback between fluid transport and mineral dissolution leads to the spontaneous formation of pronounced flow channels, frequently referred to as "wormholes". The wormholes carry the chemically active fluid deeper inside the system, which dramatically speeds up the overall permeability increase. If the low-pH fluids are used during fracking, then the non-uniform dissolution becomes important for retaining the fracture permeability, even in the absence of the proppant. Whereas a uniformly etched fracture will close tightly under the overburden once the fluid pressure is removed, the nonuniform etching will tend to maintain the permeability since the less dissolved regions will act as supports to keep more dissolved regions open. [1] Gale, J. F., Reed, R. M., Holder, J. (2007). Natural fractures in the Barnett Shale and their importance for hydraulic fracture treatments. AAPG bulletin, 91(4), 603-622. [2] Walton, I., & McLennan, J. (2013, May). The Role of Natural Fractures in Shale Gas Production. In ISRM International Conference for Effective and Sustainable Hydraulic Fracturing. International Society for Rock Mechanics. [3] Grieser, W. et al. "Surface Reactive Fluid's Effect on Shale." Proceedings of the Production and Operations Symposium, 31 March-3 April 2007, Oklahoma City (SPE-106815-MS) [4] Khosrokhavar, R., Griffiths, S., & Wolf, K. H. (2014). Shale Gas Formations and Their Potential for Carbon Storage: Opportunities and Outlook. Environmental Processes, 1(4), 595-611.

Modeling of fault reactivation and induced seismicity during hydraulic fracturing of shale-gas reservoirs

EPA Science Inventory

We have conducted numerical simulation studies to assess the potential for injection-induced fault reactivation and notable seismic events associated with shale-gas hydraulic fracturing operations. The modeling is generally tuned toward conditions usually encountered in the Marce...

Draft Genome Sequence of Pseudomonas sp. BDAL1 Reconstructed from a Bakken Shale Hydraulic Fracturing-Produced Water Storage Tank Metagenome.

PubMed

Lipus, Daniel; Ross, Daniel; Bibby, Kyle; Gulliver, Djuna

2017-03-16

We report the 5,425,832 bp draft genome of Pseudomonas sp. strain BDAL1, recovered from a Bakken shale hydraulic fracturing-produced water tank metagenome. Genome annotation revealed several key biofilm formation genes and osmotic stress response mechanisms necessary for survival in hydraulic fracturing-produced water. Copyright © 2017 Lipus et al.

Microbial metabolisms in a 2.5-km-deep ecosystem created by hydraulic fracturing in shales

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

Daly, Rebecca A.; Borton, Mikayla A.; Wilkins, Michael J.

Hydraulic fracturing is the industry standard for extracting hydrocarbons from shale formations. Attention has been paid to the economic benefits and environmental impacts of this process, yet the biogeochemical changes induced in the deep subsurface are poorly understood. Recent single-gene investigations revealed that halotolerant microbial communities were enriched after hydraulic fracturing. Here the reconstruction of 31 unique genomes coupled to metabolite data from the Marcellus and Utica shales revealed that methylamine cycling supports methanogenesis in the deep biosphere. Fermentation of injected chemical additives also sustains long-term microbial persistence, while sulfide generation from thiosulfate represents a poorly recognized corrosion mechanism inmore » shales. Extensive links between viruses and microbial hosts demonstrate active viral predation, which may contribute to the release of labile cellular constituents into the extracellular environment. Our analyses show that hydraulic fracturing provides the organismal and chemical inputs for colonization and persistence in the deep terrestrial subsurface.« less

Characterization of the Oriskany and Berea Sandstones: Evaluating Biogeochemical Reactions of Potential Sandstone–Hydraulic Fracturing Fluid Interaction

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

Verba, Circe; Harris, Aubrey

The Marcellus shale, located in the mid-Atlantic Appalachian Basin, has been identified as a source for natural gas and targeted for hydraulic fracturing recovery methods. Hydraulic fracturing is a technique used by the oil and gas industry to access petroleum reserves in geologic formations that cannot be accessed with conventional drilling techniques (Capo et al., 2014). This unconventional technique fractures rock formations that have low permeability by pumping pressurized hydraulic fracturing fluids into the subsurface. Although the major components of hydraulic fracturing fluid are water and sand, chemicals, such as recalcitrant biocides and polyacrylamide, are also used (Frac Focus, 2015).more » There is domestic concern that the chemicals could reach groundwater or surface water during transport, storage, or the fracturing process (Chapman et al., 2012). In the event of a surface spill, understanding the natural attenuation of the chemicals in hydraulic fracturing fluid, as well as the physical and chemical properties of the aquifers surrounding the spill site, will help mitigate potential dangers to drinking water. However, reports on the degradation pathways of these chemicals are limited in existing literature. The Appalachian Basin Marcellus shale and its surrounding sandstones host diverse mineralogical suites. During the hydraulic fracturing process, the hydraulic fracturing fluids come into contact with variable mineral compositions. The reactions between the fracturing fluid chemicals and the minerals are very diverse. This report: 1) describes common minerals (e.g. quartz, clay, pyrite, and carbonates) present in the Marcellus shale, as well as the Oriskany and Berea sandstones, which are located stratigraphically below and above the Marcellus shale; 2) summarizes the existing literature of the degradation pathways for common hydraulic fracturing fluid chemicals [polyacrylamide, ethylene glycol, poly(diallyldimethylammonium chloride), glutaraldehyde, guar gum, and isopropanol]; 3) reviews the known research about the interactions between several hydraulic fracturing chemicals [e.g. polyacrylamide, ethylene glycol, poly(diallyldimethylammonium chloride), and glutaraldehyde] with the minerals (quartz, clay, pyrite, and carbonates) common to the lithologies of the Marcellus shale and its surrounding sandstones; and 4) characterizes the Berea sandstone and analyzes the physical and chemical effects of flowing guar gum through a Berea sandstone core.« less

Effect of water on critical and subcritical fracture properties of Woodford shale

NASA Astrophysics Data System (ADS)

Chen, Xiaofeng; Eichhubl, Peter; Olson, Jon E.

2017-04-01

Subcritical fracture behavior of shales under aqueous conditions is poorly characterized despite increased relevance to oil and gas resource development and seal integrity in waste disposal and subsurface carbon sequestration. We measured subcritical fracture properties of Woodford shale in ambient air, dry CO2 gas, and deionized water by using the double-torsion method. Compared to tests in ambient air, the presence of water reduces fracture toughness by 50%, subcritical index by 77%, and shear modulus by 27% and increases inelastic deformation. Comparison between test specimens coated with a hydrophobic agent and uncoated specimens demonstrates that the interaction of water with the bulk rock results in the reduction of fracture toughness and enhanced plastic effects, while water-rock interaction limited to the vicinity of the propagating fracture tip by a hydrophobic specimen coating lowers subcritical index and increases fracture velocity. The observed deviation of a rate-dependent subcritical index from the power law K-V relations for coated specimens tested in water is attributed to a time-dependent weakening process resulting from the interaction between water and clays in the vicinity of the fracture tip.

Potential Repercussions Associated with Halanaerobium Colonization of Hydraulically Fractured Shales

NASA Astrophysics Data System (ADS)

Booker, A. E.; Borton, M.; Daly, R. A.; Nicora, C.; Welch, S.; Dusane, D.; Johnston, M.; Sharma, S.; Mouser, P. J.; Cole, D. R.; Lipton, M. S.; Wrighton, K. C.; Wilkins, M.

2017-12-01

Hydraulic fracturing of black shale formations has greatly increased U.S. oil and natural gas recovery. Bacterial Halanaerobium strains become the dominant microbial community member in produced fluids from many fractured shales, regardless of their geographic location. Halanaerobium is not native to the subsurface, but is inadvertently introduced during the drilling and fracturing process. The accumulation of biomass in pipelines and reservoirs is detrimental due to possible well souring, microbially-induced corrosion, and pore clogging. Here, we used Halanaerobium strains isolated from a hydraulically fractured well in the Utica Shale, proteogenomics, isotopic and geochemical field observations, and laboratory growth experiments to identify detrimental effects associated with Halanaerobium growth. Analysis of Halanaerobium isolate genomes and reconstructed genomes from metagenomic datasets revealed the conserved presence of rhodanese-like proteins and anaerobic sulfite reductase complexes that can convert thiosulfate to sulfide. Furthermore, laboratory growth curves confirmed the capability of Halanaerobium to grow across a wide range of pressures (14-7000 PSI). Shotgun proteomic measurements were used to track the higher abundance of rhodanese and anaerobic sulfite reductase enzymes present when thiosulfate was available in the growth media. This technique also identified a higher abundance of proteins associated with the production of extracellular polymeric substances when Halanaerobium was grown under increasing pressures. Halanaerobium culture based assays identified thiosulfate-dependent sulfide production, while pressure incubations revealed higher cellular attachment to quartz surfaces. Increased production of sulfide and organic acids during stationary growth phase suggests that fermentative Halanaerobium use thiosulfate to remove excess reductant, aiding in NAD+ recovery. Additionally, the increased cellular attachment to surfaces under pressure indicates Halanaerobium has the capability of forming cellular clusters that could clog the shale fracture network and limit natural gas recovery. These findings bring awareness to the detrimental effects that could arise from Halanaerobium growth in hydraulically fractured shales throughout the U.S.

Porosity of the Marcellus Shale: A contrast matching small-angle neutron scattering study

USGS Publications Warehouse

Bahadur, Jitendra; Ruppert, Leslie F.; Pipich, Vitaliy; Sakurovs, Richard; Melnichenko, Yuri B.

2018-01-01

Neutron scattering techniques were used to determine the effect of mineral matter on the accessibility of water and toluene to pores in the Devonian Marcellus Shale. Three Marcellus Shale samples, representing quartz-rich, clay-rich, and carbonate-rich facies, were examined using contrast matching small-angle neutron scattering (CM-SANS) at ambient pressure and temperature. Contrast matching compositions of H2O, D2O and toluene, deuterated toluene were used to probe open and closed pores of these three shale samples. Results show that although the mean pore radius was approximately the same for all three samples, the fractal dimension of the quartz-rich sample was higher than for the clay-rich and carbonate-rich samples, indicating different pore size distributions among the samples. The number density of pores was highest in the clay-rich sample and lowest in the quartz-rich sample. Contrast matching with water and toluene mixtures shows that the accessibility of pores to water and toluene also varied among the samples. In general, water accessed approximately 70–80% of the larger pores (>80 nm radius) in all three samples. At smaller pore sizes (~5–80 nm radius), the fraction of accessible pores decreases. The lowest accessibility to both fluids is at pore throat size of ~25 nm radii with the quartz-rich sample exhibiting lower accessibility than the clay- and carbonate-rich samples. The mechanism for this behaviour is unclear, but because the mineralogy of the three samples varies, it is likely that the inaccessible pores in this size range are associated with organics and not a specific mineral within the samples. At even smaller pore sizes (~<2.5 nm radius), in all samples, the fraction of accessible pores to water increases again to approximately 70–80%. Accessibility to toluene generally follows that of water; however, in the smallest pores (~<2.5 nm radius), accessibility to toluene decreases, especially in the clay-rich sample which contains about 30% more closed pores than the quartz- and carbonate-rich samples. Results from this study show that mineralogy of producing intervals within a shale reservoir can affect accessibility of pores to water and toluene and these mineralogic differences may affect hydrocarbon storage and production and hydraulic fracturing characteristics

Method of rubblization for in-situ oil shale processing

NASA Technical Reports Server (NTRS)

Yang, Lien C. (Inventor)

1985-01-01

A method that produces a uniformly rubblized oil shale bed of desirable porosity for underground, in-situ heat extraction of oil. Rubblization is the generation of rubble of various sized fragments. The method uses explosive loadings lying at different levels in adjacent holes and detonation of the explosives at different levels in sequence to achieve the fracturing and the subsequent expansion of the fractured oil shale into excavated rooms both above and below the hole pattern.

Stratigraphy, structure, and lithofacies relationships of Devonian through Permian sedimentary rocks: Paradox Basin and adjacent areas - southeastern Utah. Technical report

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

McCleary, J.; Rogers, T.; Ely, R.

Geophysical well log analysis, literature review, and field work were conducted to develop isopach, structure contour, outcrop, and facies maps and cross sections for the Devonian through Permian strata of a 14,586-km/sup 2/ (5632-square-mile) area in southeastern Utah. The study area includes part of the Paradox Basin, the salt deposits of which are of interest in siting studies for a nuclear waste repository. For this reason hydrologic models of this area are needed. This study, part of which included the development of a three-dimensional stratigraphic computer model utilizing Geographic Information System software, can serve as a base for hydrologic ormore » other models for this area. Within and adjacent to the study area, 730 wells were screened to select the 191 wells analyzed for the study. It was found that the Elbert through Molas formations did not exhibit noticeable facies changes within the study area. The Pinkerton Trail Formation exhibits moderate changes: anhydrite and shale become somewhat more abundant toward the northeast. Facies changes in the Paradox Formation are more dramatic. Thick saline facies deposits are present in the northeast, grading to thinner anhydrite and then to carbonate facies in the south and west. The lithology of the Honaker Trail Formation appears to be fairly uniform throughout the area. Facies changes in the Cutler Group are numerous and sometimes dramatic, and generally correspond to the named formations of the group. Other factors that could affect groundwater flow, such as stratigraphic cover of fine-grained rocks, area of formation outcrops, and fracturing and faulting are discussed and delineated on maps.« less

Numerical modeling of fracking fluid and methane migration through fault zones in shale gas reservoirs

NASA Astrophysics Data System (ADS)

Taherdangkoo, Reza; Tatomir, Alexandru; Sauter, Martin

2017-04-01

Hydraulic fracturing operation in shale gas reservoir has gained growing interest over the last few years. Groundwater contamination is one of the most important environmental concerns that have emerged surrounding shale gas development (Reagan et al., 2015). The potential impacts of hydraulic fracturing could be studied through the possible pathways for subsurface migration of contaminants towards overlying aquifers (Kissinger et al., 2013; Myers, 2012). The intent of this study is to investigate, by means of numerical simulation, two failure scenarios which are based on the presence of a fault zone that penetrates the full thickness of overburden and connect shale gas reservoir to aquifer. Scenario 1 addresses the potential transport of fracturing fluid from the shale into the subsurface. This scenario was modeled with COMSOL Multiphysics software. Scenario 2 deals with the leakage of methane from the reservoir into the overburden. The numerical modeling of this scenario was implemented in DuMux (free and open-source software), discrete fracture model (DFM) simulator (Tatomir, 2012). The modeling results are used to evaluate the influence of several important parameters (reservoir pressure, aquifer-reservoir separation thickness, fault zone inclination, porosity, permeability, etc.) that could affect the fluid transport through the fault zone. Furthermore, we determined the main transport mechanisms and circumstances in which would allow frack fluid or methane migrate through the fault zone into geological layers. The results show that presence of a conductive fault could reduce the contaminant travel time and a significant contaminant leakage, under certain hydraulic conditions, is most likely to occur. Bibliography Kissinger, A., Helmig, R., Ebigbo, A., Class, H., Lange, T., Sauter, M., Heitfeld, M., Klünker, J., Jahnke, W., 2013. Hydraulic fracturing in unconventional gas reservoirs: risks in the geological system, part 2. Environ Earth Sci 70, 3855-3873. Myers, T., 2012. Potential contaminant pathways from hydraulically fractured shale to aquifers. Groundwater, 50(6), 872-882. Reagan, M.T., Moridis, G.J., Keen, N.D., Johnson, J.N., 2015. Numerical simulation of the environmental impact of hydraulic fracturing of tight/shale gas reservoirs on near-surface groundwater: Background, base cases, shallow reservoirs, short-term gas, and water transport. Water Resources Research 51, 2543-2573. Tatomir, A., 2012. From Discrete to Continuum Concepts of Flow in Fractured Porous Media. Stuttgart University: University of Stuttgart.

Chemical and Isotopic Tracers of Natural Gas and Formation Waters in Fractured Shales, Feb 24-25, 2011

EPA Pesticide Factsheets

This presentation by J.McIntosh, M.Schlegal, and B.Bates from the University of Arizona compares the chemical and isotope formation in fractured shales with shallow drift aquifers, coalbeds and other deep geologic formations, based on the Illinois basin.

Fracture Design in Horizontal Shale Wells: Data Gathering to Implementation, March 10th - 11th, 2011

EPA Pesticide Factsheets

This presentation focuses on general fracture design in horizontal shale plays across the U.S. with an emphasis on the data taken into consideration for each frac job and a brief discussion of how that data is obtained and used.

Water Availability for Shale Gas Development in Sichuan Basin, China.

PubMed

Yu, Mengjun; Weinthal, Erika; Patiño-Echeverri, Dalia; Deshusses, Marc A; Zou, Caineng; Ni, Yunyan; Vengosh, Avner

2016-03-15

Unconventional shale gas development holds promise for reducing the predominant consumption of coal and increasing the utilization of natural gas in China. While China possesses some of the most abundant technically recoverable shale gas resources in the world, water availability could still be a limiting factor for hydraulic fracturing operations, in addition to geological, infrastructural, and technological barriers. Here, we project the baseline water availability for the next 15 years in Sichuan Basin, one of the most promising shale gas basins in China. Our projection shows that continued water demand for the domestic sector in Sichuan Basin could result in high to extremely high water stress in certain areas. By simulating shale gas development and using information from current water use for hydraulic fracturing in Sichuan Basin (20,000-30,000 m(3) per well), we project that during the next decade water use for shale gas development could reach 20-30 million m(3)/year, when shale gas well development is projected to be most active. While this volume is negligible relative to the projected overall domestic water use of ∼36 billion m(3)/year, we posit that intensification of hydraulic fracturing and water use might compete with other water utilization in local water-stress areas in Sichuan Basin.

Hydraulic fracturing offers view of microbial life in the deep terrestrial subsurface.

PubMed

Mouser, Paula J; Borton, Mikayla; Darrah, Thomas H; Hartsock, Angela; Wrighton, Kelly C

2016-11-01

Horizontal drilling and hydraulic fracturing are increasingly used for recovering energy resources in black shales across the globe. Although newly drilled wells are providing access to rocks and fluids from kilometer depths to study the deep biosphere, we have much to learn about microbial ecology of shales before and after 'fracking'. Recent studies provide a framework for considering how engineering activities alter this rock-hosted ecosystem. We first provide data on the geochemical environment and microbial habitability in pristine shales. Next, we summarize data showing the same pattern across fractured shales: diverse assemblages of microbes are introduced into the subsurface, eventually converging to a low diversity, halotolerant, bacterial and archaeal community. Data we synthesized show that the shale microbial community predictably shifts in response to temporal changes in geochemistry, favoring conservation of key microorganisms regardless of inputs, shale location or operators. We identified factors that constrain diversity in the shale and inhibit biodegradation at the surface, including salinity, biocides, substrates and redox. Continued research in this engineered ecosystem is required to assess additive biodegradability, quantify infrastructure biocorrosion, treat wastewaters that return to the surface and potentially enhance energy production through in situ methanogenesis. © FEMS 2016. All rights reserved. For permissions, please e-mail: journals.permissions@oup.com.

Review of hydrofracking, the environmental pollution and some new methods may be used to skip the water in fracking process

NASA Astrophysics Data System (ADS)

Wang, B.

2013-12-01

Shale gas is natural gas that is found trapped within shale formations. And it has become an increasingly important source of natural gas in the United States since start of this century. Because shales ordinarily have insufficient permeability to allow significant fluid flow to a well bore, so gas production in commercial quantities requires fractures to provide permeability. Usually, the shale gas boom is due to modern technology in hydraulic fracturing to create extensive artificial fractures around well bores. In the same time, horizontal drilling is often used with shale gas wells, to create maximum borehole surface area in contact with shale. However, the extraction and use of shale gas can affect the environment through the leaking of extraction into water supplies, and the pollution caused by improper processing of natural gas. The challenge to prevent pollution is that shale gas extractions varies widely even in the two wells that in the same project. What's more, the enormous amounts of water will be needed for drilling, while some of the largest sources of shale gas are found in deserts. So if we can find some technologies to substitute the water in the fracking process, we will not only solve the environmental problems, but also the water supply issues. There are already some methods that have been studied for this purpose, like the CO2 fracking process by Tsuyoshi Ishida et al. I will also propose our new method called air-pressure system for fracking the shales without using water in the fracking process at last.

Experimental analysis and application of the effect of stress on continental shale reservoir brittleness

NASA Astrophysics Data System (ADS)

Yin, Shuai; Lv, Dawei; Jin, Lin; Ding, Wenlong

2018-04-01

Hydraulic fracturing is an effective measure of reservoir modification for the development of shale gas. The evaluation of rock brittleness can provide a basis for the optimization of fracturing. In this paper, the effect of stress on the brittleness of shale is systematically analyzed by designing triaxial mechanics tests. The strain analysis method was used to evaluate the shale brittleness. The research indicates that, with the increase of effective confining pressure, the value of the brittleness index (B 1) decreases. There is a linear and positive correlation between the average reduction ratio of B 1 and the buried depth. The stress has a significant effect on the shale brittleness. Therefore, the rock brittleness can be overestimated without considering the influence of the buried depth or the stress of formation when using the mineral composition method. Being affected by the stress, when the brittle mineral content of the shale reservoir is 70%, 65%, 60%, and 55%, the lower limit depth of the shale gas development is 5000 m, 4400 m, 3000 m, and 1800 m, respectively. However, when the brittle mineral content of the shale is less than 50%, the brittleness index is less than 50% in all of the buried depths. In this case, the shale will not have any commercial development potential. The logging interpretation results of the brittleness index conducted with stress correction are more consistent with the real situation, and thus, this method can be better used to help the optimization of the fracturing intervals of shale gas.

Geology and total petroleum systems of the Paradox Basin, Utah, Colorado, New Mexico, and Arizona

USGS Publications Warehouse

Whidden, Katherine J.; Lillis, Paul G.; Anna, Lawrence O.; Pearson, Krystal M.; Dubiel, Russell F.

2014-01-01

The most studied source intervals are the Pennsylvanian black shales that were deposited during relative high stands in an otherwise evaporitic basin. These black shales are the source for most of the discovered hydrocarbons in the Paradox Basin. A second oil type can be traced to either a Mississippian or Permian source rock to the west, and therefore requires long-distance migration to explain its presence in the basin. Upper Cretaceous continental to nearshore-marine sandstones are interbedded with coal beds that have recognized coalbed methane potential. Precambrian and Devonian TPSs are considered hypothetical, as both are known to have organic-rich intervals, but no discovered hydrocarbons have been definitively typed back to either of these units.

Thermal maturity of type II kerogen from the New Albany Shale assessed by13C CP/MAS NMR

USGS Publications Warehouse

Werner-Zwanziger, U.; Lis, G.; Mastalerz, Maria; Schimmelmann, A.

2005-01-01

Thermal maturity of oil and gas source rocks is typically quantified in terms of vitrinite reflectance, which is based on optical properties of terrestrial woody remains. This study evaluates 13C CP/MAS NMR parameters in kerogen (i.e., the insoluble fraction of organic matter in sediments and sedimentary rocks) as proxies for thermal maturity in marine-derived source rocks where terrestrially derived vitrinite is often absent or sparse. In a suite of samples from the New Albany Shale (Middle Devonian to the Early Mississippian, Illinois Basin) the abundance of aromatic carbon in kerogen determined by 13C CP/MAS NMR correlates linearly well with vitrinite reflectance. ?? 2004 Elsevier Inc. All rights reserved.

Adequacy of Current State Setbacks for Directional High-Volume Hydraulic Fracturing in the Marcellus, Barnett, and Niobrara Shale Plays.

PubMed

Haley, Marsha; McCawley, Michael; Epstein, Anne C; Arrington, Bob; Bjerke, Elizabeth Ferrell

2016-09-01

There is an increasing awareness of the multiple potential pathways leading to human health risks from hydraulic fracturing. Setback distances are a legislative method to mitigate potential risks. We attempted to determine whether legal setback distances between well-pad sites and the public are adequate in three shale plays. We reviewed geography, current statutes and regulations, evacuations, thermal modeling, air pollution studies, and vapor cloud modeling within the Marcellus, Barnett, and Niobrara Shale Plays. The evidence suggests that presently utilized setbacks may leave the public vulnerable to explosions, radiant heat, toxic gas clouds, and air pollution from hydraulic fracturing activities. Our results suggest that setbacks may not be sufficient to reduce potential threats to human health in areas where hydraulic fracturing occurs. It is more likely that a combination of reasonable setbacks with controls for other sources of pollution associated with the process will be required. Haley M, McCawley M, Epstein AC, Arrington B, Bjerke EF. 2016. Adequacy of current state setbacks for directional high-volume hydraulic fracturing in the Marcellus, Barnett, and Niobrara Shale Plays. Environ Health Perspect 124:1323-1333; http://dx.doi.org/10.1289/ehp.1510547.

Paracontinuous boundaries within the Devonian Columbus Limestone and Delaware Formation of central Ohio

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

Conkin, J.E.; Conkin, B.M.

1994-04-01

Internal units within the Columbus Limestone (Early Devonian Emsian [Schoharie] to Middle Devonian Eifelian [late Onesquethawan]) and the Delaware Formation (Middle Devonian early Givetian [Cazenovian]) of central Ohio are separated by disconformities of the magnitude of paracontinuities. Stauffer (1909) divided the Columbus Limestone into zones A--H and the Delaware Formation into zones I--M. Within the Columbus, the A Zone (conglomerate at the base of Bellepoint Member) disconformably overlies Late Silurian beds. The D zone at top of the Bellepoint Member (bearing the Kawkawlin Metabentonite horizon) is overlain paracontinuously by the Marblehead Member (Lower Paraspirifer acuminatus-Spirifer macrothyris to Brevispirifer gregarius-Moellerina greeneimore » zones [= E--G zones]), with the Onondagan Indian Nation Metabentonite in the top of the G Zone. The Marblehead Member is overlain paracontinuously by a bone bed at base of the Venice Member (H zone = Upper Paraspirifer acuminatus- Spirifer duodenarius'' Zone). I Zone (Dublin Shale=Marcellus) of the Delaware Formation overlies the Columbus and has two bone beds at its base; Tioga Metabentonite (restricted) overlies the I Zone bone beds and is a few tenths to 1.85 feet above the base of the I Zone. Paracontinuities and bone beds occur at the bases of J, K, and L zones. Conkin and Conkin (1975) have shown Stauffer's (1909) M Zone is an extension of his L Zone. The Olentangy paracontinuously overlies the L Zone.« less

Identification Method of Mud Shale Fractures Base on Wavelet Transform

NASA Astrophysics Data System (ADS)

Xia, Weixu; Lai, Fuqiang; Luo, Han

2018-01-01

In recent years, inspired by seismic analysis technology, a new method for analysing mud shale fractures oil and gas reservoirs by logging properties has emerged. By extracting the high frequency attribute of the wavelet transform in the logging attribute, the formation information hidden in the logging signal is extracted, identified the fractures that are not recognized by conventional logging and in the identified fracture segment to show the “cycle jump”, “high value”, “spike” and other response effect is more obvious. Finally formed a complete wavelet denoising method and wavelet high frequency identification fracture method.

Sedimentary processes and depositional environments of the Horn River Shale in British Columbia, Canada

NASA Astrophysics Data System (ADS)

Yoon, Seok-Hoon; Koh, Chang-Seong; Joe, Young-Jin; Woo, Ju-Hwan; Lee, Hyun-Suk

2017-04-01

The Horn River Basin in the northeastern British Columbia, Canada, is one of the largest unconventional gas accumulations in North America. It consists mainly of Devonian shales (Horn River Formation) and is stratigraphically divided into three members, the Muskwa, Otterpark and Evie in descending order. This study focuses on sedimentary processes and depositional environments of the Horn River shale based on sedimentary facies analysis aided by well-log mineralogy (ECS) and total organic carbon (TOC) data. The shale formation consists dominantly of siliceous minerals (quartz, feldspar and mica) and subordinate clay mineral and carbonate materials, and TOC ranging from 1.0 to 7.6%. Based on sedimentary structures and micro texture, three sedimentary facies were classified: homogeneous mudstone (HM), indistinctly laminated mudstone (ILM), and planar laminated mudstone (PLM). Integrated interpretation of the sedimentary facies, lithology and TOC suggests that depositional environment of the Horn River shale was an anoxic quiescent basin plain and base-of-slope off carbonate platform or reef. In this deeper marine setting, organic-rich facies HM and ILM, dominant in the Muskwa (the upper part of the Horn River Formation) and Evie (the lower part of the Horn River Formation) members, may have been emplaced by pelagic to hemipelagic sedimentation on the anoxic sea floor with infrequent effects of low-density gravity flows (turbidity currents or nepheloid flows). In the other hand, facies PLM typifying the Otterpark Member (the middle part of the Horn River Formation) suggests more frequent inflow of bottom-hugging turbidity currents punctuating the hemipelagic settling of the background sedimentation process. The stratigraphic change of sedimentary facies and TOC content in the Horn River Formation is most appropriately interpreted to have been caused by the relative sea-level change, that is, lower TOC and frequent signal of turbidity current during the sea-level lowstand and vice versa. Therefore, the Horn River Formation represents an earlier upward shallowing environmental change from a deep basin (Evie) to shallower marginal slope (middle Otterpark), then turning back to the deeper marine environment (Muskwa) in association with overall regression-lowstand-transgression of the sea level. (This study is supported by "Research on Exploration Technologies and an Onsite Verification to Enhance the Fracturing Efficiency of a Shale Gas Formation" of the Korea Institute of Energy Technology Evaluation and Planning (KETEP), granted financial resource from the Ministry of Trade, Industry & Energy, Republic of Korea.)

Structural Mapping and Geomorphology of Ireland's Southwest Continental Shelf Using High Resolution Sonar

NASA Astrophysics Data System (ADS)

Bowden, S.; Wireman, R.

2016-02-01

Bathymetric surveys were conducted on the continental shelf off the southwest coast of County Cork, Ireland by the Marine Institute of Ireland, the Geological Survey of Ireland, and the INFOMAR project. Data were collected from July 2006 through September 2014 using a Kongsberg EM2040 multibeam echosounder aboard the R/Vs Celtic Voyager and Keary, and a Kongsberg EM1002 on the R/V Celtic Explorer. Sonar data were post-processed with CARIS HIPS and SIPS 9.0 to create 2D and 3D bathymetric and backscatter intensity surfaces with a resolution of 1 m. The offshore study site is part of the 286 Ma western Variscian orogenic front and has several massive outcrops, exhibiting 5 to 20 m of near-vertical relief. These outcrops were structurally mapped and relatively aged, and exhibit significant folding, rotation, tilting, and joint systems. Google Earth, ArcGIS, and previous terrestrial studies were used to further analyze how geomorphology is controlled by seafloor composition and structural features. Rock type and age were interpreted by comparing fracture analysis of the joints and fold trends to similar onshore outcrops documented previously, to determine an age of 416-299 Ma for the shelf's outcropping strata and associated structural features. The oldest features observed are regional anticlines and synclines containing Upper Devonian Old Red Sandstone and Lower Carboniferous shales. Within the shale layers are NE-SW plunging parasitic chevron folds. Jointing is observed in both sandstone and shale layers and is superimposed on chevron folding, with cross joints appearing to influence shallow current patterns. Rotation of the regional folds is the youngest structural feature, as both the parasitic folds and joint systems are warped. Our study shows that high resolution sonar is an effective tool for offshore structural mapping and is an important resource for understanding the geomorphology and geologic history of submerged outcrops on continental shelf systems.

Leakage detection of Marcellus Shale natural gas at an Upper Devonian gas monitoring well: a 3-d numerical modeling approach.

PubMed

Zhang, Liwei; Anderson, Nicole; Dilmore, Robert; Soeder, Daniel J; Bromhal, Grant

2014-09-16

Potential natural gas leakage into shallow, overlying formations and aquifers from Marcellus Shale gas drilling operations is a public concern. However, before natural gas could reach underground sources of drinking water (USDW), it must pass through several geologic formations. Tracer and pressure monitoring in formations overlying the Marcellus could help detect natural gas leakage at hydraulic fracturing sites before it reaches USDW. In this study, a numerical simulation code (TOUGH 2) was used to investigate the potential for detecting leaking natural gas in such an overlying geologic formation. The modeled zone was based on a gas field in Greene County, Pennsylvania, undergoing production activities. The model assumed, hypothetically, that methane (CH4), the primary component of natural gas, with some tracer, was leaking around an existing well between the Marcellus Shale and the shallower and lower-pressure Bradford Formation. The leaky well was located 170 m away from a monitoring well, in the Bradford Formation. A simulation study was performed to determine how quickly the tracer monitoring could detect a leak of a known size. Using some typical parameters for the Bradford Formation, model results showed that a detectable tracer volume fraction of 2.0 × 10(-15) would be noted at the monitoring well in 9.8 years. The most rapid detection of tracer for the leak rates simulated was 81 days, but this scenario required that the leakage release point was at the same depth as the perforation zone of the monitoring well and the zones above and below the perforation zone had low permeability, which created a preferred tracer migration pathway along the perforation zone. Sensitivity analysis indicated that the time needed to detect CH4 leakage at the monitoring well was very sensitive to changes in the thickness of the high-permeability zone, CH4 leaking rate, and production rate of the monitoring well.

Shale Fracture Analysis using the Combined Finite-Discrete Element Method

NASA Astrophysics Data System (ADS)

Carey, J. W.; Lei, Z.; Rougier, E.; Knight, E. E.; Viswanathan, H.

2014-12-01

Hydraulic fracturing (hydrofrac) is a successful method used to extract oil and gas from highly carbonate rocks like shale. However, challenges exist for industry experts estimate that for a single $10 million dollar lateral wellbore fracking operation, only 10% of the hydrocarbons contained in the rock are extracted. To better understand how to improve hydrofrac recovery efficiencies and to lower its costs, LANL recently funded the Laboratory Directed Research and Development (LDRD) project: "Discovery Science of Hydraulic Fracturing: Innovative Working Fluids and Their Interactions with Rocks, Fractures, and Hydrocarbons". Under the support of this project, the LDRD modeling team is working with the experimental team to understand fracture initiation and propagation in shale rocks. LANL's hybrid hydro-mechanical (HM) tool, the Hybrid Optimization Software Suite (HOSS), is being used to simulate the complex fracture and fragment processes under a variety of different boundary conditions. HOSS is based on the combined finite-discrete element method (FDEM) and has been proven to be a superior computational tool for multi-fracturing problems. In this work, the comparison of HOSS simulation results to triaxial core flooding experiments will be presented.

Kerogen extraction from subterranean oil shale resources

DOEpatents

Looney, Mark Dean; Lestz, Robert Steven; Hollis, Kirk; Taylor, Craig; Kinkead, Scott; Wigand, Marcus

2010-09-07

The present invention is directed to methods for extracting a kerogen-based product from subsurface (oil) shale formations, wherein such methods rely on fracturing and/or rubblizing portions of said formations so as to enhance their fluid permeability, and wherein such methods further rely on chemically modifying the shale-bound kerogen so as to render it mobile. The present invention is also directed at systems for implementing at least some of the foregoing methods. Additionally, the present invention is also directed to methods of fracturing and/or rubblizing subsurface shale formations and to methods of chemically modifying kerogen in situ so as to render it mobile.

Kerogen extraction from subterranean oil shale resources

DOEpatents

Looney, Mark Dean [Houston, TX; Lestz, Robert Steven [Missouri City, TX; Hollis, Kirk [Los Alamos, NM; Taylor, Craig [Los Alamos, NM; Kinkead, Scott [Los Alamos, NM; Wigand, Marcus [Los Alamos, NM

2009-03-10

The present invention is directed to methods for extracting a kerogen-based product from subsurface (oil) shale formations, wherein such methods rely on fracturing and/or rubblizing portions of said formations so as to enhance their fluid permeability, and wherein such methods further rely on chemically modifying the shale-bound kerogen so as to render it mobile. The present invention is also directed at systems for implementing at least some of the foregoing methods. Additionally, the present invention is also directed to methods of fracturing and/or rubblizing subsurface shale formations and to methods of chemically modifying kerogen in situ so as to render it mobile.

Unconventional Liquid Flow in Low-Permeability Media: Theory and Revisiting Darcy's Law

NASA Astrophysics Data System (ADS)

Liu, H. H.; Chen, J.

2017-12-01

About 80% of fracturing fluid remains in shale formations after hydraulic fracturing and the flow back process. It is critical to understand and accurately model the flow process of fracturing fluids in a shale formation, because the flow has many practical applications for shale gas recovery. Owing to the strong solid-liquid interaction in low-permeability media, Darcy's law is not always adequate for describing liquid flow process in a shale formation. This non-Darcy flow behavior (characterized by nonlinearity of the relationship between liquid flux and hydraulic gradient), however, has not been given enough attention in the shale gas community. The current study develops a systematic methodology to address this important issue. We developed a phenomenological model for liquid flow in shale (in which liquid flux is a power function of pressure gradient), an extension of the conventional Darcy's law, and also a methodology to estimate parameters for the phenomenological model from spontaneous imbibition tests. The validity of our new developments is verified by satisfactory comparisons of theoretical results and observations from our and other research groups. The relative importance of this non-Darcy liquid flow for hydrocarbon production in unconventional reservoirs remains an issue that needs to be further investigated.

An integrated profile of natural fractures in gas-bearing shale complex (Pomerania, Poland): based on structural profiling of oriented core and borehole logging data.

NASA Astrophysics Data System (ADS)

Bobek, Kinga; Jarosiński, Marek; Stadtmuller, Marek; Pachytel, Radomir; Lis-Śledziona, Anita

2016-04-01

Natural fractures in gas-bearing shales has significant impact on reservoir stimulation and increase of exploitation. Density of natural fractures and their orientation in respect to the maximum horizontal stress are crucial for propagation of technological hydraulic fractures. Having access to continuous borehole core profile and modern geophysical logging from several wells in the Pomeranian part of the Early Paleozoic Baltic Basin (Poland) we were able to compare the consistency of structural interpretation of several data sets. Although, final aim of our research is to optimize the method of fracture network reconstruction on a reservoir scale, at a recent stage we were focused on quantitative characterization of tectonic structures in a direct vicinity of boreholes. The data we have, cover several hundred meters long profiles of boreholes from the Ordovician and Silurian shale complexes. Combining different sets of data we broaden the scale of observation from borehole core (5 cm radius), through XRMI scan of a borehole wall (10 cm radius), up to penetration of a signal of an acoustic dipole logging (several tens of cm range). At the borehole core we examined the natural tectonic structures and mechanically significant features, like: mineral veins, fractured veins, bare fractures, slickensides, fault zones, stylolites, bedding plane and mechanically contrasting layers. We have also noticed drilling-induced features like centerline fractures and core disking, controlled by a recent tectonic stress. We have measured the orientation of fractures, their size, aperture and spacing and also describe the character of veins and tried to determine the stress regime responsible for fault slippage and fracture propagation. Wide range of analyzed features allowed us to discriminate fracture sets and reconstruct tectonic evolution of the complex. The most typical for analyzed shale complexes are steep and vertical strata-bound fractures that create an orthogonal joint system, which is locally disturbed by small-scale faults and fractures, associated with them. For regular joints, observed on borehole core, we have calculated variation of mean height and area and volume of mineralization for veins. Fracture density variation reveals good correlation with lithological shale formations which are comparable with Consistent Mechanical Units differentiated based on detailed lithological profiling and geophysical data (see Pachytel et al., this issue).We have also proposed a new method of a rose diagram construction presenting strike of fractures taking into account their size and angular error bar in strike determination. Each fracture was weighted with its length or aperture and an angular error was included by blurring the less credible records. This allowed for more precise adjustment of fracture sets direction in comparison to conventional diagrams without weighting procedure. Recently, we are processing acoustic dipole logs for anisotropy analyses aiming in comparison with density of fracture sets. Our study, which is conducted in the frame of ShaleMech Project (within Blue Gas Program) is in progress, thus the presented results should be considered as preliminary.

Study of gas production from shale reservoirs with multi-stage hydraulic fracturing horizontal well considering multiple transport mechanisms.

PubMed

Guo, Chaohua; Wei, Mingzhen; Liu, Hong

2018-01-01

Development of unconventional shale gas reservoirs (SGRs) has been boosted by the advancements in two key technologies: horizontal drilling and multi-stage hydraulic fracturing. A large number of multi-stage fractured horizontal wells (MsFHW) have been drilled to enhance reservoir production performance. Gas flow in SGRs is a multi-mechanism process, including: desorption, diffusion, and non-Darcy flow. The productivity of the SGRs with MsFHW is influenced by both reservoir conditions and hydraulic fracture properties. However, rare simulation work has been conducted for multi-stage hydraulic fractured SGRs. Most of them use well testing methods, which have too many unrealistic simplifications and assumptions. Also, no systematical work has been conducted considering all reasonable transport mechanisms. And there are very few works on sensitivity studies of uncertain parameters using real parameter ranges. Hence, a detailed and systematic study of reservoir simulation with MsFHW is still necessary. In this paper, a dual porosity model was constructed to estimate the effect of parameters on shale gas production with MsFHW. The simulation model was verified with the available field data from the Barnett Shale. The following mechanisms have been considered in this model: viscous flow, slip flow, Knudsen diffusion, and gas desorption. Langmuir isotherm was used to simulate the gas desorption process. Sensitivity analysis on SGRs' production performance with MsFHW has been conducted. Parameters influencing shale gas production were classified into two categories: reservoir parameters including matrix permeability, matrix porosity; and hydraulic fracture parameters including hydraulic fracture spacing, and fracture half-length. Typical ranges of matrix parameters have been reviewed. Sensitivity analysis have been conducted to analyze the effect of the above factors on the production performance of SGRs. Through comparison, it can be found that hydraulic fracture parameters are more sensitive compared with reservoir parameters. And reservoirs parameters mainly affect the later production period. However, the hydraulic fracture parameters have a significant effect on gas production from the early period. The results of this study can be used to improve the efficiency of history matching process. Also, it can contribute to the design and optimization of hydraulic fracture treatment design in unconventional SGRs.

Study of gas production from shale reservoirs with multi-stage hydraulic fracturing horizontal well considering multiple transport mechanisms

PubMed Central

Wei, Mingzhen; Liu, Hong

2018-01-01

Development of unconventional shale gas reservoirs (SGRs) has been boosted by the advancements in two key technologies: horizontal drilling and multi-stage hydraulic fracturing. A large number of multi-stage fractured horizontal wells (MsFHW) have been drilled to enhance reservoir production performance. Gas flow in SGRs is a multi-mechanism process, including: desorption, diffusion, and non-Darcy flow. The productivity of the SGRs with MsFHW is influenced by both reservoir conditions and hydraulic fracture properties. However, rare simulation work has been conducted for multi-stage hydraulic fractured SGRs. Most of them use well testing methods, which have too many unrealistic simplifications and assumptions. Also, no systematical work has been conducted considering all reasonable transport mechanisms. And there are very few works on sensitivity studies of uncertain parameters using real parameter ranges. Hence, a detailed and systematic study of reservoir simulation with MsFHW is still necessary. In this paper, a dual porosity model was constructed to estimate the effect of parameters on shale gas production with MsFHW. The simulation model was verified with the available field data from the Barnett Shale. The following mechanisms have been considered in this model: viscous flow, slip flow, Knudsen diffusion, and gas desorption. Langmuir isotherm was used to simulate the gas desorption process. Sensitivity analysis on SGRs’ production performance with MsFHW has been conducted. Parameters influencing shale gas production were classified into two categories: reservoir parameters including matrix permeability, matrix porosity; and hydraulic fracture parameters including hydraulic fracture spacing, and fracture half-length. Typical ranges of matrix parameters have been reviewed. Sensitivity analysis have been conducted to analyze the effect of the above factors on the production performance of SGRs. Through comparison, it can be found that hydraulic fracture parameters are more sensitive compared with reservoir parameters. And reservoirs parameters mainly affect the later production period. However, the hydraulic fracture parameters have a significant effect on gas production from the early period. The results of this study can be used to improve the efficiency of history matching process. Also, it can contribute to the design and optimization of hydraulic fracture treatment design in unconventional SGRs. PMID:29320489

Heterogeneity of shale documented by micro-FTIR and image analysis.

PubMed

Chen, Yanyan; Mastalerz, Maria; Schimmelmann, Arndt

2014-12-01

In this study, four New Albany Shale Devonian and Mississippian samples, with vitrinite reflectance [Ro ] values ranging from 0.55% to 1.41%, were analyzed by micro-FTIR mapping of chemical and mineralogical properties. One additional postmature shale sample from the Haynesville Shale (Kimmeridgian, Ro = 3.0%) was included to test the limitation of the method for more mature substrates. Relative abundances of organic matter and mineral groups (carbonates, quartz and clays) were mapped across selected microscale regions based on characteristic infrared peaks and demonstrated to be consistent with corresponding bulk compositional percentages. Mapped distributions of organic matter provide information on the organic matter abundance and the connectivity of organic matter within the overall shale matrix. The pervasive distribution of organic matter mapped in the New Albany Shale sample MM4 is in agreement with this shale's high total organic carbon abundance relative to other samples. Mapped interconnectivity of organic matter domains in New Albany Shale samples is excellent in two early mature shale samples having Ro values from 0.55% to 0.65%, then dramatically decreases in a late mature sample having an intermediate Ro of 1.15% and finally increases again in the postmature sample, which has a Ro of 1.41%. Swanson permeabilities, derived from independent mercury intrusion capillary pressure porosimetry measurements, follow the same trend among the four New Albany Shale samples, suggesting that micro-FTIR, in combination with complementary porosimetric techniques, strengthens our understanding of porosity networks. In addition, image processing and analysis software (e.g. ImageJ) have the capability to quantify organic matter and total organic carbon - valuable parameters for highly mature rocks, because they cannot be analyzed by micro-FTIR owing to the weakness of the aliphatic carbon-hydrogen signal. © 2014 The Authors Journal of Microscopy © 2014 Royal Microscopical Society.

Characterizing the variability in chemical composition of flowback and produced waters - results from lab and field studies

NASA Astrophysics Data System (ADS)

Vieth-Hillebrand, Andrea; Wilke, Franziska D. H.; Schmid, Franziska E.; Zhu, Yaling; Lipińska, Olga; Konieczyńska, Monika

2017-04-01

The huge volumes and unknown composition of flowback and produced waters cause major public concerns about the environmental and social compatibility of hydraulic fracturing and the exploitation of gas from unconventional reservoirs. Flowback and produced waters contain not only residues of fracking additives but also chemical species that are dissolved from the target shales themselves. Shales are a heterogeneous mixture of minerals, organic matter, and formation water and little is actually understood about the fluid-rock interactions occurring during hydraulic fracturing of the shales and their effects on the chemical composition of flowback and produced water. To overcome this knowledge gap, interactions of different shales with different artificial stimulation fluids were studied in lab experiments under ambient and elevated temperature and pressure conditions. These lab experiments showed clearly that fluid-rock interactions change the chemical composition of the initial stimulation fluid and that geochemistry of the fractured shale is relevant for understanding flowback water composition. In addition, flowback water samples were taken after hydraulic fracturing of one horizontal well in Pomeranian region, Poland and investigated for their chemical composition. With this presentation, results from lab and field studies will be presented and compared to decipher possible controls on chemical compositions of flowback and produced water.

Numerical simulation of the environmental impact of hydraulic fracturing of tight/shale gas reservoirs on near-surface ground water: background, base cases, shallow reservoirs, short-term gas and water transport

EPA Pesticide Factsheets

Researchers examined gas and water transport between a deep tight shale gas reservoir and a shallow overlying aquifer in the two years following hydraulic fracturing, assuming a pre-existing connecting pathway.

Degradation of hydraulic fracturing additive 2-butoxyethanol using heat activated persulfate in the presence of shale rock.

PubMed

Manz, Katherine E; Carter, Kimberly E

2018-09-01

Changes in fluid composition during hydraulic fracturing (HF) for natural gas production can impact well productivity and the water quality of the fluids returning to the surface during productivity. Shale formation conditions can influence the extent of fluid transformation. Oxidizers, such as sodium persulfate, likely play a strong role in fluid transformation. This study investigates the oxidation of 2-butoxyethanol (2-BE), a surfactant used in HF, by sodium persulfate in the presence of heat, pH changes, Fe(II), and shale rock. Increasing temperature and Fe(II) concentrations sped up 2-BE oxidation, while pH played little to no role in 2-BE degradation. The presence of shale rock impeded 2-BE oxidation with increasing shale concentrations causing decreasing pseudo-first-order reaction rate constant to be observed. Over the course of reactions containing shales, dissolved solids were tracked to better understand how reactions with minerals in the shale impact water quality. Copyright © 2018 Elsevier Ltd. All rights reserved.

Deliberating the perceived risks, benefits, and societal implications of shale gas and oil extraction by hydraulic fracturing in the US and UK

NASA Astrophysics Data System (ADS)

Thomas, Merryn; Partridge, Tristan; Harthorn, Barbara Herr; Pidgeon, Nick

2017-04-01

Shale gas and oil production in the US has increased rapidly in the past decade, while interest in prospective development has also arisen in the UK. In both countries, shale resources and the method of their extraction (hydraulic fracturing, or 'fracking') have been met with opposition amid concerns about impacts on water, greenhouse gas emissions, and health effects. Here we report the findings of a qualitative, cross-national deliberation study of public perceptions of shale development in UK and US locations not yet subject to extensive shale development. When presented with a carefully calibrated range of risks and benefits, participants' discourse focused on risks or doubts about benefits, and potential impacts were viewed as inequitably distributed. Participants drew on direct, place-based experiences as well as national contexts in deliberating shale development. These findings suggest that shale gas development already evokes a similar 'signature' of risk across the US and UK.

Microfluidic Investigation of Oil Mobilization in Shale Fracture Networks at Reservoir Conditions

NASA Astrophysics Data System (ADS)

Porter, M. L.; Jimenez-Martinez, J.; Carey, J. W.; Viswanathan, H. S.

2015-12-01

Investigations of pore-scale fluid flow and transport phenomena using engineered micromodels has steadily increased in recent years. In these investigations fluid flow is restricted to two-dimensions allowing for real time visualization and quantification of complex flow and reactive transport behavior, which is difficult to obtain in other experimental systems. One drawback to these studies is the use of engineered materials that do not faithfully represent the rock properties (e.g., porosity, wettability, roughness, etc.) encountered in subsurface formations. In this work, we describe a unique high pressure (up to 1500 psi) and temperature (up to 80 °C) microfluidics experimental system in which we investigate fluid flow and transport in geo-material (e.g., shale, Portland cement, etc.) micromodels. The use of geo-material micromodels allows us to better represent fluid-rock interactions including wettability, chemical reactivity, and nano-scale porosity at conditions representative of natural subsurface environments. Here, we present experimental results in fracture systems with applications to hydrocarbon mobility in hydraulically fractured shale. Complex fracture network patterns are derived from 3D x-ray tomography images of actual fractures created in shale rock cores. We use both shale and glass micromodels, allowing for a detailed comparison between flow phenomena in the different materials. We discuss results from two-phase huff-and-puff experiments involving N2 and n-Decane, as well as three-phase displacement experiments involving supercritical CO2, brine, and n-Decane.

Water Saturation Relations and Their Diffusion-Limited Equilibration in Gas Shale: Implications for Gas Flow in Unconventional Reservoirs

NASA Astrophysics Data System (ADS)

Tokunaga, Tetsu K.; Shen, Weijun; Wan, Jiamin; Kim, Yongman; Cihan, Abdullah; Zhang, Yingqi; Finsterle, Stefan

2017-11-01

Large volumes of water are used for hydraulic fracturing of low permeability shale reservoirs to stimulate gas production, with most of the water remaining unrecovered and distributed in a poorly understood manner within stimulated regions. Because water partitioning into shale pores controls gas release, we measured the water saturation dependence on relative humidity (rh) and capillary pressure (Pc) for imbibition (adsorption) as well as drainage (desorption) on samples of Woodford Shale. Experiments and modeling of water vapor adsorption into shale laminae at rh = 0.31 demonstrated that long times are needed to characterize equilibrium in larger (5 mm thick) pieces of shales, and yielded effective diffusion coefficients from 9 × 10-9 to 3 × 10-8 m2 s-1, similar in magnitude to the literature values for typical low porosity and low permeability rocks. Most of the experiments, conducted at 50°C on crushed shale grains in order to facilitate rapid equilibration, showed significant saturation hysteresis, and that very large Pc (˜1 MPa) are required to drain the shales. These results quantify the severity of the water blocking problem, and suggest that gas production from unconventional reservoirs is largely associated with stimulated regions that have had little or no exposure to injected water. Gravity drainage of water from fractures residing above horizontal wells reconciles gas production in the presence of largely unrecovered injected water, and is discussed in the broader context of unsaturated flow in fractures.

Impact of ductility on hydraulic fracturing in shales

NASA Astrophysics Data System (ADS)

MacMinn, Chris; Auton, Lucy

2016-04-01

Hydraulic fracturing is a method for extracting natural gas and oil from low-permeability rocks such as shale via the high-pressure injection of fluid into the bulk of the rock. The goal is to initiate and propagate fractures that will provide hydraulic access deeper into the reservoir, enabling gas or oil to be collected from a larger region of the rock. Fracture is the tensile failure of a brittle material upon reaching a threshold tensile stress, but some shales have a high clay content and may yield plastically before fracturing. Plastic deformation is the shear failure of a ductile material, during which stress relaxes through irreversible rearrangements of the particles of the material. Here, we investigate the impact of the ductility of shales on hydraulic fracturing. We first consider a simple, axisymmetric model for radially outward fluid injection from a wellbore into a ductile porous rock. We use this model to show that plastic deformation greatly reduces the maximum tensile stress, and that this maximum stress does not always occur at the wellbore. We then complement these results with laboratory experiments in an analogue system, and with numerical simulations based on the discrete element method (DEM), both of which suggest that ductile failure can indeed dramatically change the resulting deformation pattern. These results imply that hydraulic fracturing may fail in ductile rocks, or that the required injection rate for fracking may be much larger than the rate predicted from models that assume purely elastic mechanical behavior.

What is shale gas and why is it important?

EIA Publications

2012-01-01

Shale gas refers to natural gas that is trapped within shale formations. Shales are fine-grained sedimentary rocks that can be rich sources of petroleum and natural gas. Over the past decade, the combination of horizontal drilling and hydraulic fracturing has allowed access to large volumes of shale gas that were previously uneconomical to produce. The production of natural gas from shale formations has rejuvenated the natural gas industry in the United States.

Reservoir characterization of the Clough area, Barnett Shale, Wise County, Texas. Topical report, January-July 1995

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

Hill, N.C.; Lancaster, D.E.

1995-07-01

The objective of this work was to learn more about the reservoir characteristics in the Barnett Shale. Specifically, from an analysis of pressure, production, interference, and fracture treatment data in three Mitchell Energy Corporation Cough area wells, the authors can infer the relationship between the induced hydraulic fractures and the natural fracture system in the reservoir. The authors are learning something about drainage area size, shape, and orientation.

Chemical Degradation of Polyacrylamide during Hydraulic Fracturing

NASA Astrophysics Data System (ADS)

Xiong, B.; Tasker, T.; Miller, Z.; Roman-White, S.; Farina, B.; Piechowicz, B.; Burgos, W.; Joshi, P.; Zhu, L.; Gorski, C.; Zydney, A.; Kumar, M.

2017-12-01

Polyacrylamide (PAM) based friction reducers are a primary ingredient of slickwater hydraulic fracturing fluids. Little is known regarding the fate of these polymers under downhole conditions, which could have important environmental impacts including strategies for reuse or treatment of flowback water. The objective of this study was to evaluate the chemical degradation of high molecular weight PAM, including the effects of shale, oxygen, temperature, pressure, and salinity. Data were obtained with a slickwater fracturing fluid exposed to both a shale sample collected from a Marcellus shale outcrop and to Marcellus core samples at high pressures/temperatures (HPT) simulating downhole conditions. Based on size exclusion chromatography analyses, the peak molecular weight of the PAM was reduced by two orders of magnitude, from roughly 10 MDa to 200 kDa under typical HPT fracturing conditions. The rate of degradation was independent of pressure and salinity but increased significantly at high temperatures and in the presence of oxygen dissolved in fracturing fluid. Results were consistent with a free radical chain scission mechanism, supported by measurements of sub-M hydroxyl radical concentrations. The shale sample adsorbed some PAM ( 30%), but importantly it catalyzed the chemical degradation of PAM, likely due to dissolution of Fe2+ at low pH. These results provide the first evidence of radical-induced degradation of PAM under HPT hydraulic fracturing conditions without additional oxidative breaker.

Hydrocarbon potential of Morocco

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

Achnin, H.; Nairn, A.E.M.

1988-08-01

Morocco lies at the junction of the African and Eurasian plates and carries a record of their movements since the end of the Precambrian. Four structural regions with basins and troughs can be identified: Saharan (Tarfaya-Ayoun and Tindouf basins); Anti-Atlas (Souss and Ouarzazate troughs and Boudnib basin); the Essaouria, Doukkala, Tadla, Missour, High Plateau, and Guercif basins; and Meseta and Rif (Rharb and Pre-Rif basins). The targets in the Tindouf basin are Paleozoic, Cambrian, Ordovician (clastics), Devonian (limestones), and Carboniferous reservoirs sourced primarily by Silurian shales. In the remaining basins, excluding the Rharb, the reservoirs are Triassic detritals, limestones atmore » the base of the Lias and Dogger, Malm detritals, and sandy horizons in the Cretaceous. In addition to the Silurian, potential source rocks include the Carboniferous and Permo-Carboniferous shales and clays; Jurassic shales, marls, and carbonates; and Cretaceous clays. In the Rharb basin, the objectives are sand lenses within the Miocene marls. The maturation level of the organic matter generally corresponds to oil and gas. The traps are stratigraphic (lenses and reefs) and structural (horsts and folds). The seals in the pre-Jurassic rocks are shales and evaporites; in the younger rocks, shales and marl. Hydrocarbon accumulations have been found in Paleozoic, Triassic, Liassic, Malm, and Miocene rocks.« less

Explosively produced fracture of oil shale

NASA Astrophysics Data System (ADS)

Morris, W. A.

1982-05-01

Rock fragmentation research in oil shale to develop the blasting technologies and designs required to prepare a rubble bed for a modified in situ retort is reported. Experimental work is outlined, proposed studies in explosive characterization are detailed and progress in numerical calculation techniques to predict fracture of the shale is described. A detailed geologic characterization of two Anvil Points experiment sites is related to previous work at Colony Mine. The second section focuses on computer modeling and theory. The latest generation of the stress wave code SHALE, its three dimensional potential, and the slide line package for it are described. A general stress rate equation that takes energy dependence into account is discussed.

Numerical and Statistical Analysis of Fractures in Mechanically Dissimilar Rocks of Limestone Interbedded with Shale from Nash Point in Bristol Channel, South Wales, UK.

NASA Astrophysics Data System (ADS)

Adeoye-Akinde, K.; Gudmundsson, A.

2017-12-01

Heterogeneity and anisotropy, especially with layered strata within the same reservoir, makes the geometry and permeability of an in-situ fracture network challenging to forecast. This study looks at outcrops analogous to reservoir rocks for a better understanding of in-situ fracture networks and permeability, especially fracture formation, propagation, and arrest/deflection. Here, fracture geometry (e.g. length and aperture) from interbedded limestone and shale is combined with statistical and numerical modelling (using the Finite Element Method) to better forecast fracture network properties and permeability. The main aim is to bridge the gap between fracture data obtained at the core level (cm-scale) and at the seismic level (km-scale). Analysis has been made of geometric properties of over 250 fractures from the blue Lias in Nash Point, UK. As fractures propagate, energy is required to keep them going, and according to the laws of thermodynamics, this energy can be linked to entropy. As fractures grow, entropy increases, therefore, the result shows a strong linear correlation between entropy and the scaling exponent of fracture length and aperture-size distributions. Modelling is used to numerically simulate the stress/fracture behaviour in mechanically dissimilar rocks. Results show that the maximum principal compressive stress orientation changes in the host rock as the fracture-induced stress tip moves towards a more compliant (shale) layer. This behaviour can be related to the three mechanisms of fracture arrest/deflection at an interface, namely: elastic mismatch, stress barrier and Cook-Gordon debonding. Tensile stress concentrates at the contact between the stratigraphic layers, ahead of and around the propagating fracture. However, as shale stiffens with time, the stresses concentrated at the contact start to dissipate into it. This can happen in nature through diagenesis, and with greater depth of burial. This study also investigates how induced fractures propagate and interact with existing discontinuities in layered rocks using analogue modelling. Further work will introduce the Maximum Entropy Method for more accurate statistical modelling. This method is mainly useful to forecast likely fracture-size probability distributions from incomplete subsurface information.

Understanding Hydraulic Fracturing: A Multi-Scale Problem

DOE PAGES

Hyman, Jeffrey De'Haven; Gimenez Martinez, Joaquin; Viswanathan, Hari S.; ...

2016-09-05

Despite the impact that hydraulic fracturing has had on the energy sector, the physical mechanisms that control its efficiency and environmental impacts remain poorly understood in part because the length scales involved range from nano-meters to kilo-meters. We characterize flow and transport in shale formations across and between these scales using integrated computational, theoretical, and experimental efforts. At the field scale, we use discrete fracture network modeling to simulate production at a well site whose fracture network is based on a site characterization of a shale formation. At the core scale, we use triaxial fracture experiments and a finite-element discrete-elementmore » fracture propagation model with a coupled fluid solver to study dynamic crack propagation in low permeability shale. We use lattice Boltzmann pore-scale simulations and microfluidic experiments in both synthetic and real micromodels to study pore-scale flow phenomenon such as multiphase flow and mixing. A mechanistic description and integration of these multiple scales is required for accurate predictions of production and the eventual optimization of hydrocarbon extraction from unconventional reservoirs.« less

Fault reactivation and earthquakes with magnitudes of up to Mw4.7 induced by shale-gas hydraulic fracturing in Sichuan Basin, China.

PubMed

Lei, Xinglin; Huang, Dongjian; Su, Jinrong; Jiang, Guomao; Wang, Xiaolong; Wang, Hui; Guo, Xin; Fu, Hong

2017-08-11

This paper presents a timely and detailed study of significant injection-induced seismicity recently observed in the Sichuan Basin, China, where shale-gas hydraulic fracturing has been initiated and the aggressive production of shale gas is planned for the coming years. Multiple lines of evidence, including an epidemic-type aftershock sequence model, relocated hypocenters, the mechanisms of 13 large events (M W  > 3.5), and numerically calculated Coulomb failure stress results, convincingly suggest that a series of earthquakes with moment magnitudes up to M W 4.7 has been induced by "short-term" (several months at a single well pad) injections for hydraulic fracturing at depths of 2.3 to 3 km. This, in turn, supports the hypothesis that they represent examples of injection-induced fault reactivation. The geologic reasons why earthquake magnitudes associated with hydraulic fracturing operations are so high in this area are discussed. Because hydraulic fracturing operations are on the rise in the Sichuan Basin, it would be beneficial for the geoscience, gas operator, regulator, and academic communities to work collectively to elucidate the local factors governing the high level of injection-induced seismicity, with the ultimate goal of ensuring that shale gas fracking can be carried out effectively and safely.

Adequacy of Current State Setbacks for Directional High-Volume Hydraulic Fracturing in the Marcellus, Barnett, and Niobrara Shale Plays

PubMed Central

Haley, Marsha; McCawley, Michael; Epstein, Anne C.; Arrington, Bob; Bjerke, Elizabeth Ferrell

2016-01-01

Background: There is an increasing awareness of the multiple potential pathways leading to human health risks from hydraulic fracturing. Setback distances are a legislative method to mitigate potential risks. Objectives: We attempted to determine whether legal setback distances between well-pad sites and the public are adequate in three shale plays. Methods: We reviewed geography, current statutes and regulations, evacuations, thermal modeling, air pollution studies, and vapor cloud modeling within the Marcellus, Barnett, and Niobrara Shale Plays. Discussion: The evidence suggests that presently utilized setbacks may leave the public vulnerable to explosions, radiant heat, toxic gas clouds, and air pollution from hydraulic fracturing activities. Conclusions: Our results suggest that setbacks may not be sufficient to reduce potential threats to human health in areas where hydraulic fracturing occurs. It is more likely that a combination of reasonable setbacks with controls for other sources of pollution associated with the process will be required. Citation: Haley M, McCawley M, Epstein AC, Arrington B, Bjerke EF. 2016. Adequacy of current state setbacks for directional high-volume hydraulic fracturing in the Marcellus, Barnett, and Niobrara Shale Plays. Environ Health Perspect 124:1323–1333; http://dx.doi.org/10.1289/ehp.1510547 PMID:26895553

Fracking, fracture, and permeability

NASA Astrophysics Data System (ADS)

Turcotte, D. L.; Norris, J.; Rundle, J. B.

2013-12-01

Injections of large volumes of water into tight shale reservoirs allows the extraction of oil and gas not previously accessible. This large volume 'super' fracking induces damage that allows the oil and/or gas to flow to an extraction well. The purpose of this paper is to provide a model for understanding super fracking. We assume that water is injected from a small spherical cavity into a homogeneous elastic medium. The high pressure of the injected water generates hoop stresses that reactivate natural fractures in the tight shales. These fractures migrate outward as water is added creating a spherical shell of damaged rock. The porosity associated with these fractures is equal to the water volume injected. We obtain an analytic expression for this volume. We apply our model to a typical tight shale reservoir and show that the predicted water volumes are in good agreement with the volumes used in super fracking.

Assessment of Appalachian basin oil and gas resources:Devonian shale - Middle and Upper Paleozoic Total Petroleum System

USGS Publications Warehouse

Milici, Robert C.; Swezey, Christopher S.

2006-01-01

The U.S. Geological Survey (USGS) recently completed an assessment of the technically recoverable undiscovered hydrocarbon resources of the Appalachian Basin Province. The assessment province includes parts of New York, Pennsylvania, Ohio, Maryland, West Virginia, Virginia, Kentucky, Tennessee, Georgia and Alabama. The assessment was based on six major petroleum systems, which include strata that range in age from Cambrian to Pennsylvanian. The Devonian Shale-Middle and Upper Paleozoic Total Petroleum System (TPS) extends generally from New York to Tennessee. This petroleum system has produced a large proportion of the oil and natural gas that has been discovered in the Appalachian basin since the drilling of the Drake well in Pennsylvania in 1859. For assessment purposes, the TPS was divided into 10 assessment units (plays), 4 of which were classified as conventional and 6 as continuous. The results were reported as fully risked fractiles (F95, F50, F5 and the Mean), with the fractiles indicating the probability of recovery of the assessment amount. Products reported were oil (millions of barrels of oil, MMBO), gas (billions of cubic feet of gas, BCFG), and natural gas liquids (millions of barrels of natural gas liquids, MMBNGL). The mean estimates for technically recoverable undiscovered hydrocarbons in the TPS are: 7.53 MMBO, 31,418.88 BCFG (31.42 trillion cubic feet) of gas, and 562.07 MMBNGL.

Water sources and disposal related to hydraulic fracturing in the Barnett Shale: a historical perspective

NASA Astrophysics Data System (ADS)

Nicot, J.; Scanlon, B. R.

2013-12-01

During the past few years, hydraulic fracturing (HF) has become a hotly debated topic particularly related to volume of water used and potential for contamination of shallow aquifers. In this communication, we focused on water use in the oldest shale play in the world as an example for an analysis of historical patterns of water use, consumption, and disposal. The Barnett Shale play in Texas provides an ideal case to assess some of the issues related to shale gas production. It was the first shale play to submit to intense slick-water HF (first horizontal wells in 2003, ~15,000 horizontal wells completed to date). An estimated 200, 000 acre-feet (247 million m3) of water has been used so far in the play (included for vertical wells), mostly in the 4-5 counties making up the core area. More than 90% of the water used is consumed and relatively little recycling occurs in the play. Most of the flowback / produced water is disposed of through injection wells. The median Barnett horizontal well produces back ~100% of the amount of water injected for fracturing in the course of the few years following completion, an amount larger than other well-known shale gas plays. The communication will provide detailed material documenting these findings.

Practical measures for reducing the risk of environmental contamination in shale energy production.

PubMed

Ziemkiewicz, Paul; Quaranta, John D; McCawley, Michael

2014-07-01

Gas recovery from shale formations has been made possible by advances in horizontal drilling and hydraulic fracturing technology. Rapid adoption of these methods has created a surge in natural gas production in the United States and increased public concern about its environmental and human health effects. We surveyed the environmental literature relevant to shale gas development and studied over fifteen well sites and impoundments in West Virginia to evaluate pollution caused by air emissions, light and noise during drilling. Our study also characterized liquid and solid waste streams generated by drilling and hydraulic fracturing and evaluated the integrity of impoundments used to store fluids produced by hydraulic fracturing. While most shale gas wells are completed with little or no environmental contamination, we found that many of the problems associated with shale gas development resulted from inattention to accepted engineering practices such as impoundment construction, improper liner installation and a lack of institutional controls. Recommendations are provided based on the literature and our field studies. They will address not all but a great many of the deficiencies that result in environmental release of contaminants from shale gas development. We also identified areas where new technologies are needed to fully address contaminant releases to air and water.

Pyrolysis gas chromatography-mass spectrometry to characterize organic matter and its relationship to uranium content of Appalachian Devonian black shales

USGS Publications Warehouse

Leventhal, J.S.

1981-01-01

Gas Chromatographic analysis of volatile products formed by stepwise pyrolysis of black shales can be used to characterize the kerogen by relating it to separated, identified precursors such as land-derived vitrinite and marine-source Tasmanites. Analysis of a Tasmanites sample shows exclusively n-alkane and -alkene pyrolysis products, whereas a vitrinite sample shows a predominance of one- and two-ring substituted aromatics. For core samples from northern Tennessee and for a suite of outcrop samples from eastern Kentucky, the organic matter type and the U content (<10-120ppm) show variations that are related to precursor organic materials. The samples that show a high vitrinite component in their pyrolysis products are also those samples with high contents of U. ?? 1981.

Tectono-thermal Evolution of the Lower Paleozoic Petroleum Source Rocks in the Southern Lublin Trough: Implications for Shale Gas Exploration from Maturity Modelling

NASA Astrophysics Data System (ADS)

Botor, Dariusz

2018-03-01

The Lower Paleozoic basins of eastern Poland have recently been the focus of intensive exploration for shale gas. In the Lublin Basin potential unconventional play is related to Lower Silurian source rocks. In order to assess petroleum charge history of these shale gas reservoirs, 1-D maturity modeling has been performed. In the Łopiennik IG-1 well, which is the only well that penetrated Lower Paleozoic strata in the study area, the uniform vitrinite reflectance values within the Paleozoic section are interpreted as being mainly the result of higher heat flow in the Late Carboniferous to Early Permian times and 3500 m thick overburden eroded due to the Variscan inversion. Moreover, our model has been supported by zircon helium and apatite fission track dating. The Lower Paleozoic strata in the study area reached maximum temperature in the Late Carboniferous time. Accomplished tectono-thermal model allowed establishing that petroleum generation in the Lower Silurian source rocks developed mainly in the Devonian - Carboniferous period. Whereas, during Mesozoic burial, hydrocarbon generation processes did not develop again. This has negative influence on potential durability of shale gas reservoirs.

Lidar-based fracture characterization: An outcrop-scale study of the Woodford Shale, McAlister Shale Pit, Oklahoma

NASA Astrophysics Data System (ADS)

Hanzel, Jason

The use of lidar (light detection and ranging), a remote sensing tool based on principles of laser optometry, in mapping complex, multi-scale fracture networks had not been rigorously tested prior to this study despite its foreseeable utility in interpreting rock fabric with imprints of complex tectonic evolution. This thesis demonstrates lidar-based characterization of the Woodford Shale where intense fracturing could be due to both tectonism and mineralogy. The study area is the McAlister Shale Pit in south-central Oklahoma where both the upper and middle sections of the Woodford Shale are exposed and can be lidar-mapped. Lidar results are validated using hand-measured strike and dips of fracture planes, thin sections and mineral chemistry of selected samples using X-ray diffraction (XRD). Complexity of the fracture patterns as well as inaccessibility of multiple locations within the shale pit makes hand-measurement prone to errors and biases; lidar provides an opportunity for less biased and more efficient field mapping. Fracture mapping with lidar is a multi-step process. The lidar data are converted from point clouds into a mesh through triangulation. User-defined parameters such as size and orientation of the individual triangular elements are then used to group similar elements into surfaces. The strike and dip attribute of the simulated surfaces are visualized in an equal area lower hemisphere projection stereonet. Three fracture sets were identified in the upper and middle sections with common orientation but substantially different spatial density. Measured surface attributes and spatial density relations from lidar were validated using their hand-measured counterparts. Thin section analysis suggests that high fracture density in the upper Woodford measured by both the lidar and the hand-measured data could be due to high quartz. A significant finding of this study is the reciprocal relation between lidar intensity and gamma-ray (GR), which is generally used to infer outcrop mineralogy. XRD analysis of representative samples along the common profiles show that both GR and lidar intensity were influenced by the same minerals in essentially opposite ways. Results strongly suggest that the lidar cannot only remotely map the geomorphology, but also the relative mineralogical variations to the first order of approximation.

Insights into contaminant transport from unconventional oil and gas developments from analog system analysis of methane-bearing thermal springs in the northern Canadian Rocky Mountains

NASA Astrophysics Data System (ADS)

Ferguson, Grant; Grasby, Stephen E.

2018-03-01

Natural gas is currently being produced from shales of the Montney and Liard basins in western Canada. Production requires hydraulic fracturing due to the low permeability of the shales in the basins. Stratigraphically equivalent shales are present in the northern Canadian Rocky Mountains. Thermal springs with notable hydrocarbon concentrations occur where large-scale faults intersect the same shale units that are the focus of gas development, indicating that under certain circumstances, connection of deep fractured shales to the land surface is possible. To constrain these conditions, simulations were conducted for the spring with the highest hydrocarbon flux (Toad River Spring), results of which indicate that in order to supply sufficient water to a fault to support measurable advection, the effective permeability of the shales in these structurally deformed areas must be one to four orders of magnitude higher than in areas of active gas production to the east. The spatial scale of enhanced permeability is much greater than that which is achieved by hydraulic fracturing and the mechanism of maintaining high pressures at depth is more persistent in time. Examination of groundwater velocities suggests that upward migration of solutes from hydraulic fracturing may take decades to centuries. Results also indicate that any temperature anomaly will be associated with transport along a fault at such velocities. No such temperature anomaly has been documented in regions with unconventional oil and gas development to date. Such an anomaly would be diagnostic of a deep solute source.

Fluid inclusions in calcite filled opening fractures of the Serra Alta Formation reveal paleotemperatures and composition of diagenetic fluids percolating Permian shales of the Paraná Basin

NASA Astrophysics Data System (ADS)

Teixeira, C. A. S.; Sawakuchi, A. O.; Bello, R. M. S.; Nomura, S. F.; Bertassoli, D. J.; Chamani, M. A. C.

2018-07-01

The thermal and diagenetic evolution of shale units has received renewed focus because of their emergence as unconventional hydrocarbon reservoirs. The Serra Alta Formation (SAF) is a Permian shale unit of the Paraná Basin, which is the largest South American cratonic basin. The SAF stands out as a pathway for aqueous fluids and hydrocarbon migration from the Irati organic-rich shales to the Pirambóia fluvial-eolian sandstone reservoirs. Vertical NNW and NNE opening fractures would be the main pathways for the migration of buried pore waters and aqueous fluids, besides the input of meteoric water. These fractures would be associated to the reactivation of basement discontinuities such as the Jacutinga (NE) and Guapiara (NW) faults. Thus, vertical NNE and NNW associated fractures would represent the main pathways for fluid migration in the studied area. The vertical calcite filled opening fractures from SAF record moderately low salinity (0-4.5 wt % of NaCl eq.) aqueous fluids, suggesting the input of meteoric water in the buried fracture system. Eutectic melting temperatures at -52±5 °C indicate an H2O + NaCl + CaCl2 system with CaCl2 or MgCl2 in solution. Homogenization temperatures recorded in fluid inclusion assemblages (FIAs) of calcite filled opening fractures indicate that the SAF in the studied area reached temperatures above 200 °C, suitable for generation of gaseous hydrocarbons. The recorded paleotemperatures point to a thermal peak associated with Serra Geral volcanic event during the Early Cretaceous, with the thermal effect of volcanic rock cap possibly overcoming the effect of intrusive igneous bodies. The detection of methane in SAF shale pores indicates conditions for hydrocarbon generation. However, additionally studies are necessary to confirm the thermogenic and/or biogenic origin of the methane within the SAF.

Attenuation of Chemical Reactivity of Shale Matrixes following Scale Precipitation

NASA Astrophysics Data System (ADS)

Li, Q.; Jew, A. D.; Kohli, A. H.; Alalli, G.; Kiss, A. M.; Kovscek, A. R.; Zoback, M. D.; Brown, G. E.; Maher, K.; Bargar, J.

2017-12-01

Introduction of fracture fluids into shales initiates a myriad of fluid-rock reactions that can strongly influence migration of fluid and hydrocarbon through shale/fracture interfaces. Due to the extremely low permeability of shale matrixes, studies on chemical reactivity of shales have mostly focused on shale surfaces. Shale-fluid interactions inside within shale matrixes have not been examined, yet the matrix is the primary conduit through which hydrocarbons and potential contaminants are transmitted. To characterize changes in matrix mineralogy, porosity, diffusivity, and permeability during hydraulic stimulation, we reacted Marcellus (high clay and low carbonate) and Eagle Ford (low clay and high carbonate) shale cores with fracture fluids for 3 weeks at elevated pressure and temperature (80 oC, and 77 bars). In the carbonate-poor Marcellus system, fluid pH increased from 2 to 4, and secondary Fe(OH)3 precipitates were observed in the fluid. Sulfur X-ray fluorescence maps show that fluids had saturated and reacted with the entire 1-cm-diameter core. In the carbonate-rich Eagle Ford system, pH increased from 2 to 6 due to calcite dissolution. When additional Ba2+ and SO42- were present (log10(Q/K)=1.3), extensive barite precipitation was observed in the matrix of the Eagle Ford core (and on the surface). Barite precipitation was also observed on the surface of the Marcellus core, although to a lesser extent. In the Marcellus system, the presence of barite scale attenuated diffusivity in the matrix, as demonstrated by sharply reduced Fe leaching and much less sulfide oxidation. Systematic studies in homogeneous solution show that barite scale precipitation rates are highly sensitive to pH, salinity, and the presence of organic compounds. These findings imply that chemical reactions are not confined to shale/fluid interfaces but can penetrate into shale matrices, and that barite scale formation can clog diffusion pathways for both fluid and hydrocarbon.

Creep of Posidonia and Bowland shale at elevated pressures and temperatures

NASA Astrophysics Data System (ADS)

Herrmann, Johannes; Rybacki, Erik; Sone, Hiroki; Dresen, Georg

2017-04-01

The fracture-healing rate of artificial cracks generated by hydraulic fracturing is of major interest in the E&P industry since it is important for the long-time productivity of a well. To estimate the stress-induced healing rate of unconventional reservoir rocks, we performed deformation tests on Bowland shale rocks (UK) and on Posidonia shales (Germany). Samples of 1cm diameter and 2cm length were drilled perpendicular to the bedding and deformed in a high pressure, high temperature deformation apparatus. Constant strain rate tests at 5*10-4*s-1, 50 MPa confining pressure and 100˚ C temperature reveal a mainly brittle behaviour with predominantly elastic deformation before failure and high strength of low porosity (˜2%), quartz-rich (˜42 vol%) Bowland shale. In contrast, the low porosity (˜3%), carbonate- (˜43 vol%) and clay-rich (˜33 vol%) Posidonia shale deforms semi-brittle with pronounced inelastic deformation and low peak strength. These results suggest a good fracability of the Bowland formation compared to the Posidonia shale. Constant load (creep) experiments performed on Bowland shale at 100˚ C temperature and 75 MPa pressure show mainly transient (primary) deformation with increasing strain rate at increasing axial stress. The strain rate increases also with increasing temperature, measured in the range of 75 - 150˚ C at fixed stress and confinement. In contrast, increasing confining pressure (from 30 to 115 MPa) at given temperature and stress results in decreasing strain rate. In contrast, Posidonia shale rocks are much more sensitive to changes in stress, temperature and pressure than Bowland shale. Empirical relations between strain and stress that account for the influence of pressure and temperature on creep properties of Posidonia and Bowland shale rocks can be used to estimate the fracture healing rate of these shales under reservoir conditions.

Water Saturation Relations and Their Diffusion-Limited Equilibration in Gas Shale: Implications for Gas Flow in Unconventional Reservoirs

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

Tokunaga, Tetsu K.; Shen, Weijun; Wan, Jiamin

Large volumes of water are used for hydraulic fracturing of low permeability shale reservoirs to stimulate gas production, with most of the water remaining unrecovered and distributed in a poorly understood manner within stimulated regions. Because water partitioning into shale pores controls gas release, we measured the water saturation dependence on relative humidity (rh) and capillary pressure (P c) for imbibition (adsorption) as well as drainage (desorption) on samples of Woodford Shale. Experiments and modeling of water vapor adsorption into shale laminae at rh = 0.31 demonstrated that long times are needed to characterize equilibrium in larger (5 mm thick)more » pieces of shales, and yielded effective diffusion coefficients from 9 × 10 -9 to 3 × 10 -8 m 2 s -1, similar in magnitude to the literature values for typical low porosity and low permeability rocks. Most of the experiments, conducted at 50°C on crushed shale grains in order to facilitate rapid equilibration, showed significant saturation hysteresis, and that very large P c (~1 MPa) are required to drain the shales. These results quantify the severity of the water blocking problem, and suggest that gas production from unconventional reservoirs is largely associated with stimulated regions that have had little or no exposure to injected water. Finally, gravity drainage of water from fractures residing above horizontal wells reconciles gas production in the presence of largely unrecovered injected water, and is discussed in the broader context of unsaturated flow in fractures.« less

Water Saturation Relations and Their Diffusion-Limited Equilibration in Gas Shale: Implications for Gas Flow in Unconventional Reservoirs

DOE PAGES

Tokunaga, Tetsu K.; Shen, Weijun; Wan, Jiamin; ...

2017-11-15

Large volumes of water are used for hydraulic fracturing of low permeability shale reservoirs to stimulate gas production, with most of the water remaining unrecovered and distributed in a poorly understood manner within stimulated regions. Because water partitioning into shale pores controls gas release, we measured the water saturation dependence on relative humidity (rh) and capillary pressure (P c) for imbibition (adsorption) as well as drainage (desorption) on samples of Woodford Shale. Experiments and modeling of water vapor adsorption into shale laminae at rh = 0.31 demonstrated that long times are needed to characterize equilibrium in larger (5 mm thick)more » pieces of shales, and yielded effective diffusion coefficients from 9 × 10 -9 to 3 × 10 -8 m 2 s -1, similar in magnitude to the literature values for typical low porosity and low permeability rocks. Most of the experiments, conducted at 50°C on crushed shale grains in order to facilitate rapid equilibration, showed significant saturation hysteresis, and that very large P c (~1 MPa) are required to drain the shales. These results quantify the severity of the water blocking problem, and suggest that gas production from unconventional reservoirs is largely associated with stimulated regions that have had little or no exposure to injected water. Finally, gravity drainage of water from fractures residing above horizontal wells reconciles gas production in the presence of largely unrecovered injected water, and is discussed in the broader context of unsaturated flow in fractures.« 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

Tectonic context of the penetrative fracture system origin in the Early Paleozoic shale complex (Baltic Basin, Poland/Sweden).

NASA Astrophysics Data System (ADS)

Jarosiński, Marek; Gluszynski, Andrzej; Bobek, Kinga; Dyrka, Ireneusz

2017-04-01

Characterization of natural fracture and fault pattern play significant role for reservoir stimulation design and evaluation of its results. Having structural observations limited to immediate borehole surrounding it is a common need to build up a fracture model of reservoir in a range of stimulation reservoir volume or even beyond. To do this we need both a 3D seismic model and a consistent concept of the regional tectonic evolution. We present the result of integrated tectonic study in several deep boreholes target the Lower Paleozoic shale complex of Baltic Basin (BB), combined with analysis of 3D seismic survey and outcrop screening in Scania (Swedish part of the BB). During deposition of shale complex in the Ordovician and Silurian the research area was located 200-300 km away from the continental margin of Baltica involved in the Caledonian collision with the Eastern Avalonia. This distance allowed the shale complex to avoid significant tectonic deformation. Regional seismic cross section reveals the general pattern of the BB infill characteristic for the foreland basin underwent post-collisional isostatic rebound. Due to stress changes in collisional context the shale complex was cross-cut by steep, mostly inverse faults trending NW-SE and NE-SW. The fault zones oriented NW-SE are associated with an array of en echelon faults characteristic for strike-slip displacement. In our interpretation, these faults of Silurian (Wenlock) age create pattern of the regional pop-up structure, which is simultaneously involved in the plate flexure extension. Seismic attributes (e.g. curvature or ant tracking) highlight lineaments which mostly mimic the faults orientation. However, attributes show also some artefacts that come from regular array of seismic sources and receivers, which mimic the orthogonal joint system. Structural observations on borehole core lead us to conclusion that regular, orthogonal fracture system developed after maximum burial of the complex, triggered by mechanism of natural hydraulic fracturing due to hydrocarbon generation. These fractures create veins filled with calcite that growth was controlled by mechanical layering and the TOC content of the shale complex. The main joint fracture pattern is stable across at least 300 hundred kilometers, from the Polish to Swedish portion of Baltic Basin. Therefore a major tectonic event is expected to govern its origin. The Late Carboniferous thin-skinned compression exerted at the edge of the East European Craton, is preferred tectonic fracture triggering factor. This age of jointing is confirmed by the strike of principal joint set characteristic for Variscan compression. In addition, principal joint system is sensitive (=younger) to a presence of the Caledonian-age faults in Pomerania but insensitive (=older) to the Mesozoic faults in Scania. Above genetic considerations should be taken into account while building the self-consistent discrete fracture network of faults and fractures for the purpose of shale reservoir stimulation.

Consistent lithological units and its influence on geomechanical stratification in shale reservoir: case study from Baltic Basin, Poland.

NASA Astrophysics Data System (ADS)

Pachytel, Radomir; Jarosiński, Marek; Bobek, Kinga

2017-04-01

Geomechanical investigations in shale reservoir are crucial to understand rock behavior during hydraulic fracturing treatment and to solve borehole wall stability problem. Anisotropy should be considered as key mechanical parameter while trying to characterize shale properties in variety of scales. We are developing a concept of step-by-step approach to characterize and upscale the Consistent Lithological Units (CLU) at several scales of analysis. We decided that the most regional scale model, comparable to lithostratigraphic formations, is too general for hydraulic fracture propagation study thus a more detailed description is needed. The CLU's hierarchic model aims in upscale elastic properties with their anisotropy based on available data from vertical borehole. For the purpose of our study we have an access to continuous borehole core profile and full set of geophysical logging from several wells in the Pomeranian part of the Ordovician and Silurian shale complex belongs to the Baltic Basin. We are focused on shale properties that might be crucial for mechanical response to hydraulic fracturing: mineral components, porosity, density, elastic parameters and natural fracture pattern. To prepare the precise CLU model we compare several methods of determination and upscaling every single parameter used for consistent units secretion. Mineralogical data taken from ULTRA log, GEM log, X-ray diffraction and X-ray fluorescence were compared with Young modulus from sonic logs and Triaxial Compressive Strength Tests. The results showed the impact of clay content and porosity increase on Young's modulus reduction while carbonates (both calcite and dolomite) have stronger impact on elastic modulus growth, more than quartz, represented here mostly by detrital particles. Comparing the shales of similar composition in a few wells of different depths we concluded that differences in diagenesis and compaction due to variation in formation depth in a range of 1 km has negligible influence on the values of Young modulus. Both mineralogical and mechanical brittleness display differences not only between lithostratigraphic formations, but also for the lower-order CLUs which may influence development of tectonic and technological fractures. Using this approach, we can predict the areas that may be more prone to fracture propagation and branching during hydraulic fracturing treatment and also places that can create barriers to their development. Furthermore, we demonstrate relationship between CLU's mechanical properties and the density of natural fractures determined from core and Electric-Resistivity Borehole Imager analysis. As fracture friction may rule reservoir response to technological loads induced while drilling and fracking we also applied a method of massive determination of static friction coefficient on borehole core. Tuffite beds or other weak intercalations were included in the CLU's model as possible structural barriers for hydraulic fracture propagation. Distinguished set of CLUs is possible to be traced from well to well across tens of kilometers of the Baltic Basin. Our study in the frame of ShaleMech Project funded by Polish Committee for Scientific Research is in progress and the results are preliminary.

Direct evidence for organic carbon preservation as clay-organic nanocomposites in a Devonian black shale; from deposition to diagenesis

NASA Astrophysics Data System (ADS)

Kennedy, Martin John; Löhr, Stefan Carlos; Fraser, Samuel Alex; Baruch, Elizabeth Teresa

2014-02-01

The burial of marine sourced organic carbon (OC) in continental margin sediments is most commonly linked to oceanographic regulation of bottom-water oxygenation (anoxia) and/or biological productivity. Here we show an additional influence in the Devonian Woodford Shale, in which OC occurs as nanometer intercalations with specific phyllosilicate minerals (mixed-layer illite/smectite) that we term organo-mineral nanocomposites. High resolution transmission electron microscopic (HRTEM) images provide direct evidence of this nano-scale relationship. While discrete micron-scale organic particles, such as Tasmanites algal cysts, are present in some lamina, a strong relation between total organic carbon (TOC) and mineral surface area (MSA) over a range of 15% TOC indicate that the dominant association of organic carbon is with mineral surfaces and not as discrete pelagic grains, consistent with HRTEM images of nanocomposites. Where periods of oxygenation are indicated by bioturbation, this relationship is modified by a shift to lower OC loading on mineral surfaces and reduced MSA variability likely resulting from biological mixing and homogenization of the sediment, oxidative burn down of OC and/or stripping of OC from minerals in animal guts. The TOC-MSA relationship extends across a range of burial depths and thermal maturities into the oil window and persists through partial illitization. Where illitization occurs, the loss of mineral surface area associated with the collapse of smectite interlayer space results in a systematic increase in TOC:MSA and reorganization of organic carbon and clays into nano-scale aggregates. While the Woodford Shale is representative of black shale deposits commonly thought to record heightened marine productivity and/or anoxia, our results point to the importance of high surface area clay minerals for OC enrichment. Given that the vast majority of these clay minerals are formed in soils before being transported to continental margin settings, their mineralogy and attendant preservative potential is primarily a function of continental climate and provenance making these deposits a sensitive recorder of land as well as oceanographic change.

Experimental and numerical study of hydraulic fracture geometry in shale formations with complex geologic conditions

NASA Astrophysics Data System (ADS)

Ma, Xinfang; Zhou, Tong; Zou, Yushi

2017-05-01

Strike-slip fault geostress and dipping laminated structures in Lujiaping shale formation typically result in difficultly predicting hydraulic fracture (HF) geometries. In this study, a novel 3D fracture propagation model based on discrete element method (DEM) is established. A series of simulations is performed to illustrate the influence of vertical stress difference (△σv = σv-σh), fluid viscosity, and injection rate, on HF growth geometry in the dipping layered formation. Results reveal that the fracturing fluid can easily infiltrate the dipping bedding plane (BP) interfaces with low net pressure for △σv = 1 MPa. HF height growth is also restricted. With increased △σv, fracture propagation in the vertical direction is enhanced, and a fracture network is formed by VF and partially opened dipping BPs. However, it is likely to create simple VF for △σv = 20 MPa. Appropriately increasing fracturing fluid viscosity and injection rate is conductive to weakening the containment effect of BPs on HF growth by increasing the fluid net pressure. However, no indication is found on whether a higher fracturing fluid viscosity is better. Higher viscosity can reduce the activation of BPs, so a stimulated reservoir volume is not necessarily increased. All these results can serve as theoretical guidance for the optimization of fracturing treatments in Lujiaping shale formation.

Integrated analysis and interpretation of microseismic monitoring of hydraulic fracturing in the Marcellus Shale

NASA Astrophysics Data System (ADS)

Zorn, Erich Victor

In 2012 and 2013, hydraulic fracturing was performed at two Marcellus Shale well pads, under the supervision of the Energy Corporation of America. Six lateral wells were hydraulically fractured in Greene County in southwestern Pennsylvania and one lateral well was fractured in Clearfield County in north-central Pennsylvania. During hydraulic fracturing operations, microseismic monitoring by strings of downhole geophones detected a combination of >16,000 microseismic events at the two sites. High quality traditional and geomechanical well logs were acquired at Clearfield County, as well as tomographic velocity profiles before and after stimulation. In partnership with the US Department of Energy's National Energy Technology Laboratory, I completed detailed analysis of these geophysical datasets to maximize the understanding of the engineering and geological conditions in the reservoir, the connection between hydraulic input and microseismic expression, and the geomechanical factors that control microseismic properties. Additionally, one broad-band surface seismometer was deployed at Greene County and left to passively monitor site acoustics for the duration of hydraulic fracturing. Data from this instrument shows the presence of slow-slip or long period/long duration (LPLD) seismicity. In years prior to our investigation, lab-scale fracturing studies and broadband seismic monitoring of hydraulic fracturing had been completed by other researchers in unconventional shale and tight sand in Texas and Canada. This is the first study of LPLD seismicity in the Marcellus Shale and reveals aseismic deformation during hydraulic fracturing that could account for a large portion of "lost" hydraulic energy input. Key accomplishments of the studies contained in this dissertation include interpreting microseismic data in terms of hydraulic pumping data and vice versa, verifying the presence of LPLD seismicity during fracturing, establishing important geomechanical controls on the character of induced microseismicity, and extensive data integration toward locating a previously unmapped fault that appears to have exhibited significant control over well stimulation efforts at Clearfield.

Geological and petrological considerations relevant to the disposal of radioactive wastes by hydraulic fracturing: an example at the US Department of Energy's Oak Ridge National Laboratory

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

Haase, C.S.

1983-01-01

At Oak Ridge National Laboratory the Pumpkin Valley Shale is used as a host formation for hydraulic fracturing waste disposal. Determination of the relationships between the distribution of different lithologies and porosity-permeability trends within this host formation allows these properties, important to hydraulic fracturing operations, to be related to measurable and mappable geological and petrological parameters. It also permits extrapolation of such patterns to little-studied portions of the Pumpkin Valley Shale. Such knowledge better allows for the satisfactory operation and assessment of the hydraulic fracturing at Oak Ridge National Laboratory.

Fracture propagation through a layered shale and limestone sequence at Nash Point, South Wales: Implications on the development of fracture networks in layered sequences

NASA Astrophysics Data System (ADS)

Forbes Inskip, N.; Meredith, P. G.; Gudmundsson, A.

2017-12-01

While considerable effort has been expended on the study of fracture propagation in rocks in recent years, our understanding of how fractures propagate through sedimentary rocks composed of layers with different mechanical and elastic properties remains poor. Yet the mechanical layering is a key parameter controlling the propagation of fractures in sedimentary sequences. Here we report measurements of the contrasting properties of the Lower Lias at Nash Point, South Wales, which comprises a sequence of interbedded shale and limestone layers, and how those properties influence fracture propagation. The static Young's modulus (Estat) of both rock types has been measured parallel and normal to bedding. The shale is highly anisotropic, with Estat varying from 2.4 GPa, in the bedding-normal orientation, to 7.9 GPa, in the bedding-parallel orientation, yielding an anisotropy of 107%. By contrast the limestone has a very low anisotropy of 8%, with Estat values varying from 28.5 GPa, in the bedding-normal orientation, to 26.3 GPa in the bedding-parallel orientation. It follows that for a vertical fracture propagating in this sequence the modulus contrast is by a factor of about 12. This is important because the contrast in elastic properties is a key factor in controlling whether fractures arrest, deflect, or propagate across interfaces between layers in a sequence. Preliminary numerical modelling results (using a finite element modelling software) of induced fractures at Nash Point demonstrate a rotation of the maximum principal compressive stress across interfaces but also the concentration of tensile stress within the more competent (high Estat) limestone layers. The tensile strength (σT), using the Brazil-disk technique, and fracture toughness (KIc), using the semi-circular bend methodology, of both rock types have been measured. Measurements were made in the three principal orientations relative to bedding, Arrester, Divider, and Short-Transverse, and also at 15° intervals between these planes. Again, values for the shale show a high degree of anisotropy; with similar values in the Arrester and Divider orientations, but much lower values in the Short-Transverse orientation. σT and KIc values for the limestone are considerably higher than those for the shale and exhibit no significant anisotropy.

Evaluating the Influence of Chemical Reactions on Wellbore Cement Integrity and Geochemical Tracer Behavior in Hydraulically-Fractured Shale Formations

NASA Astrophysics Data System (ADS)

Verba, C.; Lieuallen, A.; Yang, J.; Torres, M. E.; Hakala, A.

2014-12-01

Ensuring wellbore integrity for hydraulically-fractured shale reservoirs is important for maintaining zonal isolation of gases and fluids within the reservoir. Chemical reactions between wellbore cements, the shale formation, formation fluids, and fracturing fluids could affect the ability for cement to form an adequate seal. This study focuses on experimental investigations to evaluate how cement, rock, brines, and fracturing fluids react under conditions similar to the perforated zone associated with the Marcellus shale (Greene County, Pennsylvania). Two pressure/temperature regimes were investigated- moderate (25 MPa, 50oC) and high (27.5 MPa, 90oC). Shale collected from the Lower Marcellus section was encased in Class A cement, cured for 24 hours, and then exposed to simulated conditions in experimental autoclave reactors. The simulated formation fluid was a synthetic brine, modeled after a flowback fluid contained 187,000 mg/l total dissolved solids and had a pH of 7.6. The effect of pH was probed to evaluate the potential for cement reactivity under different pH conditions, and the potential for contaminant or geochemical tracer release from the shale (e.g. arsenic and rare earth elements). In addition to dissolution reactions, sorption and precipitation reactions between solutes and the cement are being evaluated, as the cement could bond with solute-phase species during continued hydration. The cements are expected to show different reactivity under the two temperature conditions because the primary cement hydration product, calcium silicate hydrate (C-S-H) is heavily influenced by temperature. Results from these experimental studies will be used both to inform the potential changes in cement chemistry that may occur along a wellbore in the hydraulically-fractured portion of a reservoir, and the types of geochemical tracers that may be useful in tracking these reactions.

The Importance of pH, Oxygen, and Bitumen on the Oxidation and Precipitation of Fe(III)-(oxy)hydroxides during Hydraulic Fracturing of Oil/Gas Shales

NASA Astrophysics Data System (ADS)

Jew, A. D.; Dustin, M. K.; Harrison, A. L.; Joe-Wong, C. M.; Thomas, D.; Maher, K.; Brown, G. E.; Bargar, J.

2016-12-01

Due to the rapid growth of hydraulic fracturing in the United States, understanding the cause for the rapid production drop off of new wells over the initial months of production is paramount. One possibility for the production decrease is pore occlusion caused by the oxidation of Fe(II)-bearing phases resulting in Fe(III) precipitates. To understand the release and fate of Fe in the shale systems, we reacted synthesized fracture fluid at 80oC with shale from four different geological localities (Marcellus Fm., Barnett Fm., Eagle Ford Fm., and Green River Fm.). A variety of wet chemical and synchrotron-based techniques (XRF mapping and x-ray absorption spectroscopy) were used to understand Fe release and solid phase Fe speciation. Solution pH was found to be the greatest factor for Fe release. Carbonate-poor Barnett and Marcellus shale showed rapid Fe release into solution followed by a plateau or significant drop in Fe concentrations indicating mineral precipitation. Conversely, in high carbonate shales, Eagle Ford and Green River, no Fe was detected in solution indicating fast Fe oxidation and precipitation. For all shale samples, bulk Fe EXAFS data show that a significant amount of Fe in the shales is bound directly to organic carbon. Throughout the course of the experiments inorganic Fe(II) phases (primarily pyrite) reacted while Fe(II) bound to C showed no indication of reaction. On the micron scale, XRF mapping coupled with μ-XANES spectroscopy showed that at pH < 4.0, Fe(III) bearing phases precipitated as diffuse surface precipitates of ferrihydrite, goethite, and magnetite away from Fe(II) point sources. In near circum-neutral pH systems, Fe(III)-bearing phases (goethite and hematite) form large particles 10's of μm's in diameter near Fe(II) point sources. Idealized systems containing synthesized fracturing fluid, dissolved ferrous chloride, and bitumen showed that bitumen released during reaction with fracturing fluids is capable of oxidizing Fe(II) to Fe(III) at pH's 2.0 and 7.0. This indicates that bitumen can play a large role in Fe oxidation and speciation in the subsurface. This work shows that shale mineralogy has a significant impact on the morphology and phases of Fe(III) precipitates in the subsurface which in turn can significantly impact subsurface solution flow.

Current perspectives on unconventional shale gas extraction in the Appalachian Basin.

PubMed

Lampe, David J; Stolz, John F

2015-01-01

The Appalachian Basin is home to three major shales, the Upper Devonian, Marcellus, and Utica. Together, they contain significant quantities of tight oil, gas, and mixed hydrocarbons. The Marcellus alone is estimated to contain upwards of 500 trillion cubic feet of natural gas. The extraction of these deposits is facilitated by a combination of horizontal drilling and slick water stimulation (e.g., hydraulic fracturing) or "fracking." The process of fracking requires large volumes of water, proppant, and chemicals as well as a large well pad (3-7 acres) and an extensive network of gathering and transmission pipelines. Drilling can generate about 1,000 tons of drill cuttings depending on the depth of the formation and the length of the horizontal bore. The flowback and produced waters that return to the surface during production are high in total dissolved solids (TDS, 60,000-350,000 mg L(-1)) and contain halides (e.g., chloride, bromide, fluoride), strontium, barium, and often naturally occurring radioactive materials (NORMs) as well as organics. The condensate tanks used to store these fluids can off gas a plethora of volatile organic compounds. The waste water, with its high TDS may be recycled, treated, or disposed of through deep well injection. Where allowed, open impoundments used for recycling are a source of air borne contamination as they are often aerated. The gas may be "dry" (mostly methane) or "wet," the latter containing a mixture of light hydrocarbons and liquids that need to be separated from the methane. Although the wells can produce significant quantities of natural gas, from 2-7 bcf, their initial decline rates are significant (50-75%) and may cease to be economic within a few years. This review presents an overview of unconventional gas extraction highlighting the environmental impacts and challenges.

Numerical analysis of fracture propagation during hydraulic fracturing operations in shale gas systems

EPA Pesticide Factsheets

Researchers used the TOUGH+ geomechanics computational software and simulation system to examine the likelihood of hydraulic fracture propagation (the spread of fractures) traveling long distances to connect with drinking water aquifers.

Investigation of Controlling Factors Impacting Water Quality in Shale Gas Produced Brine

NASA Astrophysics Data System (ADS)

Fan, W.; Hayes, K. F.; Ellis, B. R.

2014-12-01

The recent boom in production of natural gas from unconventional reservoirs has generated a substantial increase in the volume of produced brine that must be properly managed to prevent contamination of fresh water resources. Produced brine, which includes both flowback and formation water, is often highly saline and may contain elevated concentrations of naturally occurring radioactive material and other toxic elements. These characteristics present many challenges with regard to designing effective treatment and disposal strategies for shale gas produced brine. We will present results from a series of batch experiments where crushed samples from two shale formations in the Michigan Basin, the Antrim and Utica-Collingwood shales, were brought into contact with synthetic hydraulic fracturing fluids under in situ temperature and pressure conditions. The Antrim has been an active shale gas play for over three decades, while the Utica-Collingwood formation (a grouped reservoir consisting of the Utica shale and Collingwood limestone) is an emerging shale gas play. The goal of this study is to investigate the influence of water-rock interactions in controlling produced water quality. We evaluate toxic element leaching from shale samples in contact with model hydraulic fracturing fluids under system conditions corresponding to reservoir depths up to 1.5 km. Experimental results have begun to elucidate the relative importance of shale mineralogy, system conditions, and chemical additives in driving changes in produced water quality. Initial results indicate that hydraulic fracturing chemical additives have a strong influence on the extent of leaching of toxic elements from the shale. In particular, pH was a key factor in the release of uranium (U) and divalent metals, highlighting the importance of the mineral buffering capacity of the shale. Low pH values persisted in the Antrim and Utica shale experiments and resulted in higher U extraction efficiencies than that observed in the presence of the carbonate-rich Collingwood limestone. In addition to assessing U leaching, we also measured the activity of 226Ra and 228Ra via high-resolution gamma ray spectroscopy. Laboratory results will be compared to observations from a complimentary field sampling campaign of Antrim produced brine.

Creep of Posidonia Shale at Elevated Pressure and Temperature

NASA Astrophysics Data System (ADS)

Rybacki, E.; Herrmann, J.; Wirth, R.; Dresen, G.

2017-12-01

The economic production of gas and oil from shales requires repeated hydraulic fracturing operations to stimulate these tight reservoir rocks. Besides simple depletion, the often observed decay of production rate with time may arise from creep-induced fracture closure. We examined experimentally the creep behavior of an immature carbonate-rich Posidonia shale, subjected to constant stress conditions at temperatures between 50 and 200 °C and confining pressures of 50-200 MPa, simulating elevated in situ depth conditions. Samples showed transient creep in the semibrittle regime with high deformation rates at high differential stress, high temperature and low confinement. Strain was mainly accommodated by deformation of the weak organic matter and phyllosilicates and by pore space reduction. The primary decelerating creep phase observed at relatively low stress can be described by an empirical power law relation between strain and time, where the fitted parameters vary with temperature, pressure and stress. Our results suggest that healing of hydraulic fractures at low stresses by creep-induced proppant embedment is unlikely within a creep period of several years. At higher differential stress, as may be expected in situ at contact areas due to stress concentrations, the shale showed secondary creep, followed by tertiary creep until failure. In this regime, microcrack propagation and coalescence may be assisted by stress corrosion. Secondary creep rates were also described by a power law, predicting faster fracture closure rates than for primary creep, likely contributing to production rate decline. Comparison of our data with published primary creep data on other shales suggests that the long-term creep behavior of shales can be correlated with their brittleness estimated from composition. Low creep strain is supported by a high fraction of strong minerals that can build up a load-bearing framework.

Overview of DOE Oil and Gas Field Laboratory Projects

NASA Astrophysics Data System (ADS)

Bromhal, G.; Ciferno, J.; Covatch, G.; Folio, E.; Melchert, E.; Ogunsola, O.; Renk, J., III; Vagnetti, R.

2017-12-01

America's abundant unconventional oil and natural gas (UOG) resources are critical components of our nation's energy portfolio. These resources need to be prudently developed to derive maximum benefits. In spite of the long history of hydraulic fracturing, the optimal number of fracturing stages during multi-stage fracture stimulation in horizontal wells is not known. In addition, there is the dire need of a comprehensive understanding of ways to improve the recovery of shale gas with little or no impacts on the environment. Research that seeks to expand our view of effective and environmentally sustainable ways to develop our nation's oil and natural gas resources can be done in the laboratory or at a computer; but, some experiments must be performed in a field setting. The Department of Energy (DOE) Field Lab Observatory projects are designed to address those research questions that must be studied in the field. The Department of Energy (DOE) is developing a suite of "field laboratory" test sites to carry out collaborative research that will help find ways of improving the recovery of energy resources as much as possible, with as little environmental impact as possible, from "unconventional" formations, such as shale and other low permeability rock formations. Currently there are three field laboratories in various stages of development and operation. Work is on-going at two of the sites: The Hydraulic Fracturing Test Site (HFTS) in the Permian Basin and the Marcellus Shale Energy and Environmental Lab (MSEEL) project in the Marcellus Shale Play. Agreement on the third site, the Utica Shale Energy and Environmental Lab (USEEL) project in the Utica Shale Play, was just recently finalized. Other field site opportunities may be forthcoming. This presentation will give an overview of the three field laboratory projects.

Creep Behavior of Posidonia Shale at Elevated Pressure and Temperature

NASA Astrophysics Data System (ADS)

Rybacki, E.; Herrmann, J.; Wirth, R.; Dresen, G.

2017-12-01

Unconventional reservoir rocks are usually stimulated by repeated hydraulic fracturing operations. However, the production rate often decays with time that may arise from creep-induced fracture closure by proppant embedment. To examine experimentally the creep behavior of shales, we deformed immature carbonate-rich Posidonia shale at constant stress conditions and elevated temperatures between 50° and 200°C and confining pressures of 50 to 200 MPa. Samples showed transient creep in the semibrittle regime with high deformation rates at high differential stress, high temperature, and low confinement. Strain was mainly accommodated by deformation of the weak organic matter and phyllosilicates and by pore space reduction. At relatively low stress the samples deformed in the primary creep regime with continuously decelerating strain rate. The relation between strain and time can be described by an empirical power law equation, where the fitted parameters vary with temperature, pressure and stress. Our results suggest that healing of hydraulic fractures at low stresses by creep-induced proppant embedment is unlikely within a creep period of several years. At high differential stress (85-90% of the triaxial strength), as may be expected in situ at contact areas due to stress concentrations, the shale showed secondary creep, followed by tertiary creep until failure. In this regime, stress corrosion may induce microcrack propagation and coalescence. Secondary creep rates were also described by a power law that predicts faster fracture closure rates than for primary creep and likely contributes to production rate decline. Comparison of our data with published primary creep data on other shales suggest that the long-term creep behavior of shales can be correlated to their brittleness estimated from composition. Low creep strain is supported by a high fraction of strong minerals that can build up a load-bearing framework.

Breakdown pressures and characteristic flaw sizes during fluid injection experiments in shale at elevated confining pressures.

NASA Astrophysics Data System (ADS)

Chandler, M.; Mecklenburgh, J.; Rutter, E. H.; Taylor, R.; Fauchille, A. L.; Ma, L.; Lee, P. D.

2017-12-01

Fracture propagation trajectories in gas-bearing shales depend on the interaction between the anisotropic mechanical properties of the shale and the anisotropic in-situ stress field. However, there is a general paucity of available experimental data on their anisotropic mechanical, physical and fluid-flow properties, especially at elevated confining pressures. A suite of mechanical, flow and elastic measurements have been made on two shale materials, the Whitby mudrock and the Mancos shale (an interbedded silt and mudstone), as well as Pennant sandstone, an isotropic baseline and tight-gas sandstone analogue. Mechanical characterization includes standard triaxial experiments, pressure-dependent permeability, brazilian disk tensile strength, and fracture toughness determined using double-torsion experiments. Elastic characterisation was performed through ultrasonic velocities determined using a cross-correlation method. Additionally, we report the results of laboratory-scale fluid injection experiments for the same materials. Injection experiments involved the pressurisation of a blind-ending central hole in a dry cylindrical sample. Pressurisation is conducted under constant volume-rate control, using silicon oils of varying viscosities. Breakdown pressure is not seen to exhibit a strong dependence on rock type or orientation, and increases linearly with confining pressure. In most experiments, a small drop in the injection pressure record is observed at what is taken to be fracture initiation, and in the Pennant sandstone this is accompanied by a small burst of acoustic energy. The shale materials were acoustically quiet. Breakdown is found to be rapid and uncontrollable after initiation if injection is continued. A simplified 2-dimensional model for explaining this is presented in terms of the stress intensities at the tip of a pressurised crack, and is used alongside the triaxial data to derive a characteristic flaw size from which the fractures have initiated in the borehole wall.

Monitoring concentration and isotopic composition of methane in groundwater in the Utica Shale hydraulic fracturing region of Ohio.

PubMed

Claire Botner, E; Townsend-Small, Amy; Nash, David B; Xu, Xiaomei; Schimmelmann, Arndt; Miller, Joshua H

2018-05-03

Degradation of groundwater quality is a primary public concern in rural hydraulic fracturing areas. Previous studies have shown that natural gas methane (CH 4 ) is present in groundwater near shale gas wells in the Marcellus Shale of Pennsylvania, but did not have pre-drilling baseline measurements. Here, we present the results of a free public water testing program in the Utica Shale of Ohio, where we measured CH 4 concentration, CH 4 stable isotopic composition, and pH and conductivity along temporal and spatial gradients of hydraulic fracturing activity. Dissolved CH 4 ranged from 0.2 μg/L to 25 mg/L, and stable isotopic measurements indicated a predominantly biogenic carbonate reduction CH 4 source. Radiocarbon dating of CH 4 in combination with stable isotopic analysis of CH 4 in three samples indicated that fossil C substrates are the source of CH 4 in groundwater, with one 14 C date indicative of modern biogenic carbonate reduction. We found no relationship between CH 4 concentration or source in groundwater and proximity to active gas well sites. No significant changes in CH 4 concentration, CH 4 isotopic composition, pH, or conductivity in water wells were observed during the study period. These data indicate that high levels of biogenic CH 4 can be present in groundwater wells independent of hydraulic fracturing activity and affirm the need for isotopic or other fingerprinting techniques for CH 4 source identification. Continued monitoring of private drinking water wells is critical to ensure that groundwater quality is not altered as hydraulic fracturing activity continues in the region. Graphical abstract A shale gas well in rural Appalachian Ohio. Photo credit: Claire Botner.

Anisotropic and heterogeneous mechanical properties of a stratified shale/limestone sequence at Nash Point, South Wales: A case study for hydraulic fracture propagation through a layered medium

NASA Astrophysics Data System (ADS)

Forbes Inskip, Nathaniel; Meredith, Philip; Gudmundsson, Agust

2016-04-01

While considerable effort has been expended on the study of fracture propagation in rocks in recent years, our understanding of how fractures propagate through layered sedimentary rocks with different mechanical and elastic properties remains poorly constrained. Yet this is a key issue controlling the propagation of both natural and anthropogenic hydraulic fractures in layered sequences. Here we report measurements of the contrasting mechanical and elastic properties of the Lower Lias at Nash Point, South Wales, which comprises an interbedded sequence of shale and limestone layers, and how those properties may influence fracture propagation. Elastic properties of both materials have been characterised via ultrasonic wave velocity measurements as a function of azimuth on samples cored both normal and parallel to bedding. The shale is highly anisotropic, with P-wave velocities varying from 2231 to 3890 m s-1, giving an anisotropy of ~55%. By contrast, the limestone is essentially isotropic, with a mean P-wave velocity of 5828 m s-1 and an anisotropy of ~2%. The dynamic Young's modulus of the shale, calculated from P- and S-wave velocity data, is also anisotropic with a value of 36 GPa parallel to bedding and 12 GPa normal to bedding. The modulus of the limestone is again isotropic with a value of 80 GPa. It follows that for a vertical fracture propagating (i.e. normal to bedding) the modulus contrast is 6.6. This is important because the contrast in elastic properties is a key factor in controlling whether fractures arrest, deflect, or propagate across interfaces between layers in a sequence. There are three principal mechanisms by which a fracture may deflect across or along an interface, namely: Cook-Gordon debonding, stress barrier, and elastic mismatch. Preliminary numerical modelling results (using a Finite Element Modelling software) of induced fractures at Nash Point suggest that all three are important. The results demonstrate a rotation of the maximum principal compressive stress across an interface but also a confinement of tensile stress within the host layer. Mechanical properties have been characterised by indirect measurement of the tensile strength using the Brazil-Disk technique. Measurements were made in the three principal orientations relative to bedding, Arrester, Divider, and Short-Transverse, and also at 15° intervals between these planes. Values for the shale again showed a high degree of anisotropy; with similar values in the Arrester and Divider orientations, but with much lower values in the Short-Transverse (bedding parallel) orientation. The tensile strength of the limestone is considerably higher than that of the shale and exhibits no significant anisotropy. Current work is underway to characterise the fracture propagation properties by measuring the fracture toughness and fracture ductility of both rocks using a combination of the Semi-Circular Bend and Short-Rod techniques.

Microbial metabolisms in a 2.5-km-deep ecosystem created by hydraulic fracturing in shales.

PubMed

Daly, Rebecca A; Borton, Mikayla A; Wilkins, Michael J; Hoyt, David W; Kountz, Duncan J; Wolfe, Richard A; Welch, Susan A; Marcus, Daniel N; Trexler, Ryan V; MacRae, Jean D; Krzycki, Joseph A; Cole, David R; Mouser, Paula J; Wrighton, Kelly C

2016-09-05

Hydraulic fracturing is the industry standard for extracting hydrocarbons from shale formations. Attention has been paid to the economic benefits and environmental impacts of this process, yet the biogeochemical changes induced in the deep subsurface are poorly understood. Recent single-gene investigations revealed that halotolerant microbial communities were enriched after hydraulic fracturing. Here, the reconstruction of 31 unique genomes coupled to metabolite data from the Marcellus and Utica shales revealed that many of the persisting organisms play roles in methylamine cycling, ultimately supporting methanogenesis in the deep biosphere. Fermentation of injected chemical additives also sustains long-term microbial persistence, while thiosulfate reduction could produce sulfide, contributing to reservoir souring and infrastructure corrosion. Extensive links between viruses and microbial hosts demonstrate active viral predation, which may contribute to the release of labile cellular constituents into the extracellular environment. Our analyses show that hydraulic fracturing provides the organismal and chemical inputs for colonization and persistence in the deep terrestrial subsurface.

Chemical characterization of gas- and oil-bearing shales by instrumental neutron activation analysis

USGS Publications Warehouse

Frost, J.K.; Koszykowski, R.F.; Klemm, R.C.

1982-01-01

The concentration of As, Ba, Ca, Co, Cr, Cs, Dy, Eu, Fe, Ga, Hf, K, La, Lu, Mn, Mo, Na, Ni, Rb, Sb, Sc, Se, Sm, Sr, Ta, Tb, Th, U, Yb, and Zn were determined by instrumental neutron activation analysis in block shale samples of the New Albany Group (Devonian-Mississippian) in the in the Illinois Basin. Uranium content of the samples was as high as 75 ppm and interfered in the determination of samarium, molybdenum, barium and cerium. In the determination of selenium a correction was made for interference from tantalum. U, As, Co, Mo, Ni and Sb as well as Cu, V and pyritic sulphur which were determined by other methods, were found to correlate positively with the organic carbon content of the samples. ?? 1982 Akade??miai Kiado??.

Weathering of the New Albany Shale, Kentucky, USA: I. Weathering zones defined by mineralogy and major-element composition

USGS Publications Warehouse

Tuttle, M.L.W.; Breit, G.N.

2009-01-01

Comprehensive understanding of chemical and mineralogical changes induced by weathering is valuable information when considering the supply of nutrients and toxic elements from rocks. Here minerals that release and fix major elements during progressive weathering of a bed of Devonian New Albany Shale in eastern Kentucky are documented. Samples were collected from unweathered core (parent shale) and across an outcrop excavated into a hillside 40 year prior to sampling. Quantitative X-ray diffraction mineralogical data record progressive shale alteration across the outcrop. Mineral compositional changes reflect subtle alteration processes such as incongruent dissolution and cation exchange. Altered primary minerals include K-feldspars, plagioclase, calcite, pyrite, and chlorite. Secondary minerals include jarosite, gypsum, goethite, amorphous Fe(III) oxides and Fe(II)-Al sulfate salt (efflorescence). The mineralogy in weathered shale defines four weathered intervals on the outcrop-Zones A-C and soil. Alteration of the weakly weathered shale (Zone A) is attributed to the 40-a exposure of the shale. In this zone, pyrite oxidization produces acid that dissolves calcite and attacks chlorite, forming gypsum, jarosite, and minor efflorescent salt. The pre-excavation, active weathering front (Zone B) is where complete pyrite oxidation and alteration of feldspar and organic matter result in increased permeability. Acidic weathering solutions seep through the permeable shale and evaporate on the surface forming abundant efflorescent salt, jarosite and minor goethite. Intensely weathered shale (Zone C) is depleted in feldspars, chlorite, gypsum, jarosite and efflorescent salts, but has retained much of its primary quartz, illite and illite-smectite. Goethite and amorphous FE(III) oxides increase due to hydrolysis of jarosite. Enhanced permeability in this zone is due to a 14% loss of the original mass in parent shale. Denudation rates suggest that characteristics of Zone C were acquired over 1 Ma. Compositional differences between soil and Zone C are largely attributed to illuvial processes, formation of additional Fe(III) oxides and incorporation of modern organic matter.

Undiscovered petroleum resources for the Woodford Shale and Thirteen Finger Limestone-Atoka Shale assessment units, Anadarko Basin

USGS Publications Warehouse

Higley, Debra K.

2011-01-01

In 2010 the U.S. Geological Survey assessed undiscovered oil and gas resources for the Anadarko Basin Province of Colorado, Kansas, Oklahoma, and Texas. The assessment included three continuous (unconventional) assessment units (AU). Mean undiscovered resources for the (1) Devonian Woodford Shale Gas AU are about 16 trillion cubic feet of gas (TCFG) and 192 million barrels of natural gas liquids (MMBNGL), (2) Woodford Shale Oil AU are 393 million barrels of oil (MMBO), 2 TCFG, and 59 MMBNGL, and (3) Pennsylvanian Thirteen Finger Limestone-Atoka Shale Gas AU are 6.8 TCFG and 82 MMBNGL. The continuous gas AUs are mature for gas generation within the deep basin of Oklahoma and Texas. Gas generation from the Woodford Shale source rock started about 335 Ma, and from the Thirteen Finger Limestone-Atoka Shale AU about 300 Ma. Maturation results are based on vitrinite reflectance data, and on 1D and 4D petroleum system models that calculated vitrinite reflectance (Ro), and Rock-Eval and hydrous pyrolysis transformation (HP) ratios through time for petroleum source rocks. The Woodford Shale Gas AU boundary and sweet spot were defined mainly on (1) isopach thickness from well-log analysis and published sources; (2) estimated ultimate recoverable production from existing, mainly horizontal, wells; and (3) levels of thermal maturation. Measured and modeled Ro ranges from about 1.2% to 5% in the AU, which represents marginally mature to overmature for gas generation. The sweet spot included most of the Woodford that was deposited within eroded channels in the unconformably underlying Hunton Group. The Thirteen Finger Limestone-Atoka Shale Gas AU has no known production in the deep basin. This AU boundary is based primarily on the gas generation window, and on thickness and distribution of organic-rich facies from these mainly thin shale and limestone beds. Estimates of organic richness were based on well-log signatures and published data.

Four dimensional X-ray imaging of deformation modes in organic-rich Green River Shale retorted under uniaxial compression

NASA Astrophysics Data System (ADS)

Kobchenko, M.; Pluymakers, A.; Cordonnier, B.; Tairova, A.; Renard, F.

2017-12-01

Time-lapse imaging of fracture network development in organic-rich shales at elevated temperatures while kerogen is retorted allows characterizing the development of microfractures and the onset of primary migration. When the solid organic matter is transformed to hydrocarbons with lower molecular weight, the local pore-pressure increases and drives the propagation of hydro-fractures sub-parallel to the shale lamination. On the scale of samples of several mm size, these fractures can be described as mode I opening, where fracture walls dilate in the direction of minimal compression. However, so far experiments coupled to microtomography in situ imaging have been performed on samples where no load was imposed. Here, an external load was applied perpendicular to the sample laminations and we show that this stress state slows down, but does not stop, the propagation of fracture along bedding. Conversely, microfractures also propagate sub-perpendicular to the shale lamination, creating a percolating network in three dimensions. To monitor this process we have used a uniaxial compaction rig combined with in-situ heating from 50 to 500 deg C, while capturing three-dimensional X-ray microtomography scans at a voxel resolution of 2.2 μm; Data were acquired at beamline ID19 at the European Synchrotron Radiation Facility. In total ten time-resolved experiments were performed at different vertical loading conditions, with and without lateral passive confinement and different heating rates. At high external load the sample fails by symmetric bulging, while at lower external load the reaction-induced fracture network develops with the presence of microfractures both sub-parallel and sub-perpendicular to the bedding direction. In addition, the variation of experimental conditions allows the decoupling of the effects of the hydrocarbon decomposition reaction on the deformation process from the influence of thermal stress heating on the weakening and failure mode of immature shale.

Interpretation of Microseismicity Observed From Surface and Borehole Seismic Arrays During Hydraulic Fracturing in Shale - Bedding Plane Slip Model

NASA Astrophysics Data System (ADS)

Stanek, F.; Jechumtalova, Z.; Eisner, L.

2017-12-01

We present a geomechanical model explaining microseismicity induced by hydraulic fracturing in shales developed from many datasets acquired with two most common types of seismic monitoring arrays, surface and dual-borehole arrays. The geomechanical model explains the observed source mechanisms and locations of induced events from two stimulated shale reservoirs. We observe shear dip-slip source mechanisms with nodal planes aligned with location trends. We show that such seismicity can be explained as a shearing along bedding planes caused by aseismic opening of vertical hydraulic fractures. The source mechanism inversion was applied only to selected high-quality events with sufficient signal-to-noise ratio. We inverted P- and P- and S-wave arrival amplitudes to full-moment tensor and decomposed it to shear, volumetric and compensated linear vector dipole components. We also tested an effect of noise presented in the data to evaluate reliability of non-shear components. The observed seismicity from both surface and downhole monitoring of shale stimulations is very similar. The locations of induced microseismic events are limited to narrow depth intervals and propagate along distinct trend(s) showing fracture propagation in direction of maximum horizontal stress from injection well(s). The source mechanisms have a small non-shear component which can be partly explained as an effect of noise in the data, i.e. events represent shearing on faults. We observe predominantly dip-slip events with a strike of the steeper (almost vertical) nodal plane parallel to the fracture propagation. Therefore the other possible nodal plane is almost horizontal. The rake angles of the observed mechanisms divide these dip-slips into two groups with opposite polarities. It means that we observe opposite movements on the nearly identically oriented faults. Realizing a typical structural weakness of shale in horizontal planes, we interpret observed microseismicity as a result of shearing along bedding planes caused by seismically silent (aseismic) vertical fracture opening.

Water pollution risk associated with natural gas extraction from the Marcellus Shale.

PubMed

Rozell, Daniel J; Reaven, Sheldon J

2012-08-01

In recent years, shale gas formations have become economically viable through the use of horizontal drilling and hydraulic fracturing. These techniques carry potential environmental risk due to their high water use and substantial risk for water pollution. Using probability bounds analysis, we assessed the likelihood of water contamination from natural gas extraction in the Marcellus Shale. Probability bounds analysis is well suited when data are sparse and parameters highly uncertain. The study model identified five pathways of water contamination: transportation spills, well casing leaks, leaks through fractured rock, drilling site discharge, and wastewater disposal. Probability boxes were generated for each pathway. The potential contamination risk and epistemic uncertainty associated with hydraulic fracturing wastewater disposal was several orders of magnitude larger than the other pathways. Even in a best-case scenario, it was very likely that an individual well would release at least 200 m³ of contaminated fluids. Because the total number of wells in the Marcellus Shale region could range into the tens of thousands, this substantial potential risk suggested that additional steps be taken to reduce the potential for contaminated fluid leaks. To reduce the considerable epistemic uncertainty, more data should be collected on the ability of industrial and municipal wastewater treatment facilities to remove contaminants from used hydraulic fracturing fluid. © 2012 Society for Risk Analysis.

Zonation of shale reservoir stimulation modes: a conceptual model based on hydraulic fracturing data from the Baltic Basin (Poland).

NASA Astrophysics Data System (ADS)

Jarosiński, Marek; Pachytel, Radomir

2017-04-01

Depending on the pressure distribution within Stimulated Reservoir Volume (SRV), a different modes of hydraulic fracturing or tectonic fracture reactivation are active. Hydraulic pressure-driven shortening or expansion of reservoir produces changes in stress field that results in decrease of differential stress either by increasing of horizontal stress minimum (Shmin) or/and by decreasing of horizontal stress maximum (SHmax). For further considerations we assume initial strike-slip stress regime which prevails in the Polish part of the Lower Paleozoic Baltic Basin (BB), as well as in majority of the USA shale basins. The data come from vertical and horizontal shale gas exploration wells drilled from one pad located in the middle of the BB. Structural survey of a long core interval combined with stress analysis based on microfrac tests and fracturing tests allow to reconstruct the initial structural and geomechanical state of reservoir. Further geomechanical evolution of the SRV depends on the hydraulic pressure bubble growth, which is in general unknown. However, the state of pressure can be determined close to the injection borehole and in the front of the SRV migrating in time. In our case, we are able to distinguish four stimulation zones characterized by increasingly diverse stimulation modes and successively closer to the borehole injection zone: (1) shear on preexisting fractures generates microseismic events that produce open fractures propped by their natural asperities being impenetrable for proppant grains; (2) above + initial hydraulic opening of natural fractures that are preferentially oriented to the Shmin, which favors microseismic events triggered by secondary shear on bedding planes and produces open spaces supported by natural fracture asperities and fine-grained proppant; (3) above + failure of primary hydraulic fractures, which increases extensional component of the microseismic events and opens space for coarse-grained proppant; (4) above + opening of horizontal bedding fractures, that do not prevail any microseismic mechanism, stabilizes the stresses at the level close to the thrust fault regime and opens space for large amount of proppant. This stimulation mode is undesirable because horizontal bedding fractures do not drain shale matrix efficiently due to low vertical permeability of shale and sealing of bedding planes by high clay content that enhances embedment effect on proppant. The number and order of stimulation zones is site- or basin-specific and may not apply directly to other locations. In the case of strong mechanical layering the stimulation mode can also vary among formations. Large number of preferentially oriented natural fractures (like in majority of boreholes in the BB), may cause the technological hydraulic fractures to play a subordinate role. Because in the BB tectonic fractures are filled with calcite, it may negatively influence gas drainage to stimulated fractures. In our scenario, also the primary shear failure mode is not achieved due to low differential stress in respect to compressive strength of shale. The shape of stimulation zones might not be regular but adjusted to the pattern of stimulated fractures creating principal pathways for hydraulic pressure propagation into reservoir. Bearing in mind the sequence of stimulation mode zones we are able to better understand the pattern of microseismic events and predict, to some extend, the proppant distribution within SRV.

Micromorphologic evidence for paleosol development in the Endicott group, Siksikpuk formation, Kingak(?) shale, and Ipewik formation, western Brooks range, Alaska

USGS Publications Warehouse

Dumoulin, Julie A.; White, Tim

2005-01-01

Micromorphologic evidence indicates the presence of paleosols in drill-core samples from four sedimentary units in the Red Dog area, western Brooks Range. Well-developed sepic-plasmic fabrics and siderite spherules occur in claystones of the Upper Devonian through Lower Mississippian(?) Kanayut Conglomerate (Endicott Group), the Pennsylvanian through Permian Siksikpuk Formation (Etivluk Group), the Jurassic through Lower Cretaceous Kingak(?) Shale, and the Lower Cretaceous Ipewik Formation. Although exposure surfaces have been previously recognized in the Endicott Group and Kingak Shale on the basis of outcrop features, our study is the first microscopic analysis of paleosols from these units, and it provides the first evidence of subaerial exposure in the Siksikpuk and Ipewik Formations. Regional stratigraphic relations and geochemical data support our interpretations. Paleosols in the Siksikpuk, Kingak, and Ipewik Formations likely formed in nearshore coastal-plain environments, with pore waters subjected to inundation by the updip migration of slightly brackish ground water, whereas paleosols in the Kanayut Conglomerate probably formed in a more distal setting relative to a marine basin.

The radioisotopically constrained Viséan onset of turbidites in the Moravian-Silesian part of the Rhenohercynian foreland basin (Central European Variscides)

NASA Astrophysics Data System (ADS)

Jirásek, Jakub; Otava, Jiří; Matýsek, Dalibor; Sivek, Martin; Schmitz, Mark D.

2018-03-01

The Březina Formation represents the initiation of siliciclastic flysch turbidite sedimentation at the eastern margin of Bohemian Massif or within the Rhenohercynian foreland basin. Its deposition started after drowning of the Devonian carbonate platform during Viséan (Mississippian) times, resulting in a significant interval of black siliceous shale and variegated fossiliferous shale deposition in a starved basin. Near the top of the Březina Formation an acidic volcanoclastic layer (tuff) of rhyolitic composition has been dated with high precision U-Pb zircon chemical abrasion isotope dilution method at 337.73 ± 0.16 Ma. This new radiometric age correlates with the previously inferred stratigraphic age of the locality and the current calibration of the Early Carboniferous geologic time scale. Shales of the Březina Formation pass gradually upwards into the siliciclastics of the Rozstání Formation of the Drahany culm facies. Thus our new age offers one of the few available radioisotopic constraints on the time of onset of siliciclastic flysch turbidites in the Rhenohercynian foreland basin of the European Variscides.

Developing a shale heterogeneity index to predict fracture response in the Mancos Shale

NASA Astrophysics Data System (ADS)

DeReuil, Aubry; Birgenheier, Lauren; McLennan, John

2017-04-01

The interplay between sedimentary heterogeneity and fracture propagation in mudstone is crucial to assess the potential of low permeability rocks as unconventional reservoirs. Previous experimental research has demonstrated a relationship between heterogeneity and fracture of brittle rocks, as discontinuities in a rock mass influence micromechanical processes such as microcracking and strain localization, which evolve into macroscopic fractures. Though numerous studies have observed heterogeneity influencing fracture development, fundamental understanding of the entire fracture process and the physical controls on this process is still lacking. This is partly due to difficulties in quantifying heterogeneity in fine-grained rocks. Our study tests the hypothesis that there is a correlation between sedimentary heterogeneity and the manner in which mudstone is fractured. An extensive range of heterogeneity related to complex sedimentology is represented by various samples from cored intervals of the Mancos Shale. Samples were categorized via facies analysis consisting of: visual core description, XRF and XRD analysis, SEM and thin section microscopy, and reservoir quality analysis that tested porosity, permeability, water saturation, and TOC. Systematic indirect tensile testing on a broad variety of facies has been performed, and uniaxial and triaxial compression testing is underway. A novel tool based on analytically derived and statistically proven relationships between sedimentary geologic and geomechanical heterogeneity is the ultimate result, referred to as the shale heterogeneity index. Preliminary conclusions from development of the shale heterogeneity index reveal that samples with compositionally distinct bedding withstand loading at higher stress values, while texturally and compositionally homogeneous, bedded samples fail at lower stress values. The highest tensile strength results from cemented Ca-enriched samples, medial to high strength samples have approximately equivalent proportions of Al-Ca-Si compositions, while Al-rich samples have consistently low strength. Moisture preserved samples fail on average at approximately 5 MPa lower than dry samples of similar facies. Additionally, moisture preserved samples fail in a step-like pattern when tested perpendicular to bedding. Tensile fractures are halted at heterogeneities and propagate parallel to bedding planes before developing a through-going failure plane, as opposed to the discrete, continuous fractures that crosscut dry samples. This result suggests that sedimentary heterogeneity plays a greater role in fracture propagation in moisture preserved samples, which are more indicative of in-situ reservoir conditions. Stress-strain curves will be further analyzed, including estimation of an energy released term based on post-failure response, and an estimation of volume of cracking measure on the physical fracture surface.

Numerical Modeling of Gas and Water Flow in Shale Gas Formations with a Focus on the Fate of Hydraulic Fracturing Fluid.

PubMed

Edwards, Ryan W J; Doster, Florian; Celia, Michael A; Bandilla, Karl W

2017-12-05

Hydraulic fracturing in shale gas formations involves the injection of large volumes of aqueous fluid deep underground. Only a small proportion of the injected water volume is typically recovered, raising concerns that the remaining water may migrate upward and potentially contaminate groundwater aquifers. We implement a numerical model of two-phase water and gas flow in a shale gas formation to test the hypothesis that the remaining water is imbibed into the shale rock by capillary forces and retained there indefinitely. The model includes the essential physics of the system and uses the simplest justifiable geometrical structure. We apply the model to simulate wells from a specific well pad in the Horn River Basin, British Columbia, where there is sufficient available data to build and test the model. Our simulations match the water and gas production data from the wells remarkably closely and show that all the injected water can be accounted for within the shale system, with most imbibed into the shale rock matrix and retained there for the long term.

Geologic structure and occurrence of gas in part of southwestern New York. Part 1, Structure and gas possibilities of the Oriskany sandstone in Steuben, Yates, and parts of the adjacent counties

USGS Publications Warehouse

Bradley, W.H.; Pepper, J.F.

1941-01-01

The area covered by this report is in southwestern New York and includes a little more than 3,000 square miles in Steuben and Yates counties and parts of the six adjacent counties. This area has been mapped to determine the structural attitude of the exposed rocks, so as to aid those interested in prospecting for natural gas in the Oriskany sandstone of Lower Devonian age.Because of the gentle regional dip toward the southwest, the youngest beds are exposed in the southwest corner of the area, and progressively older beds crop out northeastward in successive bands that strike generally northwest. All the exposed rocks are of Upper Devonian age except those in a narrow belt at the extreme north edge of the area, where a small thickness of Middle Devonian rocks crops out. The maximum thickness of beds so exposed is nearly 4,000 feet, of which the lower part is predominantly soft dark shale and the upper part predominantly fine-grained sandstone and gray shale. All the beds are marine except a few tongues of continental deposits red shale and sandstone and gray mudstone in the youngest beds. All the beds thicken southeastward, so that there is a northwestward convergence between any two lithologic units in the series. More than 30 key horizons that are persistent and distinctive were mapped, and altitudes on these key horizons served as a basis for constructing the structure contour map. Many of the key horizons are formation or member boundaries, but others are the tops or bottoms of limestone or sandstone beds within formations. All the stratigraphic units mapped are purely lithologic. (See pi. 2.)The Tully limestone, which crops out along the northern border of the area, is an easily recognizable and therefore valuable key bed for subsurface correlations in this part of the State. Below the Tully limestone is a thick body of Middle Devonian shales of the Hamilton group which rests on another valuable key bed, the hard, cherty Onondaga limestone, also of Middle Devonian age. Below the Onondaga limestone is the Lower Devonian Oriskany sandstone, which is the gas-producing bed. Unlike the Onondaga, the Oriskany is locally thin or absent.The structure of most of the area is shown by contour lines at 25-foot intervals, but where key horizons are lacking the structure is indicated by dip symbols. Upon the regional south and southwest dip are superposed numerous gentle folds whose axes trend approximately northeastward in the greater part of the area but more nearly eastward in the eastern part. The folds generally tend to become narrower and steeper, and therefore more closely spaced, southwestward. Many of the anticlines fork southwestward, whereas the synclines. tend to fork northeastward. All the folds have a westward or southwestward plunge. Throughout the area the rocks are jointed in two dominant sets one that trends northwest and the other east or northeast. No evident relation .between these joints, which were measured only in the hard, relatively brittle beds, and the individual folds or domes was discernible.The faults are concentrated in the northeastern and southwestern parts of the area and trend either northeastward or northwestward. Some are nearly vertical normal faults; others are steep reverse faults. Subsurface data show that most of the faults increase in throw downward and also that many subsurface faults do not reach the surface. A group of faults in the northwestern part of the Greenwood quadrangle and the southwestern part of the Hornell quadrangle were active during Upper Devonian time, while the Gowanda shale and overlying beds were being deposited. At this stratigraphic horizon the beds in a zone a few hundred feet thick are highly deformed in a wide belt on both sides of the faults. Sandstone layers are thinned out into long stringers or swollen into thick masses and in places are bent acutely without fracture. Thin layers of shale, coquina, and sand have flowed together into intricately plicated zones that lack cleavage and joints. These features show that the sediments were deformed while wet and plastic and buried only a little way below the sea floor. The beds that were laid down over these disturbed zones were not involved in this deformation. Many of the sharper flexures and most of the faults are not evident in the beds several hundred feet stratigraphically higher. Accordingly, broad, gentle folds in these higher beds in parts of the area south and west of the northwest corner of the Greenwood quadrangle may conceal, at considerable depths below them, narrow folds separated by abrupt flexures or faults.Several of the larger streams and rivers occupy strike valleys, and their j courses swing to follow the changing strike of the rocks where they cross ( successive folds. But, with few exceptions, the small streams are not adjusted to the bedrock structure. Domes likely to serve as traps for natural gas are concentrated in the northeastern and southwestern parts of the area. The Wayne-Dundee gas field is in the northeastern part. All the other potentially valuable domes in this part of the area have been drilled and found valueless except one small structural feature in the southern part of the Ovid quadrangle, which, if the Oriskany is present, may trap a small quantity of gas.In the Greenwood quadrangle in the southwestern part of the area there is one gas field and four well-defined domes, all of which may be productive if the Oriskany sandstone is present. In the northwest corner of the quadrangle the dips indicate at least two domes that can be adequately defined and evaluated only by geophysical prospecting. The State Line gas field is in tbe Wellsville quadrangle. In the southeast corner of this quadrangle there are three other domes of comparable size that may also be productive if underlain by the Oriskany sandstone. At other places in the Wellsville quadrangle the dips suggest several anticlinal axes on which analogous productive domes maybe found. The structural features in this quadrangle, however, are defined by contours only in the southeastern part. In the Woodhull quadrangle a large dome east of Jasper may be productive, and the western top of the large Woodhull dome in the southwestern part of the quadrangle seems to warrant drilling, despite the absence of the Oriskany in a well on the eastern top. Two wells drilled in 1936 and 1937 a little northeast of a broad, nearly flat-topped dome in the Hornell quadrangle, a few miles east of Hornell,, struck small flows of gas, suggesting that wells drilled higher on this dome may be productive.In much of the southwestern part of the area seismograph surveys should be of great value in determining the structure at the Tully and Onondaga horizons. Without abundant subsurface control of this sort, the danger of drilling into subsurface faults can hardly be overemphasized. Three closed or nearly closed synclines in the Greenwood and Wellsville quadrangles appear to be favorable places to drill for oil in the shallow sands presumably parts of the Dunkirk sandstone.

Geologic structure and occurrence of gas in part of southwestern New York

USGS Publications Warehouse

Bradley, Wilmot H.; Pepper, James F.; Richardson, G.B.

1941-01-01

The area covered by this report is in southwestern New York and includes a little more than 3,000 square miles in Steuben and Yates counties and parts of the six adjacent counties. This area has been mapped to determine the structural attitude of the exposed rocks, so as to aid those interested in prospecting for natural gas in the Oriskany sandstone of Lower Devonian age.Because of the gentle regional dip toward the southwest, the youngest beds are exposed in the southwest corner of the area, and progressively older beds crop out northeastward in successive bands that strike generally northwest. All the exposed rocks are of Upper Devonian age except those in a narrow belt at the extreme north edge of the area, where a small thickness of Middle Devonian rocks crops out. The maximum thickness of beds so exposed is nearly 4,000 feet, of which the lower part is predominantly soft dark shale and the upper part predominantly fine-grained sandstone and gray shale. All the beds are marine except a few tongues of continental deposits—red shale and sandstone and gray mudstone—in the youngest beds. All the beds thicken southeastward, so that there is a northwestward convergence between any two lithologic units in the series. More than 30 key horizons that are persistent and distinctive were mapped, and altitudes on these key horizons served as a basis for constructing the structure contour map. Many of the key horizons are formation or member boundaries, but others are the tops or bottoms of limestone or sandstone beds within formations. All the stratigraphic units mapped are purely lithologic. (See pl. 2.)The Tully limestone, which crops out along the northern border of the area, is an easily recognizable and therefore valuable key bed for subsurface correlations in this part of the State. Below the Tully limestone is a thick body of Middle Devonian shales of the Hamilton group which rests on another valuable key bed, the hard, cherty Onondaga limestone, also of Middle Devonian age. Below the Onondaga limestone is the Lower Devonian Oriskany sandstone, which is the gas-producing bed. Unlike the Onondaga, the Oriskany is locally thin or absent.The structure of most of the area is shown by contour lines at 25-foot intervals, but, where key horizons are lacking the structure is indicated by dip symbols. Upon the regional south and southwest dip are superposed numerous gentle folds whose axes trend approximately northeastward in the greater part of the area but more nearly eastward in the eastern part. The folds generally tend to become narrower and steeper, and therefore more closely spaced, southwestward. Many of the anticlines fork southwestward, whereas the synclines tend to fork northeastward. All the folds have a westward or southwestward plunge.Throughout the area the rocks are jointed in two dominant sets—one that trends northwest and the other east or northeast. No evident relation between these joints, which were measured only in the hard, relatively brittle beds, and the individual folds or domes was discernible.The faults are concentrated in the northeastern and southwestern parts of the area and trend either northeastward or northwestward. Some are nearly vertical normal faults ; others are steep reverse faults. Subsurface data show that most of the faults increase in throw downward and also that many subsurface faults do not reach the surface. A group of faults in the northwestern part of the Greenwood quadrangle and the southwestern part of the Hornell quadrangle were active during Upper Devonian time, while the Gowanda shale and overlying beds were being deposited. At this stratigraphic horizon the beds in a zone a few hundred feet thick are highly deformed in a wide belt on both sides of the faults. Sandstone layers are thinned out into long stringers or swollen into thick masses and in places are bent acutely without fracture. Thin layers of shale, coquina, and sand have flowed together into intricately plicated zones that lack cleavage and joints. These features show that the sediments were deformed while wet and plastic and buried only a little way below the sea floor. The beds that were laid down over these disturbed zones were not involved in this deformation. Many of the sharper flexures and most of the faults are not evident in the beds several hundred feet stratigraphically higher. Accordingly, broad, gentle folds in these higher beds in parts of the area south and west of the northwest corner of the Greenwood quadrangle may conceal, at considerable depths below them, narrow folds separated by abrupt flexures or faults.Several of the larger streams and rivers occupy strike valleys, and their courses swing to follow the changing strike of the rocks where they cross successive folds. But, with few exceptions, the small streams are not adjusted to the bedrock structure.Domes likely to serve as traps for natural gas are concentrated in the northeastern and southwestern parts of the area. The Wayne-Dundee gas field is in the northeastern part. All the other potentially valuable domes in this part of the area have been drilled and found valueless except one small structural feature in the southern part of the Ovid quadrangle, which, if the Oriskany is present, may trap a small quantity of gas.In the Greenwood quadrangle in the southwestern part of the area there is one gas field and four well-defined domes, all of which may be productive if the Oriskany sandstone is present. In the northwest corner of the quadrangle the dips indicate at least two domes that can be adequately defined and evaluated only by geophysical prospecting. The State Line gas field is in the Wellsville quadrangle. In the southeast corner of this quadrangle there are three other domes of comparable size that may also be productive if underlain by the Oriskany sandstone. At other places in the Wellsville quadrangle the dips suggest several anticlinal axes on which analogous productive domes may be found. The structural features in this quadrangle, however, are defined by contours only in the southeastern part. In the Woodhull quadrangle a large dome east of Jasper may be productive, and the western top of the large Wood-hull dome in the southwestern part of the quadrangle seems to warrant drilling, despite the absence of the Oriskany in a well on the eastern top. Two wells drilled in 1936 and 1937 a little northeast of a broad, nearly flat-topped dome in the Hornell quadrangle, a few miles east of Hornell, struck small flows of gas, suggesting that wells drilled higher on this dome may be productive.In much of the southwestern part of the area seismograph surveys should be of great value in determining the structure at the Tully and Onondaga horizons. Without abundant subsurface control of this sort, the danger of drilling into subsurface faults can hardly be overemphasized.Three closed or nearly closed synclines in the Greenwood and Wellsville quadrangles appear to be favorable places to drill for oil in the shallow sands— presumably parts of the Dunkirk sandstone.

How Reducing was the Late Devonian Ocean? The Role of Extensive Expansion of Anoxia in Marine Biogeochemical Cycles of Redox Sensitive Metals.

NASA Astrophysics Data System (ADS)

Sahoo, S. K.; Jin, H.

2017-12-01

The evolution of Earth's biogeochemical cycles is intimately linked to the oxygenation of the oceans and atmosphere. The Late Devonian is no exception as its characterized with mass extinction and severe euxinia. Here we use concentrations of Molybdenum (Mo), Vanadium (V), Uranium (U) and Chromium (Cr) in organic rich black shales from the Lower Bakken Formation of the Williston Basin, to explore the relationship between extensive anoxia vs. euxinia and it's relation with massive release of oxygen in the ocean atmosphere system. XRF data from 4 core across the basin shows that modern ocean style Mo, U and Cr enrichments are observed throughout the Lower Bakken Formation, yet V is not enriched until later part of the formation. Given the coupling between redox-sensitive-trace element cycles and ocean redox, various models for Late Devonian ocean chemistry imply different effects on the biogeochemical cycling of major and trace nutrients. Here, we examine the differing redox behavior of molybdenum and vanadium under an extreme anoxia and relatively low extent of euxinia. The model suggests that Late Devonian was perhaps extensively anoxic- 40-50% compared to modern seafloor area, and a very little euxinia. Mo enrichments extend up to 500 p.p.m. throughout the section, representative of a modern reducing ocean. However, coeval low V enrichments only support towards anoxia, where anoxia is a source of V, and a sink for Mo. Our model suggests that the oceanic V reservoir is extremely sensitive to perturbations in the extent of anoxic condition, particularly during post glacial times.

Hydraulic fracturing fluid migration in the subsurface: A review and expanded modeling results

NASA Astrophysics Data System (ADS)

Birdsell, Daniel T.; Rajaram, Harihar; Dempsey, David; Viswanathan, Hari S.

2015-09-01

Understanding the transport of hydraulic fracturing (HF) fluid that is injected into the deep subsurface for shale gas extraction is important to ensure that shallow drinking water aquifers are not contaminated. Topographically driven flow, overpressured shale reservoirs, permeable pathways such as faults or leaky wellbores, the increased formation pressure due to HF fluid injection, and the density contrast of the HF fluid to the surrounding brine can encourage upward HF fluid migration. In contrast, the very low shale permeability and capillary imbibition of water into partially saturated shale may sequester much of the HF fluid, and well production will remove HF fluid from the subsurface. We review the literature on important aspects of HF fluid migration. Single-phase flow and transport simulations are performed to quantify how much HF fluid is removed via the wellbore with flowback and produced water, how much reaches overlying aquifers, and how much is permanently sequestered by capillary imbibition, which is treated as a sink term based on a semianalytical, one-dimensional solution for two-phase flow. These simulations include all of the important aspects of HF fluid migration identified in the literature review and are performed in five stages to faithfully represent the typical operation of a hydraulically fractured well. No fracturing fluid reaches the aquifer without a permeable pathway. In the presence of a permeable pathway, 10 times more fracturing fluid reaches the aquifer if well production and capillary imbibition are not included in the model.

Evaluation of shale gas potential based on organic matter characteristics and gas concentration in the Devonian Horn River Formation, Canada

NASA Astrophysics Data System (ADS)

Choi, Jiyoung; Hong, Sung Kyung; Lee, Hyun Suk

2017-04-01

In this study, we investigate organic matter characteristics from the analysis of Rock-Eval6 and biomarker, and estimate methane concentration from headspace method in the Devonian Horn River Formation, which is one of the largest shale reservoir in western Canada. The Horn River Formation consists of the Evie, Otterpark and Muskwa members in ascending stratigraphic order. Total Organic Carbon (TOC) ranges from 0.34 to 7.57 wt%, with an average of 2.78 wt%. The Evie, middle Otterpark and Muskwa members have an average TOC of more than 3%, whereas those of the lower and upper Otterpark Member are less than 2%. Based on Pristane/n-C17 (0.2 0.6) and Phytane/n-C18 (0.3 0.9) ratios, the organic matter in the Evie, middle Otterpark and Muskwa members mainly consists of type II kerogen which are formed in reducing marine environment. Thermal maturity were examined through the use of the distributions of Phenanthrene (P) and Methylphenantrenes (MP) based on m/z 178 and 192 mass chromatograms, respectively (Radke et al., 1982). The methylphenanthrene index (MPI-1) are calculated as follows : MPI-1 = 1.5 × (2MP+3MP)/(P+1MP+9MP), and Ro are calculated as follows : Ro = -0.6 × MPI-1 + 2.3. Estimated Ro ranges between 1.88 and 1.93%, which indicates the last stage of wet gas generation. The methane concentrations in headspace range from 15 to 914 ppmv, with an average of 73.5 ppmv. The methane concentrations in the Evie, middle Otterpark and Muskwa members (up to 914 ppmv) are higher than those of the lower and upper Otterpark Member (up to 75 ppmv). Considering the organic geochemical characteristics and gas concentrations, the shale gas potentials of the Evie, middle Otterpark and Muskwa members are higher than those of other members.

Determining the source and genetic fingerprint of natural gases using noble gas geochemistry: a northern Appalachian Basin case study

USGS Publications Warehouse

Hunt, Andrew G.; Darrah, Thomas H.; Poreda, Robert J.

2012-01-01

Silurian and Devonian natural gas reservoirs present within New York state represent an example of unconventional gas accumulations within the northern Appalachian Basin. These unconventional energy resources, previously thought to be noneconomically viable, have come into play following advances in drilling (i.e., horizontal drilling) and extraction (i.e., hydraulic fracturing) capabilities. Therefore, efforts to understand these and other domestic and global natural gas reserves have recently increased. The suspicion of fugitive mass migration issues within current Appalachian production fields has catalyzed the need to develop a greater understanding of the genetic grouping (source) and migrational history of natural gases in this area. We introduce new noble gas data in the context of published hydrocarbon carbon (C1,C2+) (13C) data to explore the genesis of thermogenic gases in the Appalachian Basin. This study includes natural gases from two distinct genetic groups: group 1, Upper Devonian (Marcellus shale and Canadaway Group) gases generated in situ, characterized by early mature (13C[C1  C2][13C113C2]: –9), isotopically light methane, with low (4He) (average, 1  103 cc/cc) elevated 4He/40Ar and 21Ne/40Ar (where the asterisk denotes excess radiogenic or nucleogenic production beyond the atmospheric ratio), and a variable, atmospherically (air-saturated–water) derived noble gas component; and group 2, a migratory natural gas that emanated from Lower Ordovician source rocks (i.e., most likely, Middle Ordovician Trenton or Black River group) that is currently hosted primarily in Lower Silurian sands (i.e., Medina or Clinton group) characterized by isotopically heavy, mature methane (13C[C1 – C2] [13C113C2]: 3), with high (4He) (average, 1.85  103 cc/cc) 4He/40Ar and 21Ne/40Ar near crustal production levels and elevated crustal noble gas content (enriched 4He,21Ne, 40Ar). Because the release of each crustal noble gas (i.e., He, Ne, Ar) from mineral grains in the shale matrix is regulated by temperature, natural gases obtain and retain a record of the thermal conditions of the source rock. Therefore, noble gases constitute a valuable technique for distinguishing the genetic source and post-genetic processes of natural gases.

Chemical Effect on Wellbore Instability of Nahr Umr Shale

PubMed Central

Nie, Zhen

2013-01-01

Wellbore instability is one of the major problems that hamper the drilling speed in Halfaya Oilfield. Comprehensive analysis of geological and engineering data indicates that Halfaya Oilfield features fractured shale in the Nahr Umr Formation. Complex accidents such as wellbore collapse and sticking emerged frequently in this formation. Tests and theoretical analysis revealed that wellbore instability in the Halfaya Oilfield was influenced by chemical effect of fractured shale and the formation water with high ionic concentration. The influence of three types of drilling fluids on the rock mechanical properties of Nahr Umr Shale is tested, and time-dependent collapse pressure is calculated. Finally, we put forward engineering countermeasures for safety drilling in Halfaya Oilfield and point out that increasing the ionic concentration and improving the sealing capacity of the drilling fluid are the way to keep the wellbore stable. PMID:24282391

Chemical effect on wellbore instability of Nahr Umr Shale.

PubMed

Yu, Baohua; Yan, Chuanliang; Nie, Zhen

2013-01-01

Wellbore instability is one of the major problems that hamper the drilling speed in Halfaya Oilfield. Comprehensive analysis of geological and engineering data indicates that Halfaya Oilfield features fractured shale in the Nahr Umr Formation. Complex accidents such as wellbore collapse and sticking emerged frequently in this formation. Tests and theoretical analysis revealed that wellbore instability in the Halfaya Oilfield was influenced by chemical effect of fractured shale and the formation water with high ionic concentration. The influence of three types of drilling fluids on the rock mechanical properties of Nahr Umr Shale is tested, and time-dependent collapse pressure is calculated. Finally, we put forward engineering countermeasures for safety drilling in Halfaya Oilfield and point out that increasing the ionic concentration and improving the sealing capacity of the drilling fluid are the way to keep the wellbore stable.

Appraisal of transport and deformation in shale reservoirs using natural noble gas tracers

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

Heath, Jason E.; Kuhlman, Kristopher L.; Robinson, David G.

2015-09-01

This report presents efforts to develop the use of in situ naturally-occurring noble gas tracers to evaluate transport mechanisms and deformation in shale hydrocarbon reservoirs. Noble gases are promising as shale reservoir diagnostic tools due to their sensitivity of transport to: shale pore structure; phase partitioning between groundwater, liquid, and gaseous hydrocarbons; and deformation from hydraulic fracturing. Approximately 1.5-year time-series of wellhead fluid samples were collected from two hydraulically-fractured wells. The noble gas compositions and isotopes suggest a strong signature of atmospheric contribution to the noble gases that mix with deep, old reservoir fluids. Complex mixing and transport of fracturingmore » fluid and reservoir fluids occurs during production. Real-time laboratory measurements were performed on triaxially-deforming shale samples to link deformation behavior, transport, and gas tracer signatures. Finally, we present improved methods for production forecasts that borrow statistical strength from production data of nearby wells to reduce uncertainty in the forecasts.« less

Numerical Simulation of Potential Groundwater Contaminant Pathways from Hydraulically Fractured Oil Shale in the Nevada Basin and Range Province

NASA Astrophysics Data System (ADS)

Rybarski, S.; Pohll, G.; Pohlmann, K.; Plume, R.

2014-12-01

In recent years, hydraulic fracturing (fracking) has become an increasingly popular method for extraction of oil and natural gas from tight formations. Concerns have been raised over a number of environmental risks associated with fracking, including contamination of groundwater by fracking fluids, upwelling of deep subsurface brines, and methane migration. Given the potentially long time scale for contaminant transport associated with hydraulic fracturing, numerical modeling remains the best practice for risk assessment. Oil shale in the Humboldt basin of northeastern Nevada has now become a target for hydraulic fracturing operations. Analysis of regional and shallow groundwater flow is used to assess several potential migration pathways specific to the geology and hydrogeology of this basin. The model domain in all simulations is defined by the geologic structure of the basin as determined by deep oil and gas well bores and formation outcrops. Vertical transport of gaseous methane along a density gradient is simulated in TOUGH2, while fluid transport along faults and/or hydraulic fractures and lateral flow through more permeable units adjacent to the targeted shale are modeled in FEFLOW. Sensitivity analysis considers basin, fault, and hydraulic fracturing parameters, and results highlight key processes that control fracking fluid and methane migration and time scales under which it might occur.

Bacterial communities associated with hydraulic fracturing fluids in thermogenic natural gas wells in North Central Texas, USA.

PubMed

Struchtemeyer, Christopher G; Elshahed, Mostafa S

2012-07-01

Hydraulic fracturing is used to increase the permeability of shale gas formations and involves pumping large volumes of fluids into these formations. A portion of the frac fluid remains in the formation after the fracturing process is complete, which could potentially contribute to deleterious microbially induced processes in natural gas wells. Here, we report on the geochemical and microbiological properties of frac and flowback waters from two newly drilled natural gas wells in the Barnett Shale in North Central Texas. Most probable number studies showed that biocide treatments did not kill all the bacteria in the fracturing fluids. Pyrosequencing-based 16S rRNA diversity analyses indicated that the microbial communities in the flowback waters were less diverse and completely distinct from the communities in frac waters. These differences in frac and flowback water communities appeared to reflect changes in the geochemistry of fracturing fluids that occurred during the frac process. The flowback communities also appeared well adapted to survive biocide treatments and the anoxic conditions and high temperatures encountered in the Barnett Shale. © 2011 Federation of European Microbiological Societies. Published by Blackwell Publishing Ltd. All rights reserved.

Integrating stimulation practices with geo-mechanical properties in liquid-rich plays of Eagle Ford Shale

NASA Astrophysics Data System (ADS)

Yusuf, Ahmed

Many of the techniques for hydraulically fracturing design were attempted in the liquid-rich Eagle Ford developments. This study shows why different results were observed due to the variation of geomechanical stresses of the rock across a play and related reservoir properties. An optimum treatment for a liquids-rich objective is much different than that for a gas shale due primarily to the multiphase flow and higher viscosities encountered. This study presents a new treatment workflow for liquids-rich window of Eagle Ford Shale. Review and integration of data from multiple sets across the play are used as input to a 3D hydraulic fracture simulator to model key fracture parameters which control production enhancement. These results are then used within a production analysis and forecast, well optimization, and economic model to compare treatment designs with the best placement of proppant to deliver both high initial production and long term ultimate recoveries. A key focus for this workflow is to maximize proppant transport to achieve a continuous - optimum conductive - fracture half length. Often, due to the complexity of unconventional deposition, it is difficult to maintain complete connectivity of a proppant pack back to the wellbore. As a result, much of the potential of the fracture network is lost. Understanding the interaction of a hydraulic fracture and the rock fabric helps with designing this behavior to achieve the best results. These results are used to determine optimum well spacing to effectively develop within a selected reservoir acreage. Currently, numerous wells exist with over two years of production history in much of the Eagle Ford shale formation. Results from this study are used to compare values from field production to demonstrate the importance of employing a diligent workflow in integrating reservoir and operational parameters to the fracture design. A proper understanding and application of hydraulic fracturing modeling is achieved using the methodology presented in this study.

Characterization of the Marcellus Shale based on computer-assisted correlation of wireline logs in Virginia and West Virginia

USGS Publications Warehouse

Enomoto, Catherine B.; Olea, Ricardo A.; Coleman, James L.

2014-01-01

The Middle Devonian Marcellus Shale in the Appalachian basin extends from central Ohio on the west to eastern New York on the east, and from north-central New York on the north to northern Tennessee on the south. Its thickness ranges from 0 feet (ft) where it pinches out to the west to as much as 700 ft in its eastern extent. Within the Broadtop synclinorium, the thickness of the Marcellus Shale ranges from 250 to 565 ft. Although stratigraphic complexities have been documented, a significant range in thickness most likely is because of tectonic thickening from folds and thrust faults. Outcrop studies in the Valley and Ridge and Appalachian Plateaus provinces illustrate the challenges of interpreting the relation of third-order faults, folds, and “disturbed” zones to the regional tectonic framework. Recent field work within the Valley and Ridge province determined that significant faulting and intraformational deformation are present within the Marcellus Shale at the outcrop scale. In an attempt to determine if this scale of deformation is detectable with conventional wireline logs, petrophysical properties (primarily mineralogy and porosity) were measured by interpretation of gamma-ray and bulk-density logs. The results of performing a statistical correlation of wireline logs from nine wells indicated that there are discontinuities within the Millboro Shale (undifferentiated Marcellus Shale and Mahantango Formation) where there are significant thickness differences between wells. Also, some intervals likely contain mineralogy that makes these zones more prone to layer-shortening cleavage duplexes. The Correlator program proved to be a useful tool in a region of contractional deformation.

The Timan-Pechora Basin province of northwest Arctic Russia; Domanik, Paleozoic total petroleum system

USGS Publications Warehouse

Lindquist, Sandra J.

1999-01-01

The Domanik-Paleozoic oil-prone total petroleum system covers most of the Timan-Pechora Basin Province of northwestern Arctic Russia. It contains nearly 20 BBOE ultimate recoverable reserves (66% oil). West of the province is the early Precambrian Eastern European craton margin. The province itself was the site of periodic Paleozoic tectonic events, culminating with the Hercynian Uralian orogeny along its eastern border. The stratigraphic record is dominated by Paleozoic platform and shelf-edge carbonates succeeded by Upper Permian to Triassic molasse siliciclastics that are locally present in depressions. Upper Devonian (Frasnian), deep marine shale and limestone source rocks ? with typically 5 wt % total organic carbon ? by middle Mesozoic time had generated hydrocarbons that migrated into reservoirs ranging in age from Ordovician to Triassic but most focused in Devonian and Permian rocks. Carboniferous structural inversions of old aulacogen borders, and Hercynian (Permian) to Early Cimmerian (Late Triassic to Early Jurassic) orogenic compression not only impacted depositional patterns, but also created and subsequently modified numerous structural traps within the province.

Fluid driven fracture mechanics in highly anisotropic shale: a laboratory study with application to hydraulic fracturing

NASA Astrophysics Data System (ADS)

Gehne, Stephan; Benson, Philip; Koor, Nick; Enfield, Mark

2017-04-01

The finding of considerable volumes of hydrocarbon resources within tight sedimentary rock formations in the UK led to focused attention on the fundamental fracture properties of low permeability rock types and hydraulic fracturing. Despite much research in these fields, there remains a scarcity of available experimental data concerning the fracture mechanics of fluid driven fracturing and the fracture properties of anisotropic, low permeability rock types. In this study, hydraulic fracturing is simulated in a controlled laboratory environment to track fracture nucleation (location) and propagation (velocity) in space and time and assess how environmental factors and rock properties influence the fracture process and the developing fracture network. Here we report data on employing fluid overpressure to generate a permeable network of micro tensile fractures in a highly anisotropic shale ( 50% P-wave velocity anisotropy). Experiments are carried out in a triaxial deformation apparatus using cylindrical samples. The bedding planes are orientated either parallel or normal to the major principal stress direction (σ1). A newly developed technique, using a steel guide arrangement to direct pressurised fluid into a sealed section of an axially drilled conduit, allows the pore fluid to contact the rock directly and to initiate tensile fractures from the pre-defined zone inside the sample. Acoustic Emission location is used to record and map the nucleation and development of the micro-fracture network. Indirect tensile strength measurements at atmospheric pressure show a high tensile strength anisotropy ( 60%) of the shale. Depending on the relative bedding orientation within the stress field, we find that fluid induced fractures in the sample propagate in two of the three principal fracture orientations: Divider and Short-Transverse. The fracture progresses parallel to the bedding plane (Short-Transverse orientation) if the bedding plane is aligned (parallel) with the direction of σ1. Conversely, the crack plane develops perpendicular to the bedding plane, if the bedding plane is orientated normal to σ1. Fracture initiation pressures are higher in the Divider orientation ( 24MPa) than in the Short-Transverse orientation ( 14MPa) showing a tensile strength anisotropy ( 42%) comparable to ambient tensile strength results. We then use X-Ray Computed Tomography (CT) 3D-images to evaluate the evolved fracture network in terms of fracture pattern, aperture and post-test water permeability. For both fracture orientations, very fine, axial fractures evolve over the entire length of the sample. For the fracturing in the Divider orientation, it has been observed, that in some cases, secondary fractures are branching of the main fracture. Test data from fluid driven fracturing experiments suggest that fracture pattern, fracture propagation trajectories and fracturing fluid pressure (initiation and propagation pressure) are predominantly controlled by the interaction between the anisotropic mechanical properties of the shale and the anisotropic stress environment. The orientation of inherent rock anisotropy relative to the principal stress directions seems to be the main control on fracture orientation and required fracturing pressure.

Thermodynamically consistent model of brittle oil shales under overpressure

NASA Astrophysics Data System (ADS)

Izvekov, Oleg

2016-04-01

The concept of dual porosity is a common way for simulation of oil shale production. In the frame of this concept the porous fractured media is considered as superposition of two permeable continua with mass exchange. As a rule the concept doesn't take into account such as the well-known phenomenon as slip along natural fractures, overpressure in low permeability matrix and so on. Overpressure can lead to development of secondary fractures in low permeability matrix in the process of drilling and pressure reduction during production. In this work a new thermodynamically consistent model which generalizes the model of dual porosity is proposed. Particularities of the model are as follows. The set of natural fractures is considered as permeable continuum. Damage mechanics is applied to simulation of secondary fractures development in low permeability matrix. Slip along natural fractures is simulated in the frame of plasticity theory with Drucker-Prager criterion.

Structure, Mechanics and Flow Properties of Fractured Shale: Core-Scale Experimentation and In-situ Imaging

NASA Astrophysics Data System (ADS)

Abdelmalek, B. F.; Karpyn, Z.; Liu, S.

2014-12-01

Over the last several years, hydrocarbon exploitation and development in North America has been heavily centered on shale gas plays. However, the physical attributes of shales and their manifestation on transport properties and storage capacity remain poorly understood. Therefore, more experimentally based data are needed to fill the gaps in understanding both transport and storage of fluids in shale. The proposed work includes installation and testing of an experimental system which is capable of monitoring the dynamic evolution of shale core permeability under variable loading conditions and in coordination with X-ray microCT imaging. The goal of this study is to better understand and quantify fluid flow patterns and associated transport dynamics of fractured shale samples. The independent variables considered in this study are: mechanical loading and pore pressure. The mechanical response of shale core is captured for different loading paths. To best replicate the in-situ production scenario, the pore pressure is progressively depleted to mimic pressure decline. During the course of experimentation, permeability is estimated using the pulse-decay method under tri-axial stress boundary conditions. Simultaneously, X-ray microCT imaging is used with a tracer gas that is allowed to flow through the sample as an illuminating agent. In the presence of an illuminating agent, either Xenon or Krypton, the X-ray CT scanner can image fractures, global pathways and diffusional fronts in the matrix, as well as sorption sites that reflect heterogeneities in the sample and localized deformation. Anticipated results from these experiments will help quantify permeability evolution as a function of different loading conditions and pore pressure depletion. Also, the X-ray images will help visualize the change of flow patterns and the intensity of sorption as a function of mechanical loading and pore pressure.

Temporal changes in microbial ecology and geochemistry in produced water from hydraulically fractured Marcellus shale gas wells.

PubMed

Cluff, Maryam A; Hartsock, Angela; MacRae, Jean D; Carter, Kimberly; Mouser, Paula J

2014-06-03

Microorganisms play several important roles in unconventional gas recovery, from biodegradation of hydrocarbons to souring of wells and corrosion of equipment. During and after the hydraulic fracturing process, microorganisms are subjected to harsh physicochemical conditions within the kilometer-deep hydrocarbon-bearing shale, including high pressures, elevated temperatures, exposure to chemical additives and biocides, and brine-level salinities. A portion of the injected fluid returns to the surface and may be reused in other fracturing operations, a process that can enrich for certain taxa. This study tracked microbial community dynamics using pyrotag sequencing of 16S rRNA genes in water samples from three hydraulically fractured Marcellus shale wells in Pennsylvania, USA over a 328-day period. There was a reduction in microbial richness and diversity after fracturing, with the lowest diversity at 49 days. Thirty-one taxa dominated injected, flowback, and produced water communities, which took on distinct signatures as injected carbon and electron acceptors were attenuated within the shale. The majority (>90%) of the community in flowback and produced fluids was related to halotolerant bacteria associated with fermentation, hydrocarbon oxidation, and sulfur-cycling metabolisms, including heterotrophic genera Halolactibacillus, Vibrio, Marinobacter, Halanaerobium, and Halomonas, and autotrophs belonging to Arcobacter. Sequences related to halotolerant methanogenic genera Methanohalophilus and Methanolobus were detected at low abundance (<2%) in produced waters several months after hydraulic fracturing. Five taxa were strong indicators of later produced fluids. These results provide insight into the temporal trajectory of subsurface microbial communities after "fracking" and have important implications for the enrichment of microbes potentially detrimental to well infrastructure and natural gas fouling during this process.

Bedrock-surface altitude in the midwestern basins and arches region of Indiana, Ohio, Michigan, and Illinois

USGS Publications Warehouse

Bunner, Danny W.

1993-01-01

The Midwestern Basins and Arches Regional Aquifer-Systems Analysis (RASA) is one of 28 projects that were identified by Congress in 1978, after a period of severe drought, to be studied by the U.S. Geological Survey (Sun, 1984).  The Midwestern Basins and Arches RASA study area in parts of Indiana, Ohio, Michigan, and Illinois is defined by either the limestone-shale contact of rocks of Devonian age or by the contact of the land with surface-water bodies (fig. 1).

Characterization of Radium and Radon Isotopes in Hydraulic Fracturing Flowback Fluid and Gas from the Marcellus Shale

NASA Astrophysics Data System (ADS)

Bardsley, A.

2015-12-01

High volume hydraulic fracturing of unconventional deposits has expanded rapidly over the past decade in the US, with much attention focused on the Marcellus Shale gas reservoir in the northeastern US. We use naturally occurring radium isotopes and 222Rn to explore changes in formation characteristics as a result of hydraulic fracturing. Gas and produced waters were analyzed from time series samples collected soon after hydraulic fracturing at three Marcellus Shale well sites in the Appalachian Basin, USA. Analyses of δ18O, Cl- , and 226Ra in flowback fluid are consistent with two end member mixing between injected slick water and formation brine. All three tracers indicate that the ratio of injected water to formation brine declines with time across both time series. Cl- concentration (max ~1.5-2.2 M) and 226Ra activity (max ~165-250 Bq/Kg) in flowback fluid are comparable at all three sites. There are differences evident in the stable isotopic composition (δ18O & δD) of injected slick water across the three sites, but all appear to mix with formation brine of similar isotopic composition. On a plot of water isotopes, δ18O in formation brine-dominated fluid is enriched by ~3-4 permille relative to the Global Meteoric Water Line, indicating oxygen exchange with shale. The ratio of 223Ra/226Ra and 228Ra/226Ra in produced waters is quite low relative to shale samples analyzed. This indicates that most of the 226Ra in the formation brine must be sourced from shale weathering or dissolution rather than emanation due to alpha recoil from the rock surface. During the first week of flowback, ratios of short lived isotopes 223Ra and 224Ra to longer lived radium isotopes change modestly, suggesting rock surface area per unit of produced water volume did not change substantially. For one well, longer term gas samples were collected. The 222Rn/methane ratio in produced gas from this site declines with time and may represent a decrease in the brine to gas ratio in the reservoir over the course of six months after initial fracturing. Naturally occurring radium and radon isotopes show promise in elucidating sub-surface dynamics following hydraulic fracturing plays.

The New Albany shale in Illinois: Emerging play or prolific source

USGS Publications Warehouse

Crockett, Joan; Morse, David E.

2010-01-01

The New Albany shale (Upper Devonian) in the Illinois basin is the primary hydrocarbon source rock for the basins nearly 4 billion bbl of oil production to date. The gas play is well-established in Indiana and Western Kentucky. One in-situ oil producing well was reported in a multiply competed well in the New Albany at Johnsonville field in Wayne County, Illinois. The Illinois gas and oil wells at Russellville, in Lawrence County are closely associated with the 0.6% reflectance contour, which suggests a higher level of thermal maturity in this area. Today, only one field, Russellville in eastern Lawrence County has established commercial production in the Ness Albany in Illinois. Two wildcat wells with gas shows were drilled in recent years in southern Saline County, where the New Albany is relatively deeply buried and close to faults associated with the Fluorspar District.

Water Resources Management for Shale Energy Development

NASA Astrophysics Data System (ADS)

Yoxtheimer, D.

2015-12-01

The increase in the exploration and extraction of hydrocarbons, especially natural gas, from shale formations has been facilitated by advents in horizontal drilling and hydraulic fracturing technologies. Shale energy resources are very promising as an abundant energy source, though environmental challenges exist with their development, including potential adverse impacts to water quality. The well drilling and construction process itself has the potential to impact groundwater quality, however if proper protocols are followed and well integrity is established then impacts such as methane migration or drilling fluids releases can be minimized. Once a shale well has been drilled and hydraulically fractured, approximately 10-50% of the volume of injected fluids (flowback fluids) may flow out of the well initially with continued generation of fluids (produced fluids) throughout the well's productive life. Produced fluid TDS concentrations often exceed 200,000 mg/L, with elevated levels of strontium (Sr), bromide (Br), sodium (Na), calcium (Ca), barium (Ba), chloride (Cl), radionuclides originating from the shale formation as well as fracturing additives. Storing, managing and properly disposisng of these fluids is critical to ensure water resources are not impacted by unintended releases. The most recent data in Pennsylvania suggests an estimated 85% of the produced fluids were being recycled for hydraulic fracturing operations, while many other states reuse less than 50% of these fluids and rely moreso on underground injection wells for disposal. Over the last few years there has been a shift to reuse more produced fluids during well fracturing operations in shale plays around the U.S., which has a combination of economic, regulatory, environmental, and technological drivers. The reuse of water is cost-competitive with sourcing of fresh water and disposal of flowback, especially when considering the costs of advanced treatment to or disposal well injection and lessens the use of fresh water and disposal needs thus is a major innovation for the industry. Proper water resource managment techniques from the begining of drilling through production are critical to ensure the energy necessary for society is produced while also protecting the environment.

Detachment of particulate iron sulfide during shale-water interaction

NASA Astrophysics Data System (ADS)

Emmanuel, S.; Kreisserman, Y.

2017-12-01

Hydraulic fracturing, a commonly used technique to extract oil and gas from shales, is controversial in part because of the threat it poses to water resources. The technique involves the injection into the subsurface of large amounts of fluid, which can become contaminated by fluid-rock interaction. The dissolution of pyrite is thought to be a primary pathway for the contamination of fracturing fluids with toxic elements, such as arsenic and lead. In this study, we use direct observations with atomic force microscopy to show that the dissolution of carbonate minerals in Eagle Ford shale leads to the physical detachment of embedded pyrite grains. To simulate the way fluid interacts with a fractured shale surface, we also reacted rock samples in a flow-through cell, and used environmental scanning electron microscopy to compare the surfaces before and after interaction with water. Crucially, our results show that the flux of particulate iron sulfide into the fluid may be orders of magnitude higher than the flux of pyrite from chemical dissolution. This result suggests that mechanical detachment of pyrite grains could be the dominant mode by which arsenic and other inorganic elements are mobilized in the subsurface. Thus, during hydraulic fracturing operations and in groundwater systems containing pyrite, the transport of many toxic species may be controlled by the transport of colloidal iron sulfide particles.

Hydrogeochemical and Isotopic Indicators of Hydraulic Fracturing Flowback Fluids in Shallow Groundwater and Stream Water, derived from Dameigou Shale Gas Extraction in the Northern Qaidam Basin.

PubMed

Zheng, Zhaoxian; Zhang, Hongda; Chen, Zongyu; Li, Xufeng; Zhu, Pucheng; Cui, Xiaoshun

2017-06-06

Most of the shale gas production in northwest China is from continental shale. Identifying hydrogeochemical and isotopic indicators of toxic hydraulic fracturing flowback fluids (HFFF) has great significance in assessing the safety of drinking water from shallow groundwater and streamwater. Hydrogeochemical and isotopic data for HFFF from the Dameigou shale formations (Cl/Br ratio (1.81 × 10 -4 -6.52 × 10 -4 ), Ba/Sr (>0.2), δ 11 B (-10-1‰), and ε SW Sr (56-65, where ε SW Sr is the deviation of the 87 Sr/ 86 Sr ratio from that of seawater in parts per 10 4 )) were distinct from data for the background saline shallow groundwater and streamwater before fracturing. Mixing models indicated that inorganic elemental signatures (Br/Cl, Ba/Sr) and isotopic fingerprints (δ 11 B, ε SW Sr ) can be used to distinguish between HFFF and conventional oil-field brine in shallow groundwater and streamwater. These diagnostic indicators were applied to identify potential releases of HFFF into shallow groundwater and streamwater during fracturing, flowback and storage. The monitored time series data for shallow groundwater and streamwater exhibit no clear trends along mixing curves toward the HFFF end member, indicating that there is no detectable release occurring at present.

Extracting Hydrocarbon from Shale: An Investigation of the Factors That Influence the Decline and the Tail of the Production Curve

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

Lovell, A. E.; Srinivasan, S.; Karra, S.

Understanding physical processes that control the long-term production of hydrocarbon from shale formations is important for both predicting the yield and increasing it. In this work, we explore the processes that could control the tail of the production curve by using a discrete fracture network method to calculate the total travel time from the rock matrix to small-scale fractures to the primary hydraulic fracture network. The factors investigated include matrix diffusion, extent of the small-scale fracture zone (or tributary fracture zone/TFZ) consisting of natural, reactivated and induced fractures, and the percentage of free hydrocarbon in the primary fracture network. Individualmore » and combined parameter spaces are explored for each of these to understand the limits of these parameters as well as any systematic correlations between pairs of parameters. Although recent studies have shown that the matrix diffusion in virgin shale influences the production tail only after nearly 20 years, we demonstrate that matrix diffusion in the region of the TFZ significantly impacts production within the first year itself. Additionally, we found that the depth of TFZ fracturing region had no effect on the shape of the production curves although the total mass of the hydrocarbon produced increases with the depth. We also show that one can fit the production data using a site-specific set of parameters representing the diffusion in the TFZ, depth of the TFZ and the free hydrocarbon in the large-scale fractures.« less

Extracting Hydrocarbon from Shale: An Investigation of the Factors That Influence the Decline and the Tail of the Production Curve

DOE PAGES

Lovell, A. E.; Srinivasan, S.; Karra, S.; ...

2018-04-24

Understanding physical processes that control the long-term production of hydrocarbon from shale formations is important for both predicting the yield and increasing it. In this work, we explore the processes that could control the tail of the production curve by using a discrete fracture network method to calculate the total travel time from the rock matrix to small-scale fractures to the primary hydraulic fracture network. The factors investigated include matrix diffusion, extent of the small-scale fracture zone (or tributary fracture zone/TFZ) consisting of natural, reactivated and induced fractures, and the percentage of free hydrocarbon in the primary fracture network. Individualmore » and combined parameter spaces are explored for each of these to understand the limits of these parameters as well as any systematic correlations between pairs of parameters. Although recent studies have shown that the matrix diffusion in virgin shale influences the production tail only after nearly 20 years, we demonstrate that matrix diffusion in the region of the TFZ significantly impacts production within the first year itself. Additionally, we found that the depth of TFZ fracturing region had no effect on the shape of the production curves although the total mass of the hydrocarbon produced increases with the depth. We also show that one can fit the production data using a site-specific set of parameters representing the diffusion in the TFZ, depth of the TFZ and the free hydrocarbon in the large-scale fractures.« less

CT scanning and flow measurements of shale fractures after multiple shearing events

DOE PAGES

Crandall, Dustin; Moore, Johnathan; Gill, Magdalena; ...

2017-11-05

A shearing apparatus was used in conjunction with a Hassler-style core holder to incrementally shear fractured shale cores while maintaining various confining pressures. Computed tomography scans were performed after each shearing event, and were used to obtain information on evolving fracture geometry. Fracture transmissivity was measured after each shearing event to understand the hydrodynamic response to the evolving fracture structure. The digital fracture volumes were used to perform laminar single phase flow simulations (local cubic law with a tapered plate correction model) to qualitatively examine small scale flow path variations within the altered fractures. Fractures were found to generally increasemore » in aperture after several shear slip events, with corresponding transmissivity increases. Lower confining pressure resulted in a fracture more prone to episodic mechanical failure and sudden changes in transmissivity. Conversely, higher confining pressures resulted in a system where, after an initial setting of the fracture surfaces, changes to the fracture geometry and transmissivity occurred gradually. Flow paths within the fractures are largely controlled by the location and evolution of zero aperture locations. Lastly, a reduction in the number of primary flow pathways through the fracture, and an increase in their width, was observed during all shearing tests.« less

CT scanning and flow measurements of shale fractures after multiple shearing events

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

Crandall, Dustin; Moore, Johnathan; Gill, Magdalena

A shearing apparatus was used in conjunction with a Hassler-style core holder to incrementally shear fractured shale cores while maintaining various confining pressures. Computed tomography scans were performed after each shearing event, and were used to obtain information on evolving fracture geometry. Fracture transmissivity was measured after each shearing event to understand the hydrodynamic response to the evolving fracture structure. The digital fracture volumes were used to perform laminar single phase flow simulations (local cubic law with a tapered plate correction model) to qualitatively examine small scale flow path variations within the altered fractures. Fractures were found to generally increasemore » in aperture after several shear slip events, with corresponding transmissivity increases. Lower confining pressure resulted in a fracture more prone to episodic mechanical failure and sudden changes in transmissivity. Conversely, higher confining pressures resulted in a system where, after an initial setting of the fracture surfaces, changes to the fracture geometry and transmissivity occurred gradually. Flow paths within the fractures are largely controlled by the location and evolution of zero aperture locations. Lastly, a reduction in the number of primary flow pathways through the fracture, and an increase in their width, was observed during all shearing tests.« less

Imbibition of hydraulic fracturing fluids into partially saturated shale

NASA Astrophysics Data System (ADS)

Birdsell, Daniel T.; Rajaram, Harihar; Lackey, Greg

2015-08-01

Recent studies suggest that imbibition of hydraulic fracturing fluids into partially saturated shale is an important mechanism that restricts their migration, thus reducing the risk of groundwater contamination. We present computations of imbibition based on an exact semianalytical solution for spontaneous imbibition. These computations lead to quantitative estimates of an imbibition rate parameter (A) with units of LT-1/2 for shale, which is related to porous medium and fluid properties, and the initial water saturation. Our calculations suggest that significant fractions of injected fluid volumes (15-95%) can be imbibed in shale gas systems, whereas imbibition volumes in shale oil systems is much lower (3-27%). We present a nondimensionalization of A, which provides insights into the critical factors controlling imbibition, and facilitates the estimation of A based on readily measured porous medium and fluid properties. For a given set of medium and fluid properties, A varies by less than factors of ˜1.8 (gas nonwetting phase) and ˜3.4 (oil nonwetting phase) over the range of initial water saturations reported for the Marcellus shale (0.05-0.6). However, for higher initial water saturations, A decreases significantly. The intrinsic permeability of the shale and the viscosity of the fluids are the most important properties controlling the imbibition rate.

Potential water resource impacts of hydraulic fracturing from unconventional oil production in the Bakken shale.

PubMed

Shrestha, Namita; Chilkoor, Govinda; Wilder, Joseph; Gadhamshetty, Venkataramana; Stone, James J

2017-01-01

Modern drilling techniques, notably horizontal drilling and hydraulic fracturing, have enabled unconventional oil production (UOP) from the previously inaccessible Bakken Shale Formation located throughout Montana, North Dakota (ND) and the Canadian province of Saskatchewan. The majority of UOP from the Bakken shale occurs in ND, strengthening its oil industry and businesses, job market, and its gross domestic product. However, similar to UOP from other low-permeability shales, UOP from the Bakken shale can result in environmental and human health effects. For example, UOP from the ND Bakken shale generates a voluminous amount of saline wastewater including produced and flowback water that are characterized by unusual levels of total dissolved solids (350 g/L) and elevated levels of toxic and radioactive substances. Currently, 95% of the saline wastewater is piped or trucked onsite prior to disposal into Class II injection wells. Oil and gas wastewater (OGW) spills that occur during transport to injection sites can potentially result in drinking water resource contamination. This study presents a critical review of potential water resource impacts due to deterministic (freshwater withdrawals and produced water management) and probabilistic events (spills due to leaking pipelines and truck accidents) related to UOP from the Bakken shale in ND. Copyright © 2016 Elsevier Ltd. All rights reserved.

The Frasnian-Famennian boundary (Upper Devonian) within the Hanover-Dunkirk transition, northern Appalachian basin, western New York state

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

Over, D.J.

In western New York State interbedded pyritic silty green and dark grey shales and siltstone of the Hanover Member, Java Formation, West Falls Group, are overlain by thick pyritic dark grey-black shale of the Dunkirk Member of the Canadaway formation. The dark shales in the upper Hanover and Dunkirk contain a diverse and well preserved conodont fauna which allows precise placement of the Frasnian-Famennian boundary at several described sections. At Pt. Gratiot, in far western New York State, the contact between the Hanover and Dunkirk is disconformable. The Frasnian-Famennian boundary is marked by a pyritic lag deposit at the basemore » of the Dunkirk which contains Palmatolepis triangularis and Pa. subperlobata. The underlying upper Hanover is characterized by Pa. bogartensis , Pa. cf. Pa. rhenana, Pa. winchelli, and Ancyrognathus (asymmetricus/calvini) Eastward, in the direction of the paleo-source area, the Frasnian-Famennian boundary is within the upper Hanover Member. At Irish Gulf the boundary is recognized within a 10 cm thick laminated pyritic dark grey shale bed 3.0 m below the base of the Dunkirk. Palmatolepis triangularis and Pa. subperlobata occur below a conodont-rich lag layer in the upper 2 cm of the bed. Palmatolepis bogartensis , Pa. cf. Pa. rhenana, Ancyrodella curvata, and Icriodus alternatus occur in the underlying 8 cm. Palmatolepis triangularis and Pa. winchelli occur in an underlying dark shale bed separated from the boundary bed by a hummocky cross-bedded siltstone layer.« less

Shale gas development: a smart regulation framework.

PubMed

Konschnik, Katherine E; Boling, Mark K

2014-01-01

Advances in directional drilling and hydraulic fracturing have sparked a natural gas boom from shale formations in the United States. Regulators face a rapidly changing industry comprised of hundreds of players, operating tens of thousands of wells across 30 states. They are often challenged to respond by budget cuts, a brain drain to industry, regulations designed for conventional gas developments, insufficient information, and deeply polarized debates about hydraulic fracturing and its regulation. As a result, shale gas governance remains a halting patchwork of rules, undermining opportunities to effectively characterize and mitigate development risk. The situation is dynamic, with research and incremental regulatory advances underway. Into this mix, we offer the CO/RE framework--characterization of risk, optimization of mitigation strategies, regulation, and enforcement--to design tailored governance strategies. We then apply CO/RE to three types of shale gas risks, to illustrate its potential utility to regulators.

Impact of organics and carbonates on the oxidation and precipitation of iron during hydraulic fracturing of shale

DOE PAGES

Jew, Adam D.; Dustin, Megan K.; Harrison, Anna L.; ...

2017-03-06

Hydraulic fracturing of unconventional hydrocarbon reservoirs is critical to the United States energy portfolio; however, hydrocarbon production from newly fractured wells generally declines rapidly over the initial months of production. One possible reason for this decrease, especially over time scales of several months, is the mineralization and clogging of microfracture networks and pores proximal to propped fractures. One important but relatively unexplored class of reactions that could contribute to these problems is oxidation of Fe(II) derived from Fe(II)-bearing phases (primarily pyrite, siderite, and Fe(II) bound directly to organic matter) by the oxic fracture fluid and subsequent precipitation of Fe(III)-(oxy)hydroxides. Here,more » the extent to which such reactions occur and their rates, mineral products, and physical locations within shale pore spaces are unknown.« less

Impact of organics and carbonates on the oxidation and precipitation of iron during hydraulic fracturing of shale

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

Jew, Adam D.; Dustin, Megan K.; Harrison, Anna L.

Hydraulic fracturing of unconventional hydrocarbon reservoirs is critical to the United States energy portfolio; however, hydrocarbon production from newly fractured wells generally declines rapidly over the initial months of production. One possible reason for this decrease, especially over time scales of several months, is the mineralization and clogging of microfracture networks and pores proximal to propped fractures. One important but relatively unexplored class of reactions that could contribute to these problems is oxidation of Fe(II) derived from Fe(II)-bearing phases (primarily pyrite, siderite, and Fe(II) bound directly to organic matter) by the oxic fracture fluid and subsequent precipitation of Fe(III)-(oxy)hydroxides. Here,more » the extent to which such reactions occur and their rates, mineral products, and physical locations within shale pore spaces are unknown.« less

The energy-water nexus: Potential groundwater-quality degradation associated with petroleum production from shale and tight reservoirs

NASA Astrophysics Data System (ADS)

Kharaka, Y. K.; Gans, K. D.; Conaway, C. H.; Thordsen, J. J.; Thomas, B.

2013-12-01

Oil and natural gas are the main sources of primary energy in the USA, providing 63% of total energy consumption in 2011. Production of petroleum from shale and very low permeability reservoirs has increased substantially due to recent developments in deep horizontal drilling, downhole telemetry and massive multi-stage hydraulic fracturing using ';slick water'. Production of natural gas from shale has increased rapidly, from 0.4 Tcf in 2000, to 6.8 Tcf in 2011, almost 30% of gas production in USA; it is projected to increase to account for 49% of USA gas in 2035. U.S. crude oil production has also increased from 5.0 Mbpd in 2008 to 5.6 Mbpd in 2011; oil from unconventional sources in 2035 is projected to be 0.7 to 2.8 Mbpd, accounting for 36% of domestic production. Hydraulic fracturing is carried out by injecting large volumes (~10,000-50,000 m3/well) of fresh water with added proppant, and organic and inorganic chemicals at high fluid pressures. Approximately 500-5,000 m3/well of water are also used for drilling the wells. The total water used for shale gas wells is relatively low compared to the consumptive total water usage in wet regions (e.g. 0.06% of water for the Marcellus Shale); but is much higher in arid regions (e.g. 0.8% for the Haynesville Shale) where water used could be a significant constraint for gas development because its use could impact the available water supply. Fluid pressure is lowered following hydraulic fracturing, causing the ';flowback' brine, which is a mixture of fracturing fluid and formation water, to return to the surface through the casing. During the 2-3 weeks of the ';flowback' period for a Marcellus Shale well, 10-50% of the fracturing fluid returns to the surface, initially at high rates (~1,000 m3/day), decreasing finally to ~ 50 m3/day. The salinity of the ';flowback' water is initially moderate (45,000 mg/L TDS), reflecting the composition of the fracturing water, and increasing to ~200,000 mg/L TDS. Production of natural gas and produced water follows at ~2-8 m3/day per well. The produced waters from Marcellus Shale, Haynesville and the Bakken are Na-Ca-Cl brines with extremely high salinities (≥200,000 mg/L TDS), high NORMs (up to 10,000 picocuries/L for total Ra) and Rn activities, and toxic inorganic and organic compounds. Also, companies add a large number of disclosed and undisclosed chemicals, including KCl, acids, bactericides, biocides, and corrosion and scale inhibitors to the fracturing fluids to improve production. Potential contamination of groundwater by the natural and added chemicals and NORMs in flow back and produced waters is the major concern, and some communities are also concerned about the possibility of induced seismicity. These concerns may be warranted as results of groundwater investigations indicated that private water wells in parts of Pennsylvania and New York showed an association between shale gas operations and methane contamination of drinking water. However, results of detailed chemical and isotopic compositions of shallow groundwater indicated no contamination from the Na-Cl type Fayetteville 'flowback'/produced waters with salinities of ~20,000 mg/L TDS. A major research effort is needed to minimize potential environmental impacts, especially groundwater contamination, when producing these important new sources of energy.

Experimental investigation on the fracture behaviour of black shale by acoustic emission monitoring and CT image analysis during uniaxial compression

NASA Astrophysics Data System (ADS)

Wang, Y.; Li, C. H.; Hu, Y. Z.

2018-04-01

Plenty of mechanical experiments have been done to investigate the deformation and failure characteristics of shale; however, the anisotropic failure mechanism has not been well studied. Here, laboratory Uniaxial Compressive Strength tests on cylindrical shale samples obtained by drilling at different inclinations to bedding plane were performed. The failure behaviours of the shale samples were studied by real-time acoustic emission (AE) monitoring and post-test X-ray computer tomography (CT) analysis. The experimental results suggest that the pronounced bedding planes of shale have a great influence on the mechanical properties and AE patterns. The AE counts and AE cumulative energy release curves clearly demonstrate different morphology, and the `U'-shaped curve relationship between the AE counts, AE cumulative energy release and bedding inclination was first documented. The post-test CT image analysis shows the crack patterns via 2-D image reconstructions, an index of stimulated fracture density is defined to represent the anisotropic failure mode of shale. What is more, the most striking finding is that the AE monitoring results are in good agreement with the CT analysis. The structural difference in the shale sample is the controlling factor resulting in the anisotropy of AE patterns. The pronounced bedding structure in the shale formation results in an anisotropy of elasticity, strength and AE information from which the changes in strength dominate the entire failure pattern of the shale samples.

Middle Devonian to Early Carboniferous event stratigraphy of Devils Gate and Northern Antelope Range sections, Nevada, U.S.A

USGS Publications Warehouse

Sandberg, C.A.; Morrow, J.R.; Poole, F.G.; Ziegler, W.

2003-01-01

The classic type section of the Devils Gate Limestone at Devils Gate Pass is situated on the eastern slope of a proto-Antler forebulge that resulted from convergence of the west side of the North American continent with an ocean plate. The original Late Devonian forebulge, the site of which is now located between Devils Gate Pass and the Northern Antelope Range, separated the continental-rise to deep-slope Woodruff basin on the west from the backbulge Pilot basin on the east. Two connections between these basins are recorded by deeper water siltstone beds at Devils Gate; the older one is the lower tongue of the Woodruff Formation, which forms the basal unit of the upper member of the type Devils Gate, and the upper one is the overlying, thin lower member of the Pilot Shale. The forebulge and the backbulge Pilot basin originated during the middle Frasnian (early Late Devonian) Early hassi Zone, shortly following the Alamo Impact within the punctata Zone in southern Nevada. Evidence of this impact is recorded by coeval and reworked shocked quartz grains in the Northern Antelope Range and possibly by a unique bypass-channel or megatsunami-uprush sandy diamictite within carbonate-platform rocks of the lower member of the type Devils Gate Limestone. Besides the Alamo Impact and three regional events, two other important global events are recorded in the Devils Gate section. The semichatovae eustatic rise, the maximum Late Devonian flooding event, coincides with the sharp lithogenetic change at the discordant boundary above the lower member of the Devils Gate Limestone. Most significantly, the Devils Gate section contains the thickest and most complete rock record in North America across the late Frasnian linguiformis Zone mass extinction event. Excellent exposures include not only the extinction shale, but also a younger. Early triangularis Zone tsunamite breccia, produced by global collapse of carbonate platforms during a shallowing event that continued into the next younger Famennian Stage. The Northern Antelope Range section is located near the top of the west side of the proto-Antler forebulge. Because of its unusual, tectonically active location, unmatched at any other Nevada localities, this section records only four regional and global events during a timespan slightly longer than that of the Devils Gate section. The global semichatovae rise and late Frasnian mass extinction event are largely masked because of the depositional complexities resulting from this location.

Dynamic compressive properties obtained from a split Hopkinson pressure bar test of Boryeong shale

NASA Astrophysics Data System (ADS)

Kang, Minju; Cho, Jung-Woo; Kim, Yang Gon; Park, Jaeyeong; Jeong, Myeong-Sik; Lee, Sunghak

2016-09-01

Dynamic compressive properties of a Boryeong shale were evaluated by using a split Hopkinson pressure bar, and were compared with those of a Hwangdeung granite which is a typical hard rock. The results indicated that the dynamic compressive loading reduced the resistance to fracture. The dynamic compressive strength was lower in the shale than in the granite, and was raised with increasing strain rate by microcracking effect as well as strain rate strengthening effect. Since the number of microcracked fragments increased with increasing strain rate in the shale having laminated weakness planes, the shale showed the better fragmentation performance than the granite at high strain rates. The effect of transversely isotropic plane on compressive strength decreased with increasing strain rate, which was desirable for increasing the fragmentation performance. Thus, the shale can be more reliably applied to industrial areas requiring good fragmentation performance as the striking speed of drilling or hydraulic fracturing machines increased. The present dynamic compressive test effectively evaluated the fragmentation performance as well as compressive strength and strain energy density by controlling the air pressure, and provided an important idea on which rock was more readily fragmented under dynamically processing conditions such as high-speed drilling and blasting.

Capillary Imbibition of Hydraulic Fracturing Fluids into Partially Saturated Shale

NASA Astrophysics Data System (ADS)

Birdsell, D.; Rajaram, H.; Lackey, G.

2015-12-01

Understanding the migration of hydraulic fracturing fluids injected into unconventional reservoirs is important to assess the risk of aquifer contamination and to optimize oil and gas production. Capillary imbibition causes fracturing fluids to flow from fractures into the rock matrix where the fluids are sequestered for geologically long periods of time. Imbibition could explain the low amount of flowback water observed in the field (5-50% of the injected volume) and reduce the chance of fracturing fluid migrating out of formation towards overlying aquifers. We present calculations of spontaneous capillary imbibition in the form of an "imbibition rate parameter" (A) based on the only known exact analytical solution for spontaneous capillary imbibition. A depends on the hydraulic and capillary properties of the reservoir rock, the initial water saturation, and the viscosities of the wetting and nonwetting fluids. Imbibed volumes can be large for a high permeability shale gas reservoir (up to 95% of the injected volume) or quite small for a low permeability shale oil reservoir (as low as 3% of the injected volume). We also present a nondimensionalization of the imbibition rate parameter, which facilitates the calculation of A and clarifies the relation of A to initial saturation, porous medium properties, and fluid properties. Over the range of initial water saturations reported for the Marcellus shale (0.05-0.6), A varies by less than factors of ~1.8 and ~3.4 for gas and oil nonwetting phases respectively. However, A decreases significantly for larger initial water saturations. A is most sensitive to the intrinsic permeability of the reservoir rock and the viscosity of the fluids.

The Architecture and Frictional Properties of Faults in Shale

NASA Astrophysics Data System (ADS)

De Paola, N.; Imber, J.; Murray, R.; Holdsworth, R.

2015-12-01

The geometry of brittle fault zones in shale rocks, as well as their frictional properties at reservoir conditions, are still poorly understood. Nevertheless, these factors may control the very low recovery factors (25% for gas and 5% for oil) obtained during fracking operations. Extensional brittle fault zones (maximum displacement < 3 m) cut exhumed oil mature black shales in the Cleveland Basin (UK). Fault cores up to 50 cm wide accommodated most of the displacement, and are defined by a stair-step geometry. Their internal architecture is characterised by four distinct fault rock domains: foliated gouges; breccias; hydraulic breccias; and a slip zone up to 20 mm thick, composed of a fine-grained black gouge. Hydraulic breccias are located within dilational jogs with aperture of up to 20 cm. Brittle fracturing and cataclastic flow are the dominant deformation mechanisms in the fault core of shale faults. Velocity-step and slide-hold-slide experiments at sub-seismic slip rates (microns/s) were performed in a rotary shear apparatus under dry, water and brine-saturated conditions, for displacements of up to 46 cm. Both the protolith shale and the slip zone black gouge display shear localization, velocity strengthening behaviour and negative healing rates, suggesting that slow, stable sliding faulting should occur within the protolith rocks and slip zone gouges. Experiments at seismic speed (1.3 m/s), performed on the same materials under dry conditions, show that after initial friction values of 0.5-0.55, friction decreases to steady-state values of 0.1-0.15 within the first 10 mm of slip. Contrastingly, water/brine saturated gouge mixtures, exhibit almost instantaneous attainment of very low steady-state sliding friction (0.1), suggesting that seismic ruptures may efficiently propagate in the slip zone of fluid-saturated shale faults. Stable sliding in faults in shale can cause slow fault/fracture propagation, affecting the rate at which new fracture areas are created and, hence, limiting oil and gas production during reservoir stimulation. However, fluid saturated conditions can favour seismic slip propagation, with fast and efficient creation of new fracture areas. These processes are very effective at dilational jogs, where fluid circulation may be enhanced, facilitating oil and gas production.

Organic and inorganic composition and microbiology of produced waters from Pennsylvania shale gas wells

USGS Publications Warehouse

Akob, Denise M.; Cozzarelli, Isabelle M.; Dunlap, Darren S.; Rowan, Elisabeth L.; Lorah, Michelle M.

2015-01-01

Hydraulically fractured shales are becoming an increasingly important source of natural gas production in the United States. This process has been known to create up to 420 gallons of produced water (PW) per day, but the volume varies depending on the formation, and the characteristics of individual hydraulic fracture. PW from hydraulic fracturing of shales are comprised of injected fracturing fluids and natural formation waters in proportions that change over time. Across the state of Pennsylvania, shale gas production is booming; therefore, it is important to assess the variability in PW chemistry and microbiology across this geographical span. We quantified the inorganic and organic chemical composition and microbial communities in PW samples from 13 shale gas wells in north central Pennsylvania. Microbial abundance was generally low (66–9400 cells/mL). Non-volatile dissolved organic carbon (NVDOC) was high (7–31 mg/L) relative to typical shallow groundwater, and the presence of organic acid anions (e.g., acetate, formate, and pyruvate) indicated microbial activity. Volatile organic compounds (VOCs) were detected in four samples (∼1 to 11.7 μg/L): benzene and toluene in the Burket sample, toluene in two Marcellus samples, and tetrachloroethylene (PCE) in one Marcellus sample. VOCs can be either naturally occurring or from industrial activity, making the source of VOCs unclear. Despite the addition of biocides during hydraulic fracturing, H2S-producing, fermenting, and methanogenic bacteria were cultured from PW samples. The presence of culturable bacteria was not associated with salinity or location; although organic compound concentrations and time in production were correlated with microbial activity. Interestingly, we found that unlike the inorganic chemistry, PW organic chemistry and microbial viability were highly variable across the 13 wells sampled, which can have important implications for the reuse and handling of these fluids

On wettability of shale rocks.

PubMed

Roshan, H; Al-Yaseri, A Z; Sarmadivaleh, M; Iglauer, S

2016-08-01

The low recovery of hydraulic fracturing fluid in unconventional shale reservoirs has been in the centre of attention from both technical and environmental perspectives in the last decade. One explanation for the loss of hydraulic fracturing fluid is fluid uptake by the shale matrix; where capillarity is the dominant process controlling this uptake. Detailed understanding of the rock wettability is thus an essential step in analysis of loss of the hydraulic fracturing fluid in shale reservoirs, especially at reservoir conditions. We therefore performed a suit of contact angle measurements on a shale sample with oil and aqueous ionic solutions, and tested the influence of different ion types (NaCl, KCl, MgCl2, CaCl2), concentrations (0.1, 0.5 and 1M), pressures (0.1, 10 and 20MPa) and temperatures (35 and 70°C). Furthermore, a physical model was developed based on the diffuse double layer theory to provide a framework for the observed experimental data. Our results show that the water contact angle for bivalent ions is larger than for monovalent ions; and that the contact angle (of both oil and different aqueous ionic solutions) increases with increase in pressure and/or temperature; these increases are more pronounced at higher ionic concentrations. Finally, the developed model correctly predicted the influence of each tested variable on contact angle. Knowing contact angle and therefore wettability, the contribution of the capillary process in terms of water uptake into shale rocks and the possible impairment of hydrocarbon production due to such uptake can be quantified. Copyright © 2016 Elsevier Inc. All rights reserved.

Microbially Induced Calcite Precipitation (MICP) - A Technology for Managing Flow and Transport in Porous and Fractured Media

NASA Astrophysics Data System (ADS)

Phillips, A. J.; Hiebert, R.; Kirksey, J.; Lauchnor, E. G.; Rothman, A.; Spangler, L.; Esposito, R.; Gerlach, R.; Cunningham, A. B.

2014-12-01

Certain microorganisms e.g., Sporosarcina pasteurii contribute enzymes that catalyze reactions which in the presence of calcium, can create saturation conditions favorable for calcium carbonate precipitation (microbially-induced calcium carbonate precipitation (MICP)). MICP can be used for a number of engineering applications including securing geologic storage of CO2 or other fluids by sealing fractures, improving wellbore integrity, and stabilizing fractured and unstable porous media. MICP treatment has the advantage of the use of small microorganisms, ~2μm, suggesting applicability to treatment of small aperture fractures not accessible to traditional treatments, for example the use of fine cement. The promotion of MICP in the subsurface is a complex reactive transport problem coupling microbial, abiotic (geochemical), geomechanical and hydrodynamic processes. In the laboratory, MICP has been demonstrated to cement together heavily fractured shale and reduce the permeability of fractures in shale and sandstone cores up to five orders of magnitude under both ambient and subsurface relevant pressure conditions (Figure 1). Most recently, a MICP fracture treatment field study was performed at a well at the Southern Company Gorgas Steam Generation Plant (Alabama) (Figure 1). The Fayetteville Sandstone at approximately 1120' below ground surface was hydraulically fractured prior to MICP treatment. After 4 days of injection of 24 calcium pulses and 6 microbial inoculations, injectivity of brine into the formation was significantly reduced. The experiment also resulted in a reduction in pressure decay which is a measure of improved wellbore integrity. These promising results suggest the potential for MICP treatment to seal fractured pathways at the field scale to improve the long-term security of geologically-stored carbon dioxide or prevent leakage of shale gas or hydraulic fracturing fluids into functional overlying aquifers, reducing environmental impacts.

Flow of Gas and Water in Hydraulically Fractured Shale Gas Reservoirs, March 28-29, 2011

EPA Pesticide Factsheets

Underground fluid flow is primarily controlled by two physical factors: hydraulic conduits and pressure gradients. Both are required, or fluids will not move. In their natural state, shale formations are very impermeable.

Modeling of fault activation and seismicity by injection directly into a fault zone associated with hydraulic fracturing of shale-gas reservoirs

DOE PAGES

Rutqvist, Jonny; Rinaldi, Antonio P.; Cappa, Frédéric; ...

2015-03-01

We conducted three-dimensional coupled fluid-flow and geomechanical modeling of fault activation and seismicity associated with hydraulic fracturing stimulation of a shale-gas reservoir. We simulated a case in which a horizontal injection well intersects a steeply dip- ping fault, with hydraulic fracturing channeled within the fault, during a 3-hour hydraulic fracturing stage. Consistent with field observations, the simulation results show that shale-gas hydraulic fracturing along faults does not likely induce seismic events that could be felt on the ground surface, but rather results in numerous small microseismic events, as well as aseismic deformations along with the fracture propagation. The calculated seismicmore » moment magnitudes ranged from about -2.0 to 0.5, except for one case assuming a very brittle fault with low residual shear strength, for which the magnitude was 2.3, an event that would likely go unnoticed or might be barely felt by humans at its epicenter. The calculated moment magnitudes showed a dependency on injection depth and fault dip. We attribute such dependency to variation in shear stress on the fault plane and associated variation in stress drop upon reactivation. Our simulations showed that at the end of the 3-hour injection, the rupture zone associated with tensile and shear failure extended to a maximum radius of about 200 m from the injection well. The results of this modeling study for steeply dipping faults at 1000 to 2500 m depth is in agreement with earlier studies and field observations showing that it is very unlikely that activation of a fault by shale-gas hydraulic fracturing at great depth (thousands of meters) could cause felt seismicity or create a new flow path (through fault rupture) that could reach shallow groundwater resources.« less

Modeling of fault activation and seismicity by injection directly into a fault zone associated with hydraulic fracturing of shale-gas reservoirs

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

Rutqvist, Jonny; Rinaldi, Antonio P.; Cappa, Frédéric

We conducted three-dimensional coupled fluid-flow and geomechanical modeling of fault activation and seismicity associated with hydraulic fracturing stimulation of a shale-gas reservoir. We simulated a case in which a horizontal injection well intersects a steeply dip- ping fault, with hydraulic fracturing channeled within the fault, during a 3-hour hydraulic fracturing stage. Consistent with field observations, the simulation results show that shale-gas hydraulic fracturing along faults does not likely induce seismic events that could be felt on the ground surface, but rather results in numerous small microseismic events, as well as aseismic deformations along with the fracture propagation. The calculated seismicmore » moment magnitudes ranged from about -2.0 to 0.5, except for one case assuming a very brittle fault with low residual shear strength, for which the magnitude was 2.3, an event that would likely go unnoticed or might be barely felt by humans at its epicenter. The calculated moment magnitudes showed a dependency on injection depth and fault dip. We attribute such dependency to variation in shear stress on the fault plane and associated variation in stress drop upon reactivation. Our simulations showed that at the end of the 3-hour injection, the rupture zone associated with tensile and shear failure extended to a maximum radius of about 200 m from the injection well. The results of this modeling study for steeply dipping faults at 1000 to 2500 m depth is in agreement with earlier studies and field observations showing that it is very unlikely that activation of a fault by shale-gas hydraulic fracturing at great depth (thousands of meters) could cause felt seismicity or create a new flow path (through fault rupture) that could reach shallow groundwater resources.« less

How Deep is the Critical Zone: A Scientific Question with Potential Impact For Decision-makers in Areas of Shale-Gas Development and Hydraulic Fracturing

NASA Astrophysics Data System (ADS)

Brantley, S. L.

2014-12-01

Citizens living in areas of shale-gas development such as the Marcellus gas play in Pennsylvania and surrounding states are cognizant of the possibility that drilling and production of natural gas -- including hydraulic fracturing -- may have environmental impacts on their water. The Critical Zone is defined as the zone from vegetation canopy to the lower limits of groundwater. This definition is nebulous in terms of the lower limit, and yet, defining the bottom of the Critical Zone is important if citizens are to embrace shale-gas development. This is because, although no peer-reviewed study has been presented that documents a case where hydraulic fracturing or formation fluids have migrated upwards from fracturing depths to drinking water resources, a few cases of such leakage have been alleged. On the other hand, many cases of methane migration into aquifers have been documented to occur and some have been attributed to shale-gas development. The Critical Zone science community has a role to play in understanding such contamination problems, how they unfold, and how they should be ameliorated. For example, one big effort of the Critical Zone science community is to promote sharing of data describing the environment. This data effort has been extended to provide data for citizens to understand water quality by a team known as the Shale Network. As scientists learn to publish data online, these efforts must also be made accessible to non-scientists. As citizens access the data, the demand for data will grow and all branches of government will eventually respond by providing more accessible data that will help the public and policy-makers make decisions.

Methane baseline concentrations and sources in shallow aquifers from the shale gas-prone region of the St. Lawrence lowlands (Quebec, Canada).

PubMed

Moritz, Anja; Hélie, Jean-Francois; Pinti, Daniele L; Larocque, Marie; Barnetche, Diogo; Retailleau, Sophie; Lefebvre, René; Gélinas, Yves

2015-04-07

Hydraulic fracturing is becoming an important technique worldwide to recover hydrocarbons from unconventional sources such as shale gas. In Quebec (Canada), the Utica Shale has been identified as having unconventional gas production potential. However, there has been a moratorium on shale gas exploration since 2010. The work reported here was aimed at defining baseline concentrations of methane in shallow aquifers of the St. Lawrence Lowlands and its sources using δ(13)C methane signatures. Since this study was performed prior to large-scale fracturing activities, it provides background data prior to the eventual exploitation of shale gas through hydraulic fracturing. Groundwater was sampled from private (n = 81), municipal (n = 34), and observation (n = 15) wells between August 2012 and May 2013. Methane was detected in 80% of the wells with an average concentration of 3.8 ± 8.8 mg/L, and a range of <0.0006 to 45.9 mg/L. Methane concentrations were linked to groundwater chemistry and distance to the major faults in the studied area. The methane δ(1)(3)C signature of 19 samples was > -50‰, indicating a potential thermogenic source. Localized areas of high methane concentrations from predominantly biogenic sources were found throughout the study area. In several samples, mixing, migration, and oxidation processes likely affected the chemical and isotopic composition of the gases, making it difficult to pinpoint their origin. Energy companies should respect a safe distance from major natural faults in the bedrock when planning the localization of hydraulic fracturation activities to minimize the risk of contaminating the surrounding groundwater since natural faults are likely to be a preferential migration pathway for methane.

Chemical Degradation of Polyacrylamide during Hydraulic Fracturing.

PubMed

Xiong, Boya; Miller, Zachary; Roman-White, Selina; Tasker, Travis; Farina, Benjamin; Piechowicz, Bethany; Burgos, William D; Joshi, Prachi; Zhu, Liang; Gorski, Christopher A; Zydney, Andrew L; Kumar, Manish

2018-01-02

Polyacrylamide (PAM) based friction reducers are a primary ingredient of slickwater hydraulic fracturing fluids. Little is known regarding the fate of these polymers under downhole conditions, which could have important environmental impacts including decisions on strategies for reuse or treatment of flowback water. The objective of this study was to evaluate the chemical degradation of high molecular weight PAM, including the effects of shale, oxygen, temperature, pressure, and salinity. Data were obtained with a slickwater fracturing fluid exposed to both a shale sample collected from a Marcellus outcrop and to Marcellus core samples at high pressures/temperatures (HPT) simulating downhole conditions. Based on size exclusion chromatography analyses, the peak molecular weight of the PAM was reduced by 2 orders of magnitude, from roughly 10 MDa to 200 kDa under typical HPT fracturing conditions. The rate of degradation was independent of pressure and salinity but increased significantly at high temperatures and in the presence of oxygen dissolved in fracturing fluids. Results were consistent with a free radical chain scission mechanism, supported by measurements of sub-μM hydroxyl radical concentrations. The shale sample adsorbed some PAM (∼30%), but importantly it catalyzed the chemical degradation of PAM, likely due to dissolution of Fe 2+ at low pH. These results provide the first evidence of radical-induced degradation of PAM under HPT hydraulic fracturing conditions without additional oxidative breaker.

Paleozoic Hydrocarbon-Seep Limestones

NASA Astrophysics Data System (ADS)

Peckmann, J.

2007-12-01

To date, five Paleozoic hydrocarbon-seep limestones have been recognized based on carbonate fabrics, associated fauna, and stable carbon isotopes. These are the Middle Devonian Hollard Mound from the Antiatlas of Morocco [1], Late Devonian limestone lenses with the dimerelloid brachiopod Dzieduszyckia from the Western Meseta of Morocco [2], Middle Mississippian limestones with the dimerelloid brachiopod Ibergirhynchia from the Harz Mountains of Germany [3], Early Pennsylvanian limestones from the Tantes Mound in the High Pyrenees of France [4], and Late Pennsylvanian limestone lenses from the Ganigobis Shale Member of southern Namibia [5]. Among these examples, the composition of seepage fluids varied substantially as inferred from delta C-13 values of early diagenetic carbonate phases. Delta C-13 values as low as -50 per mil from the Tantes Mound and -51 per mil from the Ganigobis limestones reveal seepage of biogenic methane, whereas values of -12 per mil from limestones with Dzieduszyckia associated with abundant pyrobitumen agree with oil seepage. Intermediate delta C-13 values of carbonate cements from the Hollard Mound and Ibergirhynchia deposits probably reflect seepage of thermogenic methane. It is presently very difficult to assess the faunal evolution at seeps in the Paleozoic based on the limited number of examples. Two of the known seeps were typified by extremely abundant rhynchonellide brachiopods of the superfamily Dimerelloidea. Bivalve mollusks and tubeworms were abundant at two of the known Paleozoic seep sites; one was dominated by bivalve mollusks (Hollard Mound, Middle Devonian), another was dominated by tubeworms (Ganigobis Shale Member, Late Pennsylvanian). The tubeworms from these two deposits are interpreted to represent vestimentiferan worms, based on studies of the taphonomy of modern vestimentiferans. However, this interpretation is in conflict with the estimated evolutionary age of vestimentiferans based on molecular clock methods, which suggest a maximal age of 126 million years for this group. 1. Peckmann et al. (1999) Facies 40, 281. 2. Peckmann et al. (2007) Palaios 22, 114. 3. Peckmann et al. (2001) Geology 29, 271. 4. Buggisch and Krumm (2005) Facies 51, 566. 5. Himmler et al. (submitted) Palaeogeogr., Palaeoclimatol., Palaeoecol.

Variations in petrophysical properties of shales along a stratigraphic section in the Whitby mudstone (UK)

NASA Astrophysics Data System (ADS)

Barnhoorn, Auke; Houben, Maartje; Lie-A-Fat, Joella; Ravestein, Thomas; Drury, Martyn

2015-04-01

In unconventional tough gas reservoirs (e.g. tight sandstones or shales) the presence of fractures, either naturally formed or hydraulically induced, is almost always a prerequisite for hydrocarbon productivity to be economically viable. One of the formations classified so far as a potential interesting formation for shale gas exploration in the Netherlands is the Lower Jurassic Posidonia Shale Formation (PSF). However data of the Posidonia Shale Formation is scarce so far and samples are hard to come by, especially on the variability and heterogeneity of the petrophysical parameters of this shale little is known. Therefore research and sample collection is conducted on a time and depositional analogue of the PSF: the Whitby Mudstone Formation (WMF) in the United Kingdom. A large number of samples along a ~7m stratigraphic section of the Whitby Mudstone Formation have been collected and analysed. Standard petrophysical properties such as porosity and matrix densities are quantified for a number of samples throughout the section, as well as mineral composition analysis based on XRD/XRF and SEM analyses. Seismic velocity measurements are also conducted at multiple heights in the section and in multiple directions to elaborate on anisotropy of the material. Attenuation anisotropy is incorporated as well as Thomsen's parameters combined with elastic parameters, e.g. Young's modulus and Poisson's ratio, to quantify the elastic anisotropy. Furthermore rock mechanical experiments are conducted to determine the elastic constants, rock strength, fracture characteristics, brittleness index, fraccability and rock mechanical anisotropy across the stratigraphic section of the Whitby mudstone formation. Results show that the WMF is highly anisotropic and it exhibits an anisotropy on the large limit of anisotropy reported for US gas shales. The high anisotropy of the Whitby shales has an even larger control on the formation of the fracture network. Furthermore, most petrophysical properties are highly variable. They vary per sample, but even within a sample on a mm-scale, large variations in e.g. the porosity occur. These relatively large variations influence the potential for future shale gas exploration for these Lower Jurassic shales in northern Europe and need to be quantified in detail beforehand. Compositional analyses and rock deformation experiments on the first samples indicate relatively low brittleness indices for the Whitby shale, but variation of these parameters within the stratigraphy are present. All petrophysical analyses combined will provide a complete assessment of the potential for shale gas exploration of these Lower Jurassic shales.

Stratigraphy and facies development of the marine Late Devonian near the Boulongour Reservoir, northwest Xinjiang, China

NASA Astrophysics Data System (ADS)

Suttner, Thomas J.; Kido, Erika; Chen, Xiuqin; Mawson, Ruth; Waters, Johnny A.; Frýda, Jiří; Mathieson, David; Molloy, Peter D.; Pickett, John; Webster, Gary D.; Frýdová, Barbora

2014-02-01

Late Devonian to Early Carboniferous stratigraphic units within the 'Zhulumute' Formation, Hongguleleng Formation (stratotype), 'Hebukehe' Formation and the Heishantou Formation near the Boulongour Reservoir in northwestern Xinjiang are fossil-rich. The Hongguleleng and 'Hebukehe' formations are biostratigraphically well constrained by microfossils from the latest Frasnian linguiformis to mid-Famennian trachytera conodont biozones. The Hongguleleng Formation (96.8 m) is characterized by bioclastic argillaceous limestones and marls (the dominant facies) intercalated with green spiculitic calcareous shales. It yields abundant and highly diverse faunas of bryozoans, brachiopods and crinoids with subordinate solitary rugose corals, ostracods, trilobites, conodonts and other fish teeth. The succeeding 'Hebukehe' Formation (95.7 m) consists of siltstones, mudstones, arenites and intervals of bioclastic limestone (e.g. 'Blastoid Hill') and cherts with radiolarians. A diverse ichnofauna, phacopid trilobites, echinoderms (crinoids and blastoids) together with brachiopods, ostracods, bryozoans and rare cephalopods have been collected from this interval. Analysis of geochemical data, microfacies and especially the distribution of marine organisms, which are not described in detail here, but used for facies analysis, indicate a deepening of the depositional environment at the Boulongour Reservoir section. Results presented here concern mainly the sedimentological and stratigraphical context of the investigated section. Additionally, one Late Devonian palaeo-oceanic and biotic event, the Upper Kellwasser Event is recognized near the section base.

Geochemical and multi-isotopic (87Sr/86Sr, 143Nd/144Nd, 238U/235U) perspectives of sediment sources, depositional conditions, and diagenesis of the Marcellus Shale, Appalachian Basin, USA

NASA Astrophysics Data System (ADS)

Phan, Thai T.; Gardiner, James B.; Capo, Rosemary C.; Stewart, Brian W.

2018-02-01

We investigate sediment sources, depositional conditions and diagenetic processes affecting the Middle Devonian Marcellus Shale in the Appalachian Basin, eastern USA, a major target of natural gas exploration. Multiple proxies, including trace metal contents, rare earth elements (REE), the Sm-Nd and Rb-Sr isotope systems, and U isotopes were applied to whole rock digestions and sequentially extracted fractions of the Marcellus shale and adjacent units from two locations in the Appalachian Basin. The narrow range of εNd values (from -7.8 to -6.4 at 390 Ma) is consistent with derivation of the clastic sedimentary component of the Marcellus Shale from a well-mixed source of fluvial and eolian material of the Grenville orogenic belt, and indicate minimal post-depositional alteration of the Sm-Nd system. While silicate minerals host >80% of the REE in the shale, data from sequentially extracted fractions reflect post-depositional modifications at the mineralogical scale, which is not observed in whole rock REE patterns. Limestone units thought to have formed under open ocean (oxic) conditions have δ238U values and REE patterns consistent with modern seawater. The δ238U values in whole rock shale and authigenic phases are greater than those of modern seawater and the upper crust. The δ238U values of reduced phases (the oxidizable fraction consisting of organics and sulfide minerals) are ∼0.6‰ greater than that of modern seawater. Bulk shale and carbonate cement extracted from the shale have similar δ238U values, and are greater than δ238U values of adjacent limestone units. We suggest these trends are due to the accumulation of chemically and, more likely, biologically reduced U from anoxic to euxinic bottom water as well as the influence of diagenetic reactions between pore fluids and surrounding sediment and organic matter during diagenesis and catagenesis.

Using SEM Analysis on Ion-Milled Shale Surface to Determine Shale-Fracturing Fluid Interaction

NASA Astrophysics Data System (ADS)

Lu, J.; Mickler, P. J.; Nicot, J. P.

2014-12-01

It is important to document and assess shale-fluid interaction during hydraulic fracturing (HF) in order to understand its impact on flowback water chemistry and rock property. A series of autoclave experiments were conducted to react shale samples from major oil and gas shales with synthetic HF containing various additives. To better determine mineral dissolution and precipitation at the rock-fluid interface, ion-milling technique was applied to create extremely flat rock surfaces that were examined before and after the autoclave experiments using a scanning electron microscope (SEM) coupled with energy dispersive spectroscopy (EDS) detectors. This method is able to reveal a level of detail not observable on broken surface or mechanically polished surface. It allows direct comparison of the same mineral and organic matter particles before and after the reaction experiments. Minerals undergone dissolution and newly precipitated materials are readily determined by comparing to the exact locations before reaction. The dissolution porosity and the thickness of precipitates can be quantified by tracing and measuring the geometry of the pores and precipitates. Changes in porosity and permeability were confirmed by mercury intrusion capillary tests.

Design of experimental system for supercritical CO2 fracturing under confining pressure conditions

NASA Astrophysics Data System (ADS)

Wang, H.; Lu, Q.; Li, X.; Yang, B.; Zheng, Y.; Shi, L.; Shi, X.

2018-03-01

Supercritical CO2 has the characteristics of low viscosity, high diffusion and zero surface tension, and it is considered as a new fluid for non-polluting and non-aqueous fracturing which can be used for shale gas development. Fracturing refers to a method of utilizing the high-pressure fluid to generate fractures in the rock formation so as to improve the oil and gas flow conditions and increase the oil and gas production. In this article, a new type of experimental system for supercritical CO2 fracturing under confining pressure conditions is designed, which is based on characteristics of supercritical CO2, shale reservoir and down-hole environment. The experimental system consists of three sub-systems, including supercritical CO2 generation system, supercritical CO2 fracturing system and data analysis system. It can be used to simulate supercritical CO2 fracturing under geo-stress conditions, thus to study the rock initiation pressure, the formation of the rock fractures, fractured surface morphology and so on. The experimental system has successfully carried out a series of supercritical CO2 fracturing experiments. The experimental results confirm the feasibility of the experimental system and the high efficiency of supercritical CO2 in fracturing tight rocks.

Smart magnetic markers use in hydraulic fracturing.

PubMed

Zawadzki, Jarosław; Bogacki, Jan

2016-11-01

One of the main challenges and unknowns during shale gas exploration is to assess the range and efficiency of hydraulic fracturing. It is also essential to assess the distribution of proppant, which keeps the fracture pathways open. Solving these problems may considerably increase the efficiency of the shale gas extraction. Because of that, the idea of smart magnetic marker, which can be detected when added to fracturing fluid, has been considered for a long time. This study provides overview of the possibilities of magnetic marker application for shale gas extraction. The imaging methods using electromagnetic markers, are considered or developed in two directions. The first possibility is the markers' electromagnetic activity throughout the whole volume of the fracturing fluid. Thus, it can be assumed that the whole fracturing fluid is the marker. Among these type of hydraulic fracturing solutions, ferrofluid could be considered. The second possibility is marker, which is just one of many components of the fracturing fluid. In this case feedstock magnetic materials, ferrites and nanomaterials could be considered. Magnetic properties of magnetite could be too low and ferrofluids' or nanomaterials' price is unacceptably high. Because of that, ferrites, especially ZnMn ferrites seems to be the best material for magnetic marker. Because of the numerous applications in electronics, it is cheap and easily available, although the price is higher, then that of magnetite. The disadvantage of using ferrite, could be too small mechanical strength. It creates an essential need for combining magnetic marker with proppant into magnetic-ceramic composite. Copyright © 2016 Elsevier Ltd. All rights reserved.

Role of Induced and Natural Imbibition in Frac Fluid Transport and Fate in Gas Shales, March 28-29, 2011

EPA Pesticide Factsheets

Hydraulic fracture modeling and fracture surface area calculations determined from pressure decay analysis and reservoir numerical flow simulation support estimates of created hydraulic fracture surface areas of 24-60 MM sq ft.

Ecological risks of shale oil and gas development to wildlife, aquatic resources and their habitats

USGS Publications Warehouse

Brittingham, Margaret C.; Maloney, Kelly O.; Farag, Aïda M.; Harper, David D.; Bowen, Zachary H.

2014-01-01

Technological advances in hydraulic fracturing and horizontal drilling have led to the exploration and exploitation of shale oil and gas both nationally and internationally. Extensive development of shale resources has occurred within the United States over the past decade, yet full build out is not expected to occur for years. Moreover, countries across the globe have large shale resources and are beginning to explore extraction of these resources. Extraction of shale resources is a multistep process that includes site identification, well pad and infrastructure development, well drilling, high-volume hydraulic fracturing and production; each with its own propensity to affect associated ecosystems. Some potential effects, for example from well pad, road and pipeline development, will likely be similar to other anthropogenic activities like conventional gas drilling, land clearing, exurban and agricultural development and surface mining (e.g., habitat fragmentation and sedimentation). Therefore, we can use the large body of literature available on the ecological effects of these activities to estimate potential effects from shale development on nearby ecosystems. However, other effects, such as accidental release of wastewaters, are novel to the shale gas extraction process making it harder to predict potential outcomes. Here, we review current knowledge of the effects of high-volume hydraulic fracturing coupled with horizontal drilling on terrestrial and aquatic ecosystems in the contiguous United States, an area that includes 20 shale plays many of which have experienced extensive development over the past decade. We conclude that species and habitats most at risk are ones where there is an extensive overlap between a species range or habitat type and one of the shale plays (leading to high vulnerability) coupled with intrinsic characteristics such as limited range, small population size, specialized habitat requirements, and high sensitivity to disturbance. Examples include core forest habitat and forest specialists, sagebrush habitat and specialists, vernal pond inhabitants and stream biota. We suggest five general areas of research and monitoring that could aid in development of effective guidelines and policies to minimize negative impacts and protect vulnerable species and ecosystems: (1) spatial analyses, (2) species-based modeling, (3) vulnerability assessments, (4) ecoregional assessments, and (5) threshold and toxicity evaluations.

Ecological risks of shale oil and gas development to wildlife, aquatic resources and their habitats.

PubMed

Brittingham, Margaret C; Maloney, Kelly O; Farag, Aïda M; Harper, David D; Bowen, Zachary H

2014-10-07

Technological advances in hydraulic fracturing and horizontal drilling have led to the exploration and exploitation of shale oil and gas both nationally and internationally. Extensive development of shale resources has occurred within the United States over the past decade, yet full build out is not expected to occur for years. Moreover, countries across the globe have large shale resources and are beginning to explore extraction of these resources. Extraction of shale resources is a multistep process that includes site identification, well pad and infrastructure development, well drilling, high-volume hydraulic fracturing and production; each with its own propensity to affect associated ecosystems. Some potential effects, for example from well pad, road and pipeline development, will likely be similar to other anthropogenic activities like conventional gas drilling, land clearing, exurban and agricultural development and surface mining (e.g., habitat fragmentation and sedimentation). Therefore, we can use the large body of literature available on the ecological effects of these activities to estimate potential effects from shale development on nearby ecosystems. However, other effects, such as accidental release of wastewaters, are novel to the shale gas extraction process making it harder to predict potential outcomes. Here, we review current knowledge of the effects of high-volume hydraulic fracturing coupled with horizontal drilling on terrestrial and aquatic ecosystems in the contiguous United States, an area that includes 20 shale plays many of which have experienced extensive development over the past decade. We conclude that species and habitats most at risk are ones where there is an extensive overlap between a species range or habitat type and one of the shale plays (leading to high vulnerability) coupled with intrinsic characteristics such as limited range, small population size, specialized habitat requirements, and high sensitivity to disturbance. Examples include core forest habitat and forest specialists, sagebrush habitat and specialists, vernal pond inhabitants and stream biota. We suggest five general areas of research and monitoring that could aid in development of effective guidelines and policies to minimize negative impacts and protect vulnerable species and ecosystems: (1) spatial analyses, (2) species-based modeling, (3) vulnerability assessments, (4) ecoregional assessments, and (5) threshold and toxicity evaluations.

Complementary hydro-mechanical coupled finite/discrete element and microseismic modelling to predict hydraulic fracture propagation in tight shale reservoirs

NASA Astrophysics Data System (ADS)

Profit, Matthew; Dutko, Martin; Yu, Jianguo; Cole, Sarah; Angus, Doug; Baird, Alan

2016-04-01

This paper presents a novel approach to predict the propagation of hydraulic fractures in tight shale reservoirs. Many hydraulic fracture modelling schemes assume that the fracture direction is pre-seeded in the problem domain discretisation. This is a severe limitation as the reservoir often contains large numbers of pre-existing fractures that strongly influence the direction of the propagating fracture. To circumvent these shortcomings, a new fracture modelling treatment is proposed where the introduction of discrete fracture surfaces is based on new and dynamically updated geometrical entities rather than the topology of the underlying spatial discretisation. Hydraulic fracturing is an inherently coupled engineering problem with interactions between fluid flow and fracturing when the stress state of the reservoir rock attains a failure criterion. This work follows a staggered hydro-mechanical coupled finite/discrete element approach to capture the key interplay between fluid pressure and fracture growth. In field practice, the fracture growth is hidden from the design engineer and microseismicity is often used to infer hydraulic fracture lengths and directions. Microseismic output can also be computed from changes of the effective stress in the geomechanical model and compared against field microseismicity. A number of hydraulic fracture numerical examples are presented to illustrate the new technology.

Studies investigate effects of hydraulic fracturing

NASA Astrophysics Data System (ADS)

Balcerak, Ernie

2012-11-01

The use of hydraulic fracturing, also known as fracking, to enhance the retrieval of natural gas from shale has been increasing dramatically—the number of natural gas wells rose about 50% since 2000. Shale gas has been hailed as a relatively low-cost, abundant energy source that is cleaner than coal. However, fracking involves injecting large volumes of water, sand, and chemicals into deep shale gas reservoirs under high pressure to open fractures through which the gas can travel, and the process has generated much controversy. The popular press, advocacy organizations, and the documentary film Gasland by Josh Fox have helped bring this issue to a broad audience. Many have suggested that fracking has resulted in contaminated drinking water supplies, enhanced seismic activity, demands for large quantities of water that compete with other uses, and challenges in managing large volumes of resulting wastewater. As demand for expanded domestic energy production intensifies, there is potential for substantially increased use of fracking together with other recovery techniques for "unconventional gas resources," like extended horizontal drilling.

Integrated Experimental and Computational Study of Hydraulic Fracturing and the Use of Alternative Fracking Fluids

NASA Astrophysics Data System (ADS)

Viswanathan, H.; Carey, J. W.; Karra, S.; Porter, M. L.; Rougier, E.; Zhang, D.; Makedonska, N.; Middleton, R. S.; Currier, R.; Gupta, R.; Lei, Z.; Kang, Q.; O'Malley, D.; Hyman, J.

2014-12-01

Shale gas is an unconventional fossil energy resource that is already having a profound impact on US energy independence and is projected to last for at least 100 years. Production of methane and other hydrocarbons from low permeability shale involves hydrofracturing of rock, establishing fracture connectivity, and multiphase fluid-flow and reaction processes all of which are poorly understood. The result is inefficient extraction with many environmental concerns. A science-based capability is required to quantify the governing mesoscale fluid-solid interactions, including microstructural control of fracture patterns and the interaction of engineered fluids with hydrocarbon flow. These interactions depend on coupled thermo-hydro-mechanical-chemical (THMC) processes over scales from microns to tens of meters. Determining the key mechanisms in subsurface THMC systems has been impeded due to the lack of sophisticated experimental methods to measure fracture aperture and connectivity, multiphase permeability, and chemical exchange capacities at the high temperature, pressure, and stresses present in the subsurface. This project uses innovative high-pressure microfluidic and triaxial core flood experiments on shale to explore fracture-permeability relations and the extraction of hydrocarbon. These data are integrated with simulations including lattice Boltzmann modeling of pore-scale processes, finite-element/discrete element models of fracture development in the near-well environment, discrete-fracture modeling of the reservoir, and system-scale models to assess the economics of alternative fracturing fluids. The ultimate goal is to make the necessary measurements to develop models that can be used to determine the reservoir operating conditions necessary to gain a degree of control over fracture generation, fluid flow, and interfacial processes over a range of subsurface conditions.

Early jointing in coal and black shale: Evidence for an Appalachian-wide stress field as a prelude to the Alleghanian orogeny

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

Engelder, T.; Whitaker, A.

2006-07-15

Early ENE-striking joints (present coordinates) within both Pennsylvanian coal and Devonian black shale of the Central and Southern Appalachians reflect an approximately rectilinear stress field with a dimension > 1500 km. This Appalachian-wide stress field (AWSF) dates from the time of joint propagation, when both the coal and shale were buried to the oil window during the 10-15 m.y. period straddling the Pennsylvanian-Permian boundary. The AWSF was generated during the final assembly of Pangea as a consequence of plate-boundary tractions arising from late-stage oblique convergence, where maximum horizontal stress, S-H, of the AWSF was parallel to the direction of closuremore » between Gondwana and Laurentia. After closure, the AWSF persisted during dextral slip of peri-Gondwanan microcontinents, when SH appears to have crosscut plate-scale trans-current faults at around 30{sup o}. Following > 10 m.y. of dextral slip during tightening of Gondwana against Laurentia, the AWSF was disrupted by local stress fields associated with thrusting on master basement decollements to produce the local orocline-shaped Alleghanian map pattern seen today.« less

Factors controlling Li concentration and isotopic composition in formation waters and host rocks of Marcellus Shale, Appalachian Basin

USGS Publications Warehouse

Phan, Thai T.; Capo, Rosemary C; Stewart, Brian W.; Macpherson, Gwen; Rowan, Elisabeth L.; Hammack, Richard W.

2015-01-01

In Greene Co., southwest Pennsylvania, the Upper Devonian sandstone formation waters have δ7Li values of + 14.6 ± 1.2 (2SD, n = 25), and are distinct from Marcellus Shale formation waters which have δ7Li of + 10.0 ± 0.8 (2SD, n = 12). These two formation waters also maintain distinctive 87Sr/86Sr ratios suggesting hydrologic separation between these units. Applying temperature-dependent illitilization model to Marcellus Shale, we found that Li concentration in clay minerals increased with Li concentration in pore fluid during diagenetic illite-smectite transition. Samples from north central PA show a much smaller range in both δ7Li and 87Sr/86Sr than in southwest Pennsylvania. Spatial variations in Li and δ7Li values show that Marcellus formation waters are not homogeneous across the Appalachian Basin. Marcellus formation waters in the northeastern Pennsylvania portion of the basin show a much smaller range in both δ7Li and 87Sr/86Sr, suggesting long term, cross-formational fluid migration in this region. Assessing the impact of potential mixing of fresh water with deep formation water requires establishment of a geochemical and isotopic baseline in the shallow, fresh water aquifers, and site specific characterization of formation water, followed by long-term monitoring, particularly in regions of future shale gas development.

Stream measurements locate thermogenic methane fluxes in groundwater discharge in an area of shale-gas development.

PubMed

Heilweil, Victor M; Grieve, Paul L; Hynek, Scott A; Brantley, Susan L; Solomon, D Kip; Risser, Dennis W

2015-04-07

The environmental impacts of shale-gas development on water resources, including methane migration to shallow groundwater, have been difficult to assess. Monitoring around gas wells is generally limited to domestic water-supply wells, which often are not situated along predominant groundwater flow paths. A new concept is tested here: combining stream hydrocarbon and noble-gas measurements with reach mass-balance modeling to estimate thermogenic methane concentrations and fluxes in groundwater discharging to streams and to constrain methane sources. In the Marcellus Formation shale-gas play of northern Pennsylvania (U.S.A.), we sampled methane in 15 streams as a reconnaissance tool to locate methane-laden groundwater discharge: concentrations up to 69 μg L(-1) were observed, with four streams ≥ 5 μg L(-1). Geochemical analyses of water from one stream with high methane (Sugar Run, Lycoming County) were consistent with Middle Devonian gases. After sampling was completed, we learned of a state regulator investigation of stray-gas migration from a nearby Marcellus Formation gas well. Modeling indicates a groundwater thermogenic methane flux of about 0.5 kg d(-1) discharging into Sugar Run, possibly from this fugitive gas source. Since flow paths often coalesce into gaining streams, stream methane monitoring provides the first watershed-scale method to assess groundwater contamination from shale-gas development.

U.S. DOE NETL methodology for estimating the prospective CO 2 storage resource of shales at the national and regional scale

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

Levine, Jonathan S.; Fukai, Isis; Soeder, Daniel J.

While the majority of shale formations will serve as reservoir seals for stored anthropogenic carbon dioxide (CO2), hydrocarbon-bearing shale formations may be potential geologic sinks after depletion through primary production. Here in this paper we present the United States-Department of Energy-National Energy Technology Laboratory (US-DOE-NETL) methodology for screening-level assessment of prospective CO 2 storage resources in shale using a volumetric equation. Volumetric resource estimates are produced from the bulk volume, porosity, and sorptivity of the shale and storage efficiency factors based on formation-scale properties and petrophysical limitations on fluid transport. Prospective shale formations require: (1) prior hydrocarbon production using horizontalmore » drilling and stimulation via staged, high-volume hydraulic fracturing, (2) depths sufficient to maintain CO 2 in a supercritical state, generally >800 m, and (3) an overlying seal. The US-DOE-NETL methodology accounts for storage of CO 2 in shale as a free fluid phase within fractures and matrix pores and as an sorbed phase on organic matter and clays. Uncertainties include but are not limited to poorly-constrained geologic variability in formation thickness, porosity, existing fluid content, organic richness, and mineralogy. Knowledge of how these parameters may be linked to depositional environments, facies, and diagenetic history of the shale will improve the understanding of pore-to-reservoir scale behavior, and provide improved estimates of prospective CO 2 storage.« less

U.S. DOE NETL methodology for estimating the prospective CO 2 storage resource of shales at the national and regional scale

DOE PAGES

Levine, Jonathan S.; Fukai, Isis; Soeder, Daniel J.; ...

2016-05-31

While the majority of shale formations will serve as reservoir seals for stored anthropogenic carbon dioxide (CO2), hydrocarbon-bearing shale formations may be potential geologic sinks after depletion through primary production. Here in this paper we present the United States-Department of Energy-National Energy Technology Laboratory (US-DOE-NETL) methodology for screening-level assessment of prospective CO 2 storage resources in shale using a volumetric equation. Volumetric resource estimates are produced from the bulk volume, porosity, and sorptivity of the shale and storage efficiency factors based on formation-scale properties and petrophysical limitations on fluid transport. Prospective shale formations require: (1) prior hydrocarbon production using horizontalmore » drilling and stimulation via staged, high-volume hydraulic fracturing, (2) depths sufficient to maintain CO 2 in a supercritical state, generally >800 m, and (3) an overlying seal. The US-DOE-NETL methodology accounts for storage of CO 2 in shale as a free fluid phase within fractures and matrix pores and as an sorbed phase on organic matter and clays. Uncertainties include but are not limited to poorly-constrained geologic variability in formation thickness, porosity, existing fluid content, organic richness, and mineralogy. Knowledge of how these parameters may be linked to depositional environments, facies, and diagenetic history of the shale will improve the understanding of pore-to-reservoir scale behavior, and provide improved estimates of prospective CO 2 storage.« less

Hydrogeology of the West Branch Delaware River basin, Delaware County, New York

USGS Publications Warehouse

Reynolds, Richard J.

2013-01-01

In 2009, the U.S. Geological Survey, in cooperation with the New York State Department of Environmental Conservation, began a study of the hydrogeology of the West Branch Delaware River (Cannonsville Reservoir) watershed. There has been recent interest by energy companies in developing the natural gas reserves that are trapped within the Marcellus Shale, which is part of the Hamilton Group of Devonian age that underlies all the West Branch Delaware River Basin. Knowing the extent and thickness of stratified-drift (sand and gravel) aquifers within this basin can help State and Federal regulatory agencies evaluate any effects on these aquifers that gas-well drilling might produce. This report describes the hydrogeology of the 455-square-mile basin in the southwestern Catskill Mountain region of southeastern New York and includes a detailed surficial geologic map of the basin. Analysis of surficial geologic data indicates that the most widespread surficial geologic unit within the basin is till, which is present as deposits of ablation till in major stream valleys and as thick deposits of lodgment till that fill upland basins. Till and colluvium (remobilized till) cover about 89 percent of the West Branch Delaware River Basin, whereas stratified drift (outwash and ice-contact deposits) and alluvium account for 8.9 percent. The Cannonsville Reservoir occupies about 1.9 percent of the basin area. Large areas of outwash and ice-contact deposits occupy the West Branch Delaware River valley along its entire length. These deposits form a stratified-drift aquifer that ranges in thickness from 40 to 50 feet (ft) in the upper West Branch Delaware River valley, from 70 to 140 ft in the middle West Branch Delaware River valley, and from 60 to 70 ft in the lower West Branch Delaware River valley. The gas-bearing Marcellus Shale underlies the entire West Branch Delaware River Basin and ranges in thickness from 600 to 650 ft along the northern divide of the basin to 750 ft thick along the southern divide. The depth to the top of the Marcellus Shale ranges from 3,240 ft along the northern basin divide to 4,150 ft along the southern basin divide. Yields of wells completed in the aquifer are as high as 500 gallons per minute (gal/min). Springs from fractured sandstone bedrock are an important source of domestic and small municipal water supplies in the West Branch Delaware River Basin and elsewhere in Delaware County. The average yield of 178 springs in Delaware County is 8.5 gal/min with a median yield of 3 gal/min. An analysis of two low-flow statistics indicates that groundwater contributions from fractured bedrock compose a significant part of the base flow of the West Branch Delaware River and its tributaries.

The shale gas boom and the need for rational policy.

PubMed

Finkel, Madelon; Hays, Jake; Law, Adam

2013-07-01

High-volume, slick water hydraulic fracturing of shale relies on pumping millions of gallons of surface water laced with toxic chemicals and sand under high pressure to create fractures to release the flow of gas. The process, however, has the potential to cause serious and irreparable damage to the environment and the potential for harm to human and animal health. At issue is how society should form appropriate policy in the absence of well-designed epidemiological studies and health impact assessments. The issue is fraught with environmental, economic, and health implications, and federal and state governments must establish detailed safeguards and ensure regulatory oversight, both of which are presently lacking in states where hydraulic fracturing is allowed.

Micro-fracture Behavior of Organic Matters in Kerogen-Rich Shale (KRS) Composites from Micro- to Milli-meter Scales

NASA Astrophysics Data System (ADS)

Haque, M. H.; Han, Y.; Hull, K. L.; Abousleiman, Y. N.

2017-12-01

Understanding the failure behavior of kerogen-rich shale (KRS) at multiscale is critical to efficient hydraulic fracture stimulations in unconventional source shale reservoirs. As a composite material consisting of compacted clay particles, silt-sized grains, and organic matter (OM), KRS is highly complex both structurally and mechanically. The OM, which is intertwined within the shale matrix, presents a particular challenge as it can be much more compliant than its surrounding minerals while at the same time have a significantly higher tensile strength. The mode-I fracture toughness and tensile failure behavior of KRS has been studied at the core scale by traditional rock mechanics methods i.e., Brazilian tests and more recently with non-traditional approaches at the micro-scale using nanoindentation techniques. However, core scale testing fails in precisely capturing the effects of OM due to its coarse resolution, while nanoindention may capture the behavior of isolated component but in some cases miss the collective properties of the composite system. To bridge this gap, while still complying with ASTM/ISRM standards in principle, we investigate fracture initiation and propagation in KRS using the single-edge notched beam (SENB) miniature samples with span length in the millimeter scale. The size scale attempts to isolate the contributions from individual components, especially the OM, to the emergent and systematic fracturing behavior of KRS. Crack propagation along and across the bedding planes have left noticeable signatures on fractured OM while travelling through and around an OM body depending upon its size and spatial position along the crack path illustrating what looks like crack arrest and/or crack bridging in a composite porous matrix. The fractured surface of OM, even being polymeric in nature, exhibits smooth and even surface profile when ripped apart but not in all observed surfaces. Unique microscale features such as- ridges, twists, and inclusions have also been observed for the OM indicating a mix of complex modes of failures. This study helps further the understanding of fracture morphologies in source rock reservoirs.

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

J. Zhou; H. Huang; M. Deo

Log and seismic data indicate that most shale formations have strong heterogeneity. Conventional analytical and semi-analytical fracture models are not enough to simulate the complex fracture propagation in these highly heterogeneous formation. Without considering the intrinsic heterogeneity, predicted morphology of hydraulic fracture may be biased and misleading in optimizing the completion strategy. In this paper, a fully coupling fluid flow and geomechanics hydraulic fracture simulator based on dual-lattice Discrete Element Method (DEM) is used to predict the hydraulic fracture propagation in heterogeneous reservoir. The heterogeneity of rock is simulated by assigning different material force constant and critical strain to differentmore » particles and is adjusted by conditioning to the measured data and observed geological features. Based on proposed model, the effects of heterogeneity at different scale on micromechanical behavior and induced macroscopic fractures are examined. From the numerical results, the microcrack will be more inclined to form at the grain weaker interface. The conventional simulator with homogeneous assumption is not applicable for highly heterogeneous shale formation.« less

Image Analysis of Proppant Performance in Pressurized Fractures

NASA Astrophysics Data System (ADS)

Crandall, D.; Smith, M. M.; Carroll, S.; Walsh, S. D.; Gill, M.; Moore, J.; Tennant, B.; Aines, R. D.

2014-12-01

Proppants are small particles used to prop or hold open subsurface fractures to permit fluid flow through these pathways. In many oil and gas well applications, the most common proppant materials are sand, ceramic particles, resin-coated sands, glass beads or even walnut shells. More dense proppants require additives to create viscous fluids which can transport them further along wells and into fractures, but are generally preferred over neutrally buoyant options due to their increased strength. Currently, proppant strength and generation of broken fragments ("fines") is analyzed via a standardized crush test between parallel plates. To augment this type of information, we present here the results of various experiments involving resin-coated proppants held at increasing pressures in fractured samples of Marcellus shale. The shale/proppant samples were imaged continuously with an industrial tomography scanner during pressurization up to 10,000psi. This technique allows for in situ characterization of fracture/proppant interactions and fracture void volume and average aperture with varying confining pressures.

Evolution of water chemistry during Marcellus Shale gas development: A case study in West Virginia.

PubMed

Ziemkiewicz, Paul F; Thomas He, Y

2015-09-01

Hydraulic fracturing (HF) has been used with horizontal drilling to extract gas and natural gas liquids from source rock such as the Marcellus Shale in the Appalachian Basin. Horizontal drilling and HF generates large volumes of waste water known as flowback. While inorganic ion chemistry has been well characterized, and the general increase in concentration through the flowback is widely recognized, the literature contains little information relative to organic compounds and radionuclides. This study examined the chemical evolution of liquid process and waste streams (including makeup water, HF fluids, and flowback) in four Marcellus Shale gas well sites in north central West Virginia. Concentrations of organic and inorganic constituents and radioactive isotopes were measured to determine changes in waste water chemistry during shale gas development. We found that additives used in fracturing fluid may contribute to some of the constituents (e.g., Fe) found in flowback, but they appear to play a minor role. Time sequence samples collected during flowback indicated increasing concentrations of organic, inorganic and radioactive constituents. Nearly all constituents were found in much higher concentrations in flowback water than in injected HF fluids suggesting that the bulk of constituents originate in the Marcellus Shale formation rather than in the formulation of the injected HF fluids. Liquid wastes such as flowback and produced water, are largely recycled for subsequent fracturing operations. These practices limit environmental exposure to flowback. Copyright © 2015 Elsevier Ltd. All rights reserved.

A microfluidic investigation of gas exsolution in glass and shale fracture networks

NASA Astrophysics Data System (ADS)

Porter, M. L.; Jimenez-Martinez, J.; Harrison, A.; Currier, R.; Viswanathan, H. S.

2016-12-01

Microfluidic investigations of pore-scale fluid flow and transport phenomena has steadily increased in recent years. In these investigations fluid flow is restricted to two-dimensions allowing for real-time visualization and quantification of complex flow and reactive transport behavior, which is difficult to obtain in other experimental systems. In this work, we describe a unique high pressure (up to 10.3 MPa) and temperature (up to 80 °C) microfluidics experimental system that allows us to investigate fluid flow and transport in geo-material (e.g., shale, Portland cement, etc.) micromodels. The use of geo-material micromodels allows us to better represent fluid-rock interactions including wettability, chemical reactivity, and nano-scale porosity at conditions representative of natural subsurface environments. Here, we present experimental results in fracture systems with applications to hydrocarbon mobility in fractured rocks. Complex fracture network patterns are derived from 3D x-ray tomography images of actual fractures created in shale rock cores. We use both shale and glass micromodels, allowing for a detailed comparison between flow phenomena in the different materials. We discuss results from two-phase gas (CO2 and N2) injection experiments designed to enhance oil recovery. In these experiments gas was injected into micromodels saturated with oil and allowed to soak for approximately 12 hours at elevated pressures. The pressure in the system was then decreased to atmospheric, causing the gas to expand and/or dissolve out of solution, subsequently mobilizing the oil. In addition to the experimental results, we present a relatively simple model designed to quantify the amount of oil mobilized as a function of decreasing system pressure. We will show comparisons between the experiments and model, and discuss the potential use of the model in field-scale reservoir simulations.

Permeability Evolution of Propped Artificial Fractures in Green River Shale

NASA Astrophysics Data System (ADS)

Li, Xiang; Feng, Zijun; Han, Gang; Elsworth, Derek; Marone, Chris; Saffer, Demian; Cheon, Dae-Sung

2017-06-01

This paper compares the evolution of permeability with effective stress in propped fractures in shale for native CH4 compared with that for sorbing CO2, slightly sorbing N2 and non-sorbing He. We examine the response for laboratory experiments on artificial propped fractures in Green River Shale to explore mechanisms of proppant embedment and fracture diagenesis. Split cylindrical specimens sandwich a proppant bead-pack at a constant confining stress of 20 MPa and with varied pore pressure. Permeability and sorption characteristics are measured with the pulse transient method. To explore the effect of swelling and embedment on fracture surface geometry, we measure the evolution of conductivity characteristics for different proppant geometries (single layer vs. multilayer), gas saturation and specimen variation in order to simulate both production and enhanced gas recovery. The resulting morphology of embedment is measured by white light interferometry and characterized via surface roughness parameter of mean, maximum and root-mean-square amplitudes. For both strongly (CO2, CH4) and slightly adsorptive gases (N2), the permeability first decreases with an increase in gas pressure due to swelling before effective stress effects dominate above the Langmuir pressure threshold. CO2 with its highest adsorption affinity produces the lowest permeability among these three gas permeants. Monolayer propped specimens show maximum swelling and lowered k/k 0 ratio and increased embedment recorded in the surface roughness relative to the multilayered specimens. Permeabilities measured for both injection and depletion cycles generally overlap and are repeatable with little hysteresis. This suggests the dominant role of reversible swelling over irreversible embedment. Gas permeant composition and related swelling have an important effect on the permeability evolution of shales.

Microbial diversity and methanogenic activity of Antrim Shale formation waters from recently fractured wells

PubMed Central

Wuchter, Cornelia; Banning, Erin; Mincer, Tracy J.; Drenzek, Nicholas J.; Coolen, Marco J. L.

2013-01-01

The Antrim Shale in the Michigan Basin is one of the most productive shale gas formations in the U.S., but optimal resource recovery strategies must rely on a thorough understanding of the complex biogeochemical, microbial, and physical interdependencies in this and similar systems. We used Illumina MiSeq 16S rDNA sequencing to analyze the diversity and relative abundance of prokaryotic communities present in Antrim shale formation water of three closely spaced recently fractured gas-producing wells. In addition, the well waters were incubated with a suite of fermentative and methanogenic substrates in an effort to stimulate microbial methane generation. The three wells exhibited substantial differences in their community structure that may arise from their different drilling and fracturing histories. Bacterial sequences greatly outnumbered those of archaea and shared highest similarity to previously described cultures of mesophiles and moderate halophiles within the Firmicutes, Bacteroidetes, and δ- and ε-Proteobacteria. The majority of archaeal sequences shared highest sequence similarity to uncultured euryarchaeotal environmental clones. Some sequences closely related to cultured methylotrophic and hydrogenotrophic methanogens were also present in the initial well water. Incubation with methanol and trimethylamine stimulated methylotrophic methanogens and resulted in the largest increase in methane production in the formation waters, while fermentation triggered by the addition of yeast extract and formate indirectly stimulated hydrogenotrophic methanogens. The addition of sterile powdered shale as a complex natural substrate stimulated the rate of methane production without affecting total methane yields. Depletion of methane indicative of anaerobic methane oxidation (AMO) was observed over the course of incubation with some substrates. This process could constitute a substantial loss of methane in the shale formation. PMID:24367357

Silurian and Devonian in Vietnam—Stratigraphy and facies

NASA Astrophysics Data System (ADS)

Thanh, Tống Duy; Phương, Tạ Hoàng; Janvier, Philippe; Hùng, Nguyễn Hữu; Cúc, Nguyễn Thị Thu; Dương, Nguyễn Thùy

2013-09-01

Silurian and Devonian deposits in Viet Nam are present in several zones and regions, including Quang Ninh, East Bac Bo, and West Bac Bo Zones of the Bac Bo Region, the Dien Bien-Nghe An and Binh Tri Thien Zones of the Viet-Lao Region, and the South Trung Bo, and Western Nam Bo Zones of the South Viet Nam Region (Fig. 1). The main lithological features and faunal composition of the Silurian and Devonian Units in all these zones are briefly described. The Silurian consists of deep-water deposits of the upper parts of the Co To and Tan Mai Formations in the Quang Ninh Zone, the upper parts of the Phu Ngu Formation in the East Bac Bo Zone and the upper parts of the Long Dai and Song Ca Formations in the Viet-Lao Region. Shallow water facies Silurian units containing benthic faunas are more widely distributed, including the upper part of the Sinh Vinh and Bo Hieng Formations in the West Bac Bo Zone, the Kien An Formation in the Quang Ninh Zone, and, in the Viet-Lao Region, the Dai Giang Formation and the upper part of the Tay Trang Formation. No Lower and Middle Devonian deposits indicate deep water facies, but they are characterized by different shallow water facies. Continental to near shore, deltaic facies characterize the Lower Devonian Song Cau Group in the East Bac Bo Zone, the Van Canh Formation in the Quang Ninh Zone, and the A Choc Formation in the Binh Tri Thien Zone. Similar facies also occur in the Givetian Do Son Formation of the Quang Ninh Zone, and the Tan Lap Formation in the East Bac Bo Zone, and consist of coarse terrigenous deposits—cross-bedded conglomerates, sandstone, etc. Most Devonian units are characterized by shallow marine shelf facies. Carbonate and terrigenous-carbonate facies dominate, and terrigenous facies occur in the Lower and Middle Devonian sections in some areas only. The deep-water-like facies is characteriztic for some Upper Devonian formations in the Bac Bo (Bang Ca and Toc Tat Formations) and Viet-Lao Regions (Thien Nhan and Xom Nha Formations). These formations contain cherty shale or siliceous limestone, and fossils consist of conodonts, but there are also brachiopods and other benthos. They were possibly deposited in a deep water environment on the slope of the continental shelf. Most Devonian units distributed in the North and the Central Viet Nam consist of self shallow water sediments, and apparently they were deposited in a passive marginal marine environment. The coarse clastic continental or subcontinental deposits are distributed only in some areas of the East Bac Bo and of the Quang Ninh zones of the Bac Bo Region, and in the south of the Binh Tri Thien Zone. This situation suggests the influence of the Caledonian movement at the end of the Silurian period that called the Guangxi movement in South China.

Fundamental Study of Disposition and Release of Methane in a Shale Gas Reservoir

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

Wang, Yifeng; Xiong, Yongliang; Criscenti, Louise J.

The recent boom in shale gas production through hydrofracturing has reshaped the energy production landscape in the United States. Wellbore production rates vary greatly among the wells within a single field and decline rapidly with time, thus bring up a serious concern with the sustainability of shale gas production. Shale gas production starts with creating a fracture network by injecting a pressurized fluid in a wellbore. The induced fractures are then held open by proppant particles. During production, gas releases from the mudstone matrix, migrates to nearby fractures, and ultimately reaches a production wellbore. Given the relatively high permeability ofmore » the induced fractures, gas release and migration in low-permeability shale matrix is likely to be a limiting step for long-term wellbore production. Therefore, a clear understanding of the underlying mechanisms of methane disposition and release in shale matrix is crucial for the development of new technologies to maximize gas production and recovery. Shale is a natural nanocomposite material with distinct characteristics of nanometer-scale pore sizes, extremely low permeability, high clay contents, significant amounts of organic carbon, and large spatial heterogeneities. Our work has shown that nanopore confinement plays an important role in methane disposition and release in shale matrix. Using molecular simulations, we show that methane release in nanoporous kerogen matrix is characterized by fast release of pressurized free gas (accounting for ~ 30 - 47% recovery) followed by slow release of adsorbed gas as the gas pressure decreases. The first stage is driven by the gas pressure gradient while the second stage is controlled by gas desorption and diffusion. The long-term production decline appears controlled by the second stage of gas release. We further show that diffusion of all methane in nanoporous kerogen behaves differently from the bulk phase, with much smaller diffusion coefficients. The MD simulations also indicate that a significant fraction (3 - 35%) of methane deposited in kerogen can potentially become trapped in isolated nanopores and thus not recoverable. We have successfully established experimental capabilities for measuring gas sorption and desorption on shale and model materials under a wide range of physical and chemical conditions. Both low and high pressure measurements show significant sorption of CH 4 and CO 2 onto clays, implying that methane adsorbed on clay minerals could contribute a significant portion of gas-in-place in an unconventional reservoir. We have also studied the potential impact of the interaction of shale with hydrofracking fluid on gas sorption. We have found that the CH 4-CO 2 sorption capacity for the reacted sample is systematically lower (by a factor of ~2) than that for the unreacted (raw) sample. This difference in sorption capacity may result from a mineralogical or surface chemistry change of the shale sample induced by fluid-rock interaction. Our results shed a new light on mechanistic understanding gas release and production decline in unconventional reservoirs.« less

Release of Particulate Iron Sulfide during Shale-Fluid Interaction.

PubMed

Kreisserman, Yevgeny; Emmanuel, Simon

2018-01-16

During hydraulic fracturing, a technique often used to extract hydrocarbons from shales, large volumes of water are injected into the subsurface. Although the injected fluid typically contains various reagents, it can become further contaminated by interaction with minerals present in the rocks. Pyrite, which is common in organic-rich shales, is a potential source of toxic elements, including arsenic and lead, and it is generally thought that for these elements to become mobilized, pyrite must first dissolve. Here, we use atomic force microscopy and environmental scanning electron microscopy to show that during fluid-rock interaction, the dissolution of carbonate minerals in Eagle Ford shale leads to the physical detachment, and mobilization, of embedded pyrite grains. In experiments carried out over a range of pH, salinity, and temperature we found that in all cases pyrite particles became detached from the shale surfaces. On average, the amount of pyrite detached was equivalent to 6.5 × 10 -11 mol m -2 s -1 , which is over an order of magnitude greater than the rate of pyrite oxidation expected under similar conditions. This result suggests that mechanical detachment of pyrite grains could be an important pathway for the mobilization of arsenic in hydraulic fracturing operations and in groundwater systems containing shales.

Estimating fracture spacing from natural tracers in shale-gas production

NASA Astrophysics Data System (ADS)

Bauer, S. J.; McKenna, S. A.; Heath, J. E.; Gardner, P.

2012-12-01

Resource appraisal and long-term recovery potential of shale gas relies on the characteristics of the fracture networks created within the formation. Both well testing and analysis of micro-seismic data can provide information on fracture characteristics, but approaches that directly utilize observations of gas transport through the fractures are not well-developed. We examine transport of natural tracers and analyze the breakthrough curves (BTC's) of these tracers with a multi-rate mass transfer (MMT) model to elucidate fracture characteristics. The focus here is on numerical simulation studies to determine constraints on the ability to accurately estimate fracture network characteristics as a function of the diffusion coefficients of the natural tracers, the number and timing of observations, the flow rates from the well, and the noise in the observations. Traditional tracer testing approaches for dual-porosity systems analyze the BTC of an injected tracer to obtain fracture spacing considering a single spacing value. An alternative model is the MMT model where diffusive mass transfer occurs simultaneously over a range of matrix block sizes defined by a statistical distribution (e.g., log-normal, gamma, or power-law). The goal of the estimation is defining the parameters of the fracture spacing distribution. The MMT model has not yet been applied to analysis of natural in situ natural tracers. Natural tracers are omnipresent in the subsurface, potentially obviating the needed for introduced tracers, and could be used to improve upon fracture characteristics estimated from pressure transient and decline curve production analysis. Results of this study provide guidance for data collection and analysis of natural tracers in fractured shale formations. Parameter estimation on simulated BTC's will provide guidance on the necessary timing of BTC sampling in field experiments. The MMT model can result in non-unique or nonphysical parameter estimates. We address this with Bayesian estimation approaches that can define uncertainty in estimated parameters as a posterior probability distribution. We will also use Bayesian estimation to examine model identifiability (e.g., selecting between parametric distributions of fracture spacing) from various BTC's. Application of the MMT model to natural tracers and hydraulic fractures in shale will require extension of the model to account for partitioning of the tracers between multiple phases and different mass transfer behavior in mixed gas-liquid (e.g., oil or groundwater rich) systems. 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.

The Role of Texture, Cracks, and Fractures in Highly Anisotropic Shales

NASA Astrophysics Data System (ADS)

Baird, Alan F.; Kendall, J. Michael; Fisher, Quentin J.; Budge, Jessica

2017-12-01

Organic shales generally have low permeability unless fractures are present. However, how gas, oil, and water flows into these fractures remains enigmatic. The alignment of clay minerals and the alignment of fractures and cracks are effective means to produce seismic anisotropy. Thus, the detection and characterization of this anisotropy can be used to infer details about lithology, rock fabric, and fracture and crack properties within the subsurface. We present a study characterizing anisotropy using S wave splitting from microseismic sources in a highly anisotropic shale. We observe very strong anisotropy (up to 30%) with predominantly VTI (vertical transverse isotropy) symmetry, but with evidence of an HTI (horizontal transverse isotropy) overprint due to a NE striking vertical fracture set parallel to the maximum horizontal compressive stress. We observe clear evidence of a shear wave triplication due to anisotropy, which to our knowledge is one of only a very few observations of such triplications in field-scale data. We use modal proportions of minerals derived from X-ray fluorescence data combined with realistic textures to estimate the contribution of intrinsic anisotropy as well as possible contributions of horizontally aligned cracks. We find that aligned clays can explain much of the observed anisotropy and that any cracks contributing to the vertical transverse isotropy (VTI) must have a low ratio of normal to tangential compliance (ZN/ZT), typical of isolated cracks with low hydraulic connectivity. Subhorizontal cracks have also been observed in the reservoir, and we propose that their reactivation during hydraulic fracturing may be an important mechanism to facilitate gas flow.

Inferences from Microfractures and Geochemistry in Dynamic Shale-CO2 Packed Bed Experiments

NASA Astrophysics Data System (ADS)

Radonjic, M.; Olabode, A.

2016-12-01

Subsurface storage of large volumes of carbondioxide (CO2) is expected to have long term rock-fluid interactions impact on reservoir and seal rocks properties. Caprocks, particularly sedimentary types, are the ultimate hydraulic barrier in carbon sequestration. The mineralogical components of sedimentary rocks are geochemically active under enormous earth stresses, which generate high pressure and temperature conditions. It has been postulated that in-situ mineralization can lead to flow impedance in natural fractures in the presence of favorable geochemical and thermodynamic conditions. This experimental modelling research investigated the impact of in-situ geochemical precipitation on conductivity of fractures. Geochemical analyses were performed on four different samples of shale rocks, effluent fluids and recovered precipitates both before and after CO2-brine flooding of crushed shale rocks at moderately high temperature and pressure conditions. The results showed that most significant diagenetic changes in shale rocks after flooding with CO2-brine, reflected in the effluent fluid with predominantly calcium based minerals dissolving and precipitating under experimental conditions. Major and trace elements in the effluent (using ICP-OES analysis) indicated that multiple geochemical reactions are occurring with almost all of the constituent minerals participating. The geochemical composition of precipitates recovered after the experiments showed diagenetic carbonates and opal as the main constituents. The bulk rock showed little changes in composition except for sharper and more refined peaks on XRD analysis, suggesting that a significant portion of the amorphous content of the rocks have been removed via dissolution by the slightly acid CO2-brine fluid that was injected. Micro-indentation results captured slight reduction in the hardness of the shale rocks and this reduction appeared dependent on diagenetic quartz content. It can be inferred that convective reactive transport of dissolved minerals are involved in nanoscale precipitation-dissolution processes in shale. This reactive transport of dissolved minerals can occlude micro-fracture flow paths, thereby improving shale caprock seal integrity with respect to leakage risk under CO2 sequestration conditions.

4D petroleum system model of the Mississippian System in the Anadarko Basin Province, Oklahoma, Kansas, Texas, and Colorado, U.S.A.

USGS Publications Warehouse

Higley, Debra K.

2013-01-01

The Upper Devonian and Lower Mississippian Woodford Shale is an important petroleum source rock for Mississippian reservoirs in the Anadarko Basin Province of Oklahoma, Kansas, Texas, and Colorado, based on results from a 4D petroleum system model of the basin. The Woodford Shale underlies Mississippian strata over most of the Anadarko Basin portions of Oklahoma and northeastern Texas. The Kansas and Colorado portions of the province are almost entirely thermally immature for oil generation from the Woodford Shale or potential Mississippian source rocks, based mainly on measured vitrinite reflectance and modeled thermal maturation. Thermal maturities of the Woodford Shale range from mature for oil to overmature for gas generation at present-day depths of about 5,000 to 20,000 ft. Oil generation began at burial depths of about 6,000 to 6,500 ft. Modeled onset of Woodford Shale oil generation was about 330 million years ago (Ma); peak oil generation was from 300 to 220 Ma.Mississippian production, including horizontal wells of the informal Mississippi limestone, is concentrated within and north of the Sooner Trend area in the northeast Oklahoma portion of the basin. This large pod of oil and gas production is within the area modeled as thermally mature for oil generation from the Woodford Shale. The southern boundary of the trend approximates the 99% transformation ratio of the Woodford Shale, which marks the end of oil generation. Because most of the Sooner Trend area is thermally mature for oil generation from the Woodford Shale, the trend probably includes short- and longer-distance vertical and lateral migration. The Woodford Shale is absent in the Mocane-Laverne Field area of the eastern Oklahoma panhandle; because of this, associated oil migrated from the south into the field. If the Springer Formation or deeper Mississippian strata generated oil, then the southern field area is within the oil window for associated petroleum source rocks. Mississippian fields along the western boundary of the study area were supplied by oil that flowed northward from the Panhandle Field area and westward from the deep basin.

Determination of suitability of natural Polish resources for production of ceramic proppants applied in gas exploration from European shale formations

NASA Astrophysics Data System (ADS)

Szymanska, Joanna; Mizera, Jaroslaw

2017-04-01

Poland is one of few European countries undertaking innovative research towards effective exploration of hydrocarbons form shale deposits. With regard for strict geological conditions, which occur during hydraulic fracturing, it is required to apply ceramic proppants enhancing extraction of shale gas. Ceramic proppants are granules (16/30 - 70/120 Mesh) classified as propping agents. These granules located in the newly created fissures (due to injected high pressure fluid) in the shale rock, act as a prop, what enables gas flow up the well. It occurs if the proppants can resist high stress of the closing fractures. Commonly applied proppants are quartz sands used only for shallow reservoirs and fissile shales (in the USA). Whereas, the ceramic granules are proper for extraction of gas on the high depths at hard geomechanical conditions (in Europe) to increase output even by 30 - 50%. In comparison to other propping materials, this kind of proppants predominate with mechanical strength, smoother surface, lower solubility in acids and also high stability in water. Such parameters can be available through proper raw materials selection to further proppants production. The Polish ceramic proppants are produced from natural resources as kaolin, bauxite and white clay mixed with water and binders. Afterwards, the slurries are subjected to granulation in a mechanical granulator and sintered at high temperatures (1200 - 1550°C). Taking into consideration presence of geomechanical barriers, that prevent fracture propagation beyond shale formations, it is crucial to determine quality of applied natural deposits. Next step is to optimize the proppants production and select the best kind of granules, what was the aim of this research. Utility of the raw materials was estimated on basis of their particle size distribution, bulk density, specific surface area (BET) and thermal analysis (thermogravimetry). Morphology and shape were determined by Scanning Electron Microscopy (SEM). Energy Dispersive Spectroscopy (EDS) enabled analysis of their chemical composition, what was compared with X-ray fluorescence (XRF) results. Crystallinity of the raw compounds was established by X-ray diffraction (XRD). Characterization of loamy materials enabled evaluation of their impact on ceramic slurries preparation for further granulation and sintering. The proppants were analyzed with X-Ray Tomography to determine their shape and pore distribution. 3D models also enabled prediction of proppant settlement in the fracture. The crucial parameter as mechanical strength, that influences the integrity of created fractures (fines exceeding 1 % reduce fracture conductivity), was established during the crush tests. High roundness coefficient, uniformity and bulk density results informed about stability of the prop. Environmental proppants interaction was evaluated by turbidity and solubility in acid measurements, which reflect a threat of the proppants decay in the well. The obtained outcomes prove the utility of applied natural resources in the granules production. In consequence, the obtained proppants can be used for hydraulic fracturing in high pressure, temperature and low permeable shale formations. The granules fulfil the norms thus are prospective on a global proppants market.

Halogenation of Hydraulic Fracturing Additives in the Shale Well Parameter Space

NASA Astrophysics Data System (ADS)

Sumner, A. J.; Plata, D.

2017-12-01

Horizontal Drilling and Hydraulic fracturing (HDHF) involves the deep-well injection of a `fracking fluid' composed of diverse and numerous chemical additives designed to facilitate the release and collection of natural gas from shale plays. The potential impacts of HDHF operations on water resources and ecosystems are numerous, and analyses of flowback samples revealed organic compounds from both geogenic and anthropogenic sources. Furthermore, halogenated chemicals were also detected, and these compounds are rarely disclosed, suggesting the in situ halogenation of reactive additives. To test this transformation hypothesis, we designed and operated a novel high pressure and temperature reactor system to simulate the shale well parameter space and investigate the chemical reactivity of twelve commonly disclosed and functionally diverse HDHF additives. Early results revealed an unanticipated halogenation pathway of α-β unsaturated aldehyde, Cinnamaldehyde, in the presence of oxidant and concentrated brine. Ongoing experiments over a range of parameters informed a proposed mechanism, demonstrating the role of various shale-well specific parameters in enabling the demonstrated halogenation pathway. Ultimately, these results will inform a host of potentially unintended interactions of HDHF additives during the extreme conditions down-bore of a shale well during HDHF activities.

[Chemical hazards arising from shale gas extraction].

PubMed

Pakulska, Daria

2015-01-01

The development of the shale industry is gaining momentum and hence the analysis of chemical hazards to the environment and health of the local population is extreiely timely and important. Chemical hazards are created during the exploitation of all minerals, but in the case of shale gas production, there is much more uncertainty as regards to the effects of new technologies application. American experience suggests the increasing risk of environmental contamination, mainly groundwater. The greatest, concern is the incomplete knowledge of the composition of fluids used for fracturing shale rock and unpredictability of long-term effects of hydraulic fracturing for the environment and health of residents. High population density in the old continent causes the problem of chemical hazards which is much larger than in the USA. Despite the growing public discontent data on this subject are limited. First of all, there is no epidemiological studies to assess the relationship between risk factors, such as air and water pollution, and health effects in populations living in close proximity to gas wells. The aim of this article is to identify and discuss existing concepts on the sources of environmental contamination, an indication of the environment elements under pressure and potential health risks arising from shale gas extraction.

Installation Restoration Program. Phase I. Records Search, Hancock Field, New York.

DTIC Science & Technology

1982-07-01

purplish red, red, gray, green or black shale (major fraction) and shaly dolomite (minor fraction). The unit is poorly stra- tified and reaches a... fractured and jointed locally. At Hancock Field, the Vernon is typically overlain by a thin layer of glacial till. Test borings advanced at the Semi...the consolidated rock aquifer, composed of shales and dolomitic shales of the previously described Vernon Formation. Water is contained in this unit

Aquifers survey in the context of source rocks exploitation: from baseline acquisition to long term monitoring

NASA Astrophysics Data System (ADS)

Garcia, Bruno; Rouchon, Virgile; Deflandre, Jean-Pierre

2017-04-01

Producing hydrocarbons from source rocks (like shales: a mix of clays, silts, carbonate and sandstone minerals containing matured organic matter, i.e. kerogen oil and gas, but also non-hydrocarbon various species of chemical elements including sometimes radioactive elements) requires to create permeability within the rock matrix by at least hydraulically fracturing the source rock. It corresponds to the production of hydrocarbon fuels that have not been naturally expelled from the pressurized matured source rock and that remain trapped in the porosity or/and kerogen porosity of the impermeable matrix. Azimuth and extent of developed fractures can be respectively determined and mapped by monitoring the associated induced microseismicity. This allows to have an idea of where and how far injected fluids penetrated the rock formation. In a geological context, aquifers are always present in the vicinity -or on fluid migration paths- of such shale formations: deep aquifers (near the shale formation) up to sub-surface and potable (surface) aquifers. Our purpose will be to track any unsuitable invasion or migration of chemicals specifies coming from matured shales of production fluids including both drilling and fracturing ones into aquifers. Our objective is to early detect and alarm of any anomaly to avoid any important environmental issue. The approach consists in deploying a specific sampling tool within a well to recover formation fluids and to run a panoply of appropriate laboratory tests to state on fluid characteristics. Of course for deep aquifers, such a characterization process may consider aquifer properties prior producing shale oil and gas, as they may contain naturally some chemical species present in the source rocks. One can also consider that a baseline acquisition could be justified in case of possible previous invasion of non-natural fluids in the formation under survey (due to any anthropogenic action at surface or in the underground). The paper aims at presenting the protocol and routine test we propose to make our early detection approach efficient for production of shale hydrocarbon fluids, in considering the source-rock reservoir itself, the aquifers, and also the chemical species present in the fluids that are used for hydraulic fracturing operations.

Retrospective Case Study in Killdeer, North Dakota, Study of the Potential Impacts of Hydraulic Fracturing on Drinking Water Resources.

EPA Science Inventory

This report describes the retrospective case study conducted near Killdeer, Dunn County, North Dakota. The Killdeer study area is the location of historical oil and gas production, with current unconventional oil and gas production occurring in the late Devonian/early Mississipp...

The Shale Gas Boom and the Need for Rational Policy

PubMed Central

Finkel, Madelon; Law, Adam

2013-01-01

High-volume, slick water hydraulic fracturing of shale relies on pumping millions of gallons of surface water laced with toxic chemicals and sand under high pressure to create fractures to release the flow of gas. The process, however, has the potential to cause serious and irreparable damage to the environment and the potential for harm to human and animal health. At issue is how society should form appropriate policy in the absence of well-designed epidemiological studies and health impact assessments. The issue is fraught with environmental, economic, and health implications, and federal and state governments must establish detailed safeguards and ensure regulatory oversight, both of which are presently lacking in states where hydraulic fracturing is allowed. PMID:23678928

Modeling of fault reactivation and induced seismicity during hydraulic fracturing of shale-gas reservoirs

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

Rutqvist, Jonny; Rinaldi, Antonio P.; Cappa, Frédéric

2013-07-01

We have conducted numerical simulation studies to assess the potential for injection-induced fault reactivation and notable seismic events associated with shale-gas hydraulic fracturing operations. The modeling is generally tuned towards conditions usually encountered in the Marcellus shale play in the Northeastern US at an approximate depth of 1500 m (~;;4,500 feet). Our modeling simulations indicate that when faults are present, micro-seismic events are possible, the magnitude of which is somewhat larger than the one associated with micro-seismic events originating from regular hydraulic fracturing because of the larger surface area that is available for rupture. The results of our simulations indicatedmore » fault rupture lengths of about 10 to 20 m, which, in rare cases can extend to over 100 m, depending on the fault permeability, the in situ stress field, and the fault strength properties. In addition to a single event rupture length of 10 to 20 m, repeated events and aseismic slip amounted to a total rupture length of 50 m, along with a shear offset displacement of less than 0.01 m. This indicates that the possibility of hydraulically induced fractures at great depth (thousands of meters) causing activation of faults and creation of a new flow path that can reach shallow groundwater resources (or even the surface) is remote. The expected low permeability of faults in producible shale is clearly a limiting factor for the possible rupture length and seismic magnitude. In fact, for a fault that is initially nearly-impermeable, the only possibility of larger fault slip event would be opening by hydraulic fracturing; this would allow pressure to penetrate the matrix along the fault and to reduce the frictional strength over a sufficiently large fault surface patch. However, our simulation results show that if the fault is initially impermeable, hydraulic fracturing along the fault results in numerous small micro-seismic events along with the propagation, effectively preventing larger events from occurring. Nevertheless, care should be taken with continuous monitoring of induced seismicity during the entire injection process to detect any runaway fracturing along faults.« less

Geologic models and evaluation of undiscovered conventional and continuous oil and gas resources: Upper Cretaceous Austin Chalk

USGS Publications Warehouse

Pearson, Krystal

2012-01-01

The Upper Cretaceous Austin Chalk forms a low-permeability, onshore Gulf of Mexico reservoir that produces oil and gas from major fractures oriented parallel to the underlying Lower Cretaceous shelf edge. Horizontal drilling links these fracture systems to create an interconnected network that drains the reservoir. Field and well locations along the production trend are controlled by fracture networks. Highly fractured chalk is present along both regional and local fault zones. Fractures are also genetically linked to movement of the underlying Jurassic Louann Salt with tensile fractures forming downdip of salt-related structures creating the most effective reservoirs. Undiscovered accumulations should also be associated with structure-controlled fracture systems because much of the Austin that overlies the Lower Cretaceous shelf edge remains unexplored. The Upper Cretaceous Eagle Ford Shale is the primary source rock for Austin Chalk hydrocarbons. This transgressive marine shale varies in thickness and lithology across the study area and contains both oil- and gas-prone kerogen. The Eagle Ford began generating oil and gas in the early Miocene, and vertical migration through fractures was sufficient to charge the Austin reservoirs.

Modeling emissions and environmental impacts of transportation activities associated with high volume horizontal hydraulic fracturing operations in the Marcellus Shale Formation : final report.

DOT National Transportation Integrated Search

2015-09-18

The researchers' initial University Transportation Research Center (UTRC) research project identified routes and road segments with predicted high volumes of truck traffic related to natural gas extraction in the Marcellus Shale region. Results also ...

New Isotopic Tracers for Shale Gas and Hydraulic Fracturing Fluids

EPA Pesticide Factsheets

The combined application of geochemistry, stable isotopes (δ18O, δ2H), strontium isotopes (87Sr/86Sr), boron isotopes (δ11B), and radium isotopes (228Ra/226Ra) provides a unique methodology for tracing and monitoring shale gas and fracking fluids in the environment.

Potential of hydraulically induced fractures to communicate with existing wellbores

NASA Astrophysics Data System (ADS)

Montague, James A.; Pinder, George F.

2015-10-01

The probability that new hydraulically fractured wells drilled within the area of New York underlain by the Marcellus Shale will intersect an existing wellbore is calculated using a statistical model, which incorporates: the depth of a new fracturing well, the vertical growth of induced fractures, and the depths and locations of existing nearby wells. The model first calculates the probability of encountering an existing well in plan view and combines this with the probability of an existing well-being at sufficient depth to intersect the fractured region. Average probability estimates for the entire region of New York underlain by the Marcellus Shale range from 0.00% to 3.45% based upon the input parameters used. The largest contributing parameter on the probability value calculated is the nearby density of wells meaning that due diligence by oil and gas companies during construction in identifying all nearby wells will have the greatest effect in reducing the probability of interwellbore communication.

Managing flowback and produced water from hydraulic fracturing under stochastic environment

NASA Astrophysics Data System (ADS)

Zhang, X.; Sun, A. Y.; Duncan, I. J.; Vesselinov, V. V.

2017-12-01

A large volume of wastewater is being generated from hydraulic fracturing in shale gas plays, including flowback and produced water. The produced wastewater in terms of its quantity and quality has become one of the main environmental problems facing shale gas industries worldwide. Cost-effective planning and management of flowback and produced water is highly desirable. Careful choice of treatment, disposal, and reuse options can lower costs and reduce potential environmental impacts. To handle the recourse issue in decision-making, a two-stage stochastic management model is developed to provide optimal alternatives for fracturing wastewater management. The proposed model is capable of prompting corrective actions to allow decision makers to adjust the pre-defined management strategies. By using this two-stage model, potential penalties arising from decision infeasibility can be minimized. The applicability of the proposed model is demonstrated using a representative synthetic example, in which tradeoffs between economic and environmental goals are quantified. This approach can generate informed defensible decisions for shale gas wastewater management. In addition, probabilistic and non-probabilistic uncertainties are effectively addressed.

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.

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

Malhotra, Vivak

The USA is embarking upon tackling the serious environmental challenges posed to the world by greenhouse gases, especially carbon dioxide (CO2). The dimension of the problem is daunting. In fact, according to the Energy Information Agency, nearly 6 billion metric tons of CO2 were produced in the USA in 2007 with coal-burning power plants contributing about 2 billion metric tons. To mitigate the concerns associated with CO2 emission, geological sequestration holds promise. Among the potential geological storage sites, unmineable coal seams and shale formations in particular show promise because of the probability of methane recovery while sequestering the CO2. However.more » the success of large-scale sequestration of CO2 in coal and shale would hinge on a thorough understanding of CO2's interactions with host reservoirs. An important parameter for successful storage of CO2 reservoirs would be whether the pressurized CO2 would remain invariant in coal and shale formations under reasonable internal and/or external perturbations. Recent research has brought to the fore the potential of induced seismicity, which may result in caprock compromise. Therefore, to evaluate the potential risks involved in sequestering CO2 in Illinois bituminous coal seams and shale, we studied: (i) the mechanical behavior of Murphysboro (Illinois) and Houchin Creek (Illinois) coals, (ii) thermodynamic behavior of Illinois bituminous coal at - 100oC ≤ T ≤ 300oC, (iii) how high pressure CO2 (up to 20.7 MPa) modifies the viscosity of the host, (iv) the rate of emission of CO2 from Illinois bituminous coal and shale cores if the cores, which were pressurized with high pressure (≤ 20.7 MPa) CO2, were exposed to an atmospheric pressure, simulating the development of leakage pathways, (v) whether there are any fractions of CO2 stored in these hosts which are resistance to emission by simply exposing the cores to atmospheric pressure, and (vi) how compressive shockwaves applied to the coal and shale cores, which were pressurized with high pressure CO2, determine the fate of sequestered CO2 in these cores. Our results suggested that Illinois bituminous coal in its unperturbed state, i.e., when not pressurized with CO2, showed large variations in the mechanical properties. Modulus varied from 0.7 GPa to 3.4 GPa even though samples were extracted from a single large chunk of coal. We did not observe any glass transition for Illinois bituminous coal at - 100oC ≤ T ≤ 300oC, however, when the coal was pressurized with CO2 at ambient ≤ P ≤ 20.7 MPa, the viscosity of the coal decreased and inversely scaled with the CO2 pressure. The decrease in viscosity as a function of pressure could pose CO2 injection problems for coal as lower viscosity would allow the solid coal to flow to plug the fractures, fissures, and cleats. Our experiments also showed a very small fraction of CO2 was absorbed in coal; and when CO2 pressurized coals were exposed to atmospheric conditions, the loss of CO2 from coals was massive. Half of the sequestered gas from the coal cores was lost in less than 20 minutes. Our shockwave experiments on Illinois bituminous coal, New Albany shale (Illinois), Devonian shale (Ohio), and Utica shale (Ohio) presented clear evidence that the significant emission of the sequestered CO2 from these formations cannot be discounted during seismic activity, especially if caprock is compromised. It is argued that additional shockwave studies, both compressive and transverse, would be required for successfully mapping the risks associated with sequestering high pressure CO2 in coal and shale formations.« less

Crack classification and evolution in anisotropic shale during cyclic loading tests by acoustic emission

NASA Astrophysics Data System (ADS)

Wang, Miaomiao; Tan, Chengxuan; Meng, Jing; Yang, Baicun; Li, Yuan

2017-08-01

Characterization and evolution of the cracking mode in shale formation is significant, as fracture networks are an important element in shale gas exploitation. In this study we determine the crack modes and evolution in anisotropic shale under cyclic loading using the acoustic emission (AE) parameter-analysis method based on the average frequency and RA (rise-time/amplitude) value. Shale specimens with bedding-plane orientations parallel and perpendicular to the axial loading direction were subjected to loading cycles with increasing peak values until failure occurred. When the loading was parallel to the bedding plane, most of the cracks at failure were shear cracks, while tensile cracks were dominant in the specimens that were loaded normal to the bedding direction. The evolution of the crack mode in the shale specimens observed in the loading-unloading sequence except for the first cycle can be divided into three stages: (I) no or several cracks (AE events) form as a result of the Kaiser effect, (II) tensile and shear cracks increase steadily at nearly equal proportions, (III) tensile cracks and shear cracks increase abruptly, with more cracks forming in one mode than in the other. As the dominant crack motion is influenced by the bedding, the failure mechanism is discussed based on the evolution of the different crack modes. Our conclusions can increase our understanding of the formation mechanism of fracture networks in the field.

The Distribution of Natural Fractures Above a Gas Shale: Questions About Whether Deep Fracture Fluid Leaks into Groundwater Outside the Realm of Faulty Borehole Construction

EPA Pesticide Factsheets

The question is whether this gas leakage is a case of faulty borehole construction or whether this is a case of methane traveling toward the water table along natural pathways, most likely consisting of unhealed faults or fractures

Fate of hydraulic fracturing chemicals under down-hole conditions

NASA Astrophysics Data System (ADS)

Blotevogel, J.; Kahrilas, G.; Corrin, E. R.; Borch, T.

2013-12-01

Hydraulic fracturing is a method to increase the yield of oil and natural gas extraction from unconventional rock formations. The process of hydrofracturing occurs via injecting water, sand, and chemicals into the production well and subjecting this mixture to high pressures to crack the rock shale, allowing increased amounts of gas and oil to seep out of the target formation. Typical constituents of the chemical mixtures are biocides, which are applied to inhibit growth of sulfate reducing bacteria in order to prevent pipe corrosion and production of hazardous gases. However, very little is known about the persistence, fate, and activity of biocides when subjected to the high temperatures and pressures of down-hole conditions. Thus, the objective of this talk is to present data from ongoing experiments focused on determining the fate of biocides commonly used for hydraulic fracturing under conditions simulating down-hole environments. Using stainless steel reactors, the high pressures and temperatures of down-hole conditions in the Marcellus shale are simulated, while concentration, speciation, and degradation of priority biocides are observed as a function of time, using primarily LC/MS techniques. The impact of water quality, shale, temperature, and pressure on the transformation kinetics and pathways of biocides will be discussed. Finally, field samples (both sediments and flowback brine) from the Marcellus shale are analyzed to verify that our lab simulations mirror real-life conditions and results.

Three types of gas hydrate reservoirs in the Gulf of Mexico identified in LWD data

USGS Publications Warehouse

Lee, Myung Woong; Collett, Timothy S.

2011-01-01

High quality logging-while-drilling (LWD) well logs were acquired in seven wells drilled during the Gulf of Mexico Gas Hydrate Joint Industry Project Leg II in the spring of 2009. These data help to identify three distinct types of gas hydrate reservoirs: isotropic reservoirs in sands, vertical fractured reservoirs in shale, and horizontally layered reservoirs in silty shale. In general, most gas hydratebearing sand reservoirs exhibit isotropic elastic velocities and formation resistivities, and gas hydrate saturations estimated from the P-wave velocity agree well with those from the resistivity. However, in highly gas hydrate-saturated sands, resistivity-derived gas hydrate-saturation estimates appear to be systematically higher by about 5% over those estimated by P-wave velocity, possibly because of the uncertainty associated with the consolidation state of gas hydrate-bearing sands. Small quantities of gas hydrate were observed in vertical fractures in shale. These occurrences are characterized by high formation resistivities with P-wave velocities close to those of water-saturated sediment. Because the formation factor varies significantly with respect to the gas hydrate saturation for vertical fractures at low saturations, an isotropic analysis of formation factor highly overestimates the gas hydrate saturation. Small quantities of gas hydrate in horizontal layers in shale are characterized by moderate increase in P-wave velocities and formation resistivities and either measurement can be used to estimate gas hydrate saturations.

The application of improved NeuroEvolution of Augmenting Topologies neural network in Marcellus Shale lithofacies prediction

NASA Astrophysics Data System (ADS)

Wang, Guochang; Cheng, Guojian; Carr, Timothy R.

2013-04-01

The organic-rich Marcellus Shale was deposited in a foreland basin during Middle Devonian. In terms of mineral composition and organic matter richness, we define seven mudrock lithofacies: three organic-rich lithofacies and four organic-poor lithofacies. The 3D lithofacies model is very helpful to determine geologic and engineering sweet spots, and consequently useful for designing horizontal well trajectories and stimulation strategies. The NeuroEvolution of Augmenting Topologies (NEAT) is relatively new idea in the design of neural networks, and shed light on classification (i.e., Marcellus Shale lithofacies prediction). We have successfully enhanced the capability and efficiency of NEAT in three aspects. First, we introduced two new attributes of node gene, the node location and recurrent connection (RCC), to increase the calculation efficiency. Second, we evolved the population size from an initial small value to big, instead of using the constant value, which saves time and computer memory, especially for complex learning tasks. Third, in multiclass pattern recognition problems, we combined feature selection of input variables and modular neural network to automatically select input variables and optimize network topology for each binary classifier. These improvements were tested and verified by true if an odd number of its arguments are true and false otherwise (XOR) experiments, and were powerful for classification.

Bedrock geologic map of the Nashua South quadrangle, Hillsborough County, New Hampshire, and Middlesex County, Massachusetts

USGS Publications Warehouse

Walsh, Gregory J.; Jahns, Richard H.; Aleinikoff, John N.

2013-01-01

The bedrock geology of the 7.5-minute Nashua South quadrangle consists primarily of deformed Silurian metasedimentary rocks of the Berwick Formation. The metasedimentary rocks are intruded by a Late Silurian to Early Devonian diorite-gabbro suite, Devonian rocks of the Ayer Granodiorite, Devonian granitic rocks of the New Hampshire Plutonic Suite including pegmatite and the Chelmsford Granite, and Jurassic diabase dikes. The bedrock geology was mapped to study the tectonic history of the area and to provide a framework for ongoing hydrogeologic characterization of the fractured bedrock of Massachusetts and New Hampshire. This report presents mapping by G.J. Walsh and R.H. Jahns and zircon U-Pb geochronology by J.N. Aleinikoff. The complete report consists of a map, text pamphlet, and GIS database. The map and text pamphlet are only available as downloadable files (see frame at right). The GIS database is available for download in ESRITM shapefile and Google EarthTM formats, and includes contacts of bedrock geologic units, faults, outcrops, structural geologic information, photographs, and a three-dimensional model.

Spontaneous imbibition of water and determination of effective contact angles in the Eagle Ford Shale Formation using neutron imaging

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

DiStefano, Victoria H.; Cheshire, Michael C.; McFarlane, Joanna

Understanding of fundamental processes and prediction of optimal parameters during the horizontal drilling and hydraulic fracturing process results in economically effective improvement of oil and natural gas extraction. Although, the modern analytical and computational models can capture fracture growth, there is a lack of experimental data on spontaneous imbibition and wettability in oil and gas reservoirs for the validation of further model development. In this work, we used neutron imaging to measure the spontaneous imbibition of water into fractures of Eagle Ford Shale with known geometries and fracture orientations. An analytical solution for a set of nonlinear second-order differential equationsmore » was applied to the measured imbibition data to determine effective contact angles. The analytical solution fit the measured imbibition data reasonably well and determined effective contact angles were slightly higher than static contact angles due to effects of in-situ changes in velocity, surface roughness, and heterogeneity of mineral surfaces on the fracture surface. Additionally, small fracture widths may have retarded imbibition and affected model fits, which suggests that average fracture widths are not satisfactory for modeling imbibition in natural systems.« less

Making Knowledge from Numbers : The Shale Network as an Honest Broker for Evaluating and Educating about the Impacts of Hydraulic Fracturing in the Marcellus Shale Region

NASA Astrophysics Data System (ADS)

Pollak, J.; Brantley, S.; Williams, J.; Dykhoff, S.; Brazil, L. I.

2015-12-01

The Marcellus Shale Network is an NSF-funded project that investigates the impacts of hydraulic fracturing for shale gas development on water resources in and around the state of Pennsylvania. It is a collaborative effort that aims to be an honest broker in the shale gas conversation by involving multiple entities (including universities, government agencies, industry groups, nonprofits, etc.) to collect, analyze, and disseminate data that describe the past and current conditions of water in the Marcellus shale region. A critical component of this project has been to engage multiple types of stakeholders - academia, government agencies, industry, and citizen science groups - in annual workshops to present and discuss how to ensure the integrity of water resources in light of the challenges that natural gas extraction can present. Each workshop has included a hands-on activity that allows participants to access water quality data using the tools provided by the CUAHSI Water Data Center. One of these tools is HydroDesktop, which is an open source GIS application that can be used in formal and informal education settings as a geoscience research tool. In addition to being a GIS, HydroDesktop accesses CUAHSI's large catalog of water data thus enabling students, professional researchers, and citizen scientists to discover data that can expand the understanding of water quality issues in one's local environment and beyond. This presentation will highlight the goals of the Shale Network project and the stakeholders involved in addition to how cyberinfrastructure is being used to create a democratic, data-driven conversation about the relationship between energy production from shale gas and our water resources.

Modeling of fault activation and seismicity by injection directly into a fault zone associated with hydraulic fracturing of shale-gas reservoirs

EPA Pesticide Factsheets

LBNL, in consultation with the EPA, expanded upon a previous study by injecting directly into a 3D representation of a hypothetical fault zone located in the geologic units between the shale-gas reservoir and the drinking water aquifer.

Stratigraphic and palaeoenvironmental summary of the south-east Georgia embayment: a correlation of exploratory wells

USGS Publications Warehouse

Poppe, Lawrence J.; Popenoe, Peter; Poag, C. Wylie; Swift, B. Ann

1995-01-01

A Continental Offshore Stratigraphic Test (COST) well and six exploratory wells have been drilled in the south-east Georgia embayment. The oldest rocks penetrated are weakly metamorphosed Lower Ordovician quartz arenites and Silurian shales and argillites in the Transco 1005-1 well and Upper Devonian argillites in the COST GE-1 well. These marine strata, which are equivalent to the Tippecanoe sequence in Florida, underlie the post-rift unconformity and represent part of a disjunct fragment of Gondwana that was sutured to the North American craton during the late Palaeozoic Alleghanian orogeny. The Palaeozoic strata are unconformably overlain by interbedded non-marine Jurassic (Bajocian and younger) sandstones and shales and marginal marine Lower Cretaceous sandstones, calcareous shales and carbonates, which contain scattered beds of coal and evaporite. Together, these rocks are stratigraphically equivalent to the onshore Fort Pierce and Cotton Valley(?) Formations and rocks of the Lower Cretaceous Comanchean Provincial Series. The abundance of carbonates and evaporites in this interval, which reflects marine influences within the embayment, increases upwards, eastwards and southwards. The Upper Cretaceous part of the section is composed mainly of neritic calcareous shales and shaley limestones stratigraphically equivalent to the primarily marginal marine facies of the onshore Atkinson, Cape Fear and Middendorf Formations and Black Creek Group, and to limestones and shales of the Lawson Limestone and Peedee Formations. Cenozoic strata are primarily semiconsolidated marine carbonates. Palaeocene to middle Eocene strata are commonly cherty; middle Miocene to Pliocene strata are massive and locally phosphatic and glauconitic; Quaternary sediments are dominated by unconsolidated carbonate sands. The effects of eustatic changes and shifts in the palaeocirculation are recorded in the Upper Cretaceous and Tertiary strata.

Comparison between results of detailed tectonic studies on borehole core vs microresistivity images of borehole wall from gas-bearing shale complexes, Baltic Basin, Poland.

NASA Astrophysics Data System (ADS)

Bobek, Kinga; Jarosiński, Marek; Pachytel, Radomir

2017-04-01

Structural analysis of borehole core and microresistivity images yield an information about geometry of natural fracture network and their potential importance for reservoir stimulation. Density of natural fractures and their orientation in respect to the maximum horizontal stress has crucial meaning for hydraulic fractures propagation in unconventional reservoirs. We have investigated several hundred meters of continuous borehole core and corresponding microresistivity images (mostly XRMI) from six boreholes in the Pomeranian part of the Early Paleozoic Baltic Basin. In general, our results challenge the question about representatives of statistics based on structural analyses on a small shale volume represented by borehole core or borehole wall images and credibility of different sets of data. Most frequently, fractures observed in both XRMI and cores are steep, small strata-bound fractures and veins with minor mechanical aperture (0,1 mm in average). These veins create an orthogonal joint system, locally disturbed by fractures associated with normal or by gently dipping thrust faults. Mean fractures' height keeps in a range between 30-50 cm. Fracture density differs significantly among boreholes and Consistent Lithological Units (CLUs) but the most frequent means falls in a range 2-4 m-1. We have also payed an attention to bedding planes due to their expected coupling with natural fractures and their role as structural barriers for vertical fracture propagation. We aimed in construction for each CLU the so-called "mean brick", which size is limited by an average distance between two principal joint sets and between bedding fractures. In our study we have found out a discrepancy between structural profiles based on XRMI and core interpretation. For some CLUs joint fractures densities, are higher in cores than in XRMI. In this case, numerous small fractures were not recorded due to the limits of XRMI resolution. However, the most veins with aperture 0,1 mm, cemented with calcite, were clearly visible in scanner image. We have also observed significantly lower density of veins in core than in the XRMI that occurs systematically in one formation enriched with carbonate and dolomite. In this case, veins are not fractured in core and obliterated for bare eye by dolomitization, but are still contrastive in respect of electric resistance. Calculated density of bedding planes per 1 meter reveals systematically higher density of fractures observed on core than in the XRMI (depicted automatically by interpretation program). This difference may come from additional fracking due to relaxation of borehole core while recovery. Comparison of vertical joint fractures density with thickness of mechanical beds shows either lack of significant trends or a negative correlation (greater density of bedding fractures correspond to lower density of joints). This result, obtained for shale complexes contradict that derived for sandstone or limestone. Boundary between CLUs are visible on both: joint and bedding fracture density profiles. Considering small-scale faults and slickensides we have obtained good agreement between results of core and scanner interpretation. This study in the frame of ShaleMech Project funded by Polish Committee for Scientific Research is in progress and the results are preliminary.

Guar Gum Stimulates Biogenic Sulfide Production at Elevated Pressures: Implications for Shale Gas Extraction

PubMed Central

Nixon, Sophie L.; Walker, Leanne; Streets, Matthew D. T.; Eden, Bob; Boothman, Christopher; Taylor, Kevin G.; Lloyd, Jonathan R.

2017-01-01

Biogenic sulfide production is a common problem in the oil industry, and can lead to costly hydrocarbon processing and corrosion of extraction infrastructure. The same phenomenon has recently been identified in shale gas extraction by hydraulic fracturing, and organic additives in fracturing fluid have been hypothesized to stimulate this process. Constraining the relative effects of the numerous organic additives on microbial metabolism in situ is, however, extremely challenging. Using a bespoke bioreactor system we sought to assess the potential for guar gum, the most commonly used gelling agent in fracturing fluids, to stimulate biogenic sulfide production by sulfate-reducing microorganisms at elevated pressure. Two pressurized bioreactors were fed with either sulfate-amended freshwater medium, or low-sulfate natural surface water, in addition to guar gum (0.05 w/v%) and an inoculum of sulfate-reducing bacteria for a period of 77 days. Sulfide production was observed in both bioreactors, even when the sulfate concentration was low. Analysis of 16S rRNA gene sequences indicate that heterotrophic bacteria closely associated with the genera Brevundimonas and Acinetobacter became enriched early in the bioreactor experiments, followed by an increase in relative abundance of 16S rRNA genes associated with sulfate-reducing bacteria (Desulfosporosinus and Desulfobacteraceae) at later time points. Results demonstrate that guar gum can stimulate acid- and sulfide-producing microorganisms at elevated pressure, and may have implications for the potential role in microbially induced corrosion during hydraulic fracturing operations. Key differences between experimental and in situ conditions are discussed, as well as additional sources of carbon and energy for biogenic sulfide production during shale gas extraction. Our laboratory approach can be tailored to better simulate deep subsurface conditions in order to probe the role of other fracturing fluid additives and downhole parameters on microbial metabolisms observed in these systems. Such baseline studies will prove essential for effective future development of shale gas worldwide. PMID:28469616

Guar Gum Stimulates Biogenic Sulfide Production at Elevated Pressures: Implications for Shale Gas Extraction.

PubMed

Nixon, Sophie L; Walker, Leanne; Streets, Matthew D T; Eden, Bob; Boothman, Christopher; Taylor, Kevin G; Lloyd, Jonathan R

2017-01-01

Biogenic sulfide production is a common problem in the oil industry, and can lead to costly hydrocarbon processing and corrosion of extraction infrastructure. The same phenomenon has recently been identified in shale gas extraction by hydraulic fracturing, and organic additives in fracturing fluid have been hypothesized to stimulate this process. Constraining the relative effects of the numerous organic additives on microbial metabolism in situ is, however, extremely challenging. Using a bespoke bioreactor system we sought to assess the potential for guar gum, the most commonly used gelling agent in fracturing fluids, to stimulate biogenic sulfide production by sulfate-reducing microorganisms at elevated pressure. Two pressurized bioreactors were fed with either sulfate-amended freshwater medium, or low-sulfate natural surface water, in addition to guar gum (0.05 w/v%) and an inoculum of sulfate-reducing bacteria for a period of 77 days. Sulfide production was observed in both bioreactors, even when the sulfate concentration was low. Analysis of 16S rRNA gene sequences indicate that heterotrophic bacteria closely associated with the genera Brevundimonas and Acinetobacter became enriched early in the bioreactor experiments, followed by an increase in relative abundance of 16S rRNA genes associated with sulfate-reducing bacteria ( Desulfosporosinus and Desulfobacteraceae) at later time points. Results demonstrate that guar gum can stimulate acid- and sulfide-producing microorganisms at elevated pressure, and may have implications for the potential role in microbially induced corrosion during hydraulic fracturing operations. Key differences between experimental and in situ conditions are discussed, as well as additional sources of carbon and energy for biogenic sulfide production during shale gas extraction. Our laboratory approach can be tailored to better simulate deep subsurface conditions in order to probe the role of other fracturing fluid additives and downhole parameters on microbial metabolisms observed in these systems. Such baseline studies will prove essential for effective future development of shale gas worldwide.

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.

Assessment of undiscovered oil and gas resources of the Ordovician Utica Shale of the Appalachian Basin Province, 2012

USGS Publications Warehouse

Kirschbaum, Mark A.; Schenk, Christopher J.; Cook, Troy A.; Ryder, Robert T.; Charpentier, Ronald R.; Klett, Timothy R.; Gaswirth, Stephanie B.; Tennyson, Marilyn E.; Whidden, Katherine J.

2012-01-01

The U.S. Geological Survey assessed unconventional oil and gas resources of the Upper Ordovician Utica Shale and adjacent units in the Appalachian Basin Province. The assessment covers parts of Maryland, New York, Ohio, Pennsylvania, Virginia, and West Virginia. The geologic concept is that black shale of the Utica Shale and adjacent units generated hydrocarbons from Type II organic material in areas that are thermally mature for oil and gas. The source rocks generated petroleum that migrated into adjacent units, but also retained significant hydrocarbons within the matrix and adsorbed to organic matter of the shale. These are potentially technically recoverable resources that can be exploited by using horizontal drilling combined with hydraulic fracturing techniques.

Community-based risk assessment of water contamination from high-volume horizontal hydraulic fracturing.

PubMed

Penningroth, Stephen M; Yarrow, Matthew M; Figueroa, Abner X; Bowen, Rebecca J; Delgado, Soraya

2013-01-01

The risk of contaminating surface and groundwater as a result of shale gas extraction using high-volume horizontal hydraulic fracturing (fracking) has not been assessed using conventional risk assessment methodologies. Baseline (pre-fracking) data on relevant water quality indicators, needed for meaningful risk assessment, are largely lacking. To fill this gap, the nonprofit Community Science Institute (CSI) partners with community volunteers who perform regular sampling of more than 50 streams in the Marcellus and Utica Shale regions of upstate New York; samples are analyzed for parameters associated with HVHHF. Similar baseline data on regional groundwater comes from CSI's testing of private drinking water wells. Analytic results for groundwater (with permission) and surface water are made publicly available in an interactive, searchable database. Baseline concentrations of potential contaminants from shale gas operations are found to be low, suggesting that early community-based monitoring is an effective foundation for assessing later contamination due to fracking.

Estimating the CO2 sequestration potential of depleted and fractured shale formations using CH4 production rates

NASA Astrophysics Data System (ADS)

Clarens, A. F.; Tao, Z.

2013-12-01

Oil and gas production from hydraulically fractured shale formations is an abundant new source of domestically available energy for the United States. It will also result in significant CO2 emissions with important climate implications. Several studies have suggested that fractured shale formations could be used to permanently store CO2 once they are depleted of hydrocarbons. Many of the largest shale formations being developed in the United States have temperature and pressure profiles that are similar to those of saline aquifers being widely studied for geologic carbon sequestration. Here a modeling framework was developed that can be used to estimate the sequestration capacity for a shale formation based on historical CH4 production. The model is applied to those portions of the Marcellus formation found in Pennsylvania because reliable data on well production is readily available for this state. Production data from over 300 wells was compiled and used to estimate historical production and to extrapolate projected production. In shales, much of the CO2 would be sorbed to the pore and fracture surface and so this model considers sorption kinetics as well as total sorption capacity. The results suggest that shale formations could represent a significant repository for geologic carbon sequestration. The Marcellus shale in Pennsylvania alone could store between 10.4 and 18.4 Gigatonnes of CO2 between now and 2030. This would be over 50% of total annual US CO2 emissions from stationary sources. The mass transfer and sorption kinetics results indicate that CO2 injection proceeds several times faster than CH4 production. Model estimates were most sensitive to the permeability of the formation and assumptions about the ultimate ratio of adsorbed CH4 to CO2. CH4 production is a useful basis for calculating sequestration capacity because gas mass transfer out of the formation will be impacted by the same factors (e.g., temperature, pressure, and moisture content) influencing gas injection. The differences between horizontal and non-horizontal wells were taken into account to understand how well structure would influence gas transport kinetics. It was assumed that only the sorbed CO2 would stay in the formation over time. These estimates for sequestration capacity suggest that the approach merits further study to understand the viability of this approach and opportunities to leverage existing infrastructure. Other synergies could exist in terms of monitoring. Related impacts associated with induced seismicity and leakage would need to be explored to understand the full potential of this approach. The sequestration capacity estimated using this model supports continued exploration into this pathway for producing carbon neutral energy.

Parameters controlling mechanical stratification of gas-bearing shale complexes: integration of wellbore logging and core profiling (Peri-Baltic Basin, Poland).

NASA Astrophysics Data System (ADS)

Pachytel, Radomir; Jarosiński, Marek; Bobek, Kinga; Roszkowska-Remin, Joanna; Roman, Michał

2016-04-01

In our study of mechanical properties of gas-bearing shale complexes from exploration wells in Pomerania, we take advantage from having access to continuous, several hundred meters long core profiles which are supplemented with complete sets of geophysical logging from the same shale intervals. We are focused on different approaches to discriminate the Consistent Mechanical Units (CMUs). Such units are essential for mechanical modeling of stress and strain in shales and their scale is highly dependent on the purpose of analyses. We have done a precise lithological and structural core profiling, which results in distinguishing Consistent Lithological Units (CLUs) at a centimeter scale. The geophysical logs, essential for mechanical studies, exhibit resolution from tens of centimeters to a meter. The meter resolution we have found appropriate for consideration of mechanics of hydraulic fracture propagation and therefore we have used it in CMUs analysis. The first challenge we have faced is to switch between scales of analyses without significant losses of information coming from the lower level of observation. The next challenge, is to find the mechanical parameter which is able to discriminate CMUs most efficiently. Brittleness Indexes (BIs) are commonly used parameters in order to characterize mechanical shale units, but at the same time these indexes are arbitrary defined to match individual requirements of the users. In our study, we have determined the BIs in several ways, based either on mineral composition or on elastic modules, both supplemented with pore volume. The gamma ray (GR), Young modulus (YM), Poisson Ratio (ν) interpretation from acoustic logging, bulk density (RHOB), porosity interpretation (ø) and mineralogical profile (ULTRA, GEM) from spectral logging were computed. Detailed comparison of lithological profile and discriminated CLUs with above logs led us to conclusions about geophysical representation of dolomite and silica lithified shale, organic matter enrichment tuffite layers or disturbances in lamination, which are important for mechanical differentiation of shale complexes. Finally, we have checked which of the calculated BIs matches best the lithological differentiation and the natural fracture density profile that allowed us for selection of the BI which, in our opinion, represents the potential for hydraulic fracture propagation. Our study in the frame of ShaleMech Project (Blue Gas Program) is in progress and the results are preliminary.

Sediment Sources, Depositional Environment, and Diagenetic Alteration of the Marcellus Shale, Appalachian Basin, USA: Nd, Sr, Li and U Isotopic Constraints

NASA Astrophysics Data System (ADS)

Phan, T. T.; Capo, R. C.; Gardiner, J. B.; Stewart, B. W.

2017-12-01

The organic-rich Middle Devonian Marcellus Shale in the Appalachian Basin, eastern USA, is a major target of natural gas exploration. Constraints on local and regional sediment sources, depositional environments, and post-depositional processes are essential for understanding the evolution of the basin. In this study, multiple proxies, including trace metals, rare earth elements (REE), the Sm-Nd and Rb-Sr isotope systems, and U and Li isotopes were applied to bulk rocks and authigenic fractions of the Marcellus Shale and adjacent limestone/sandstone units from two locations separated by 400 km. The range of ɛNd values (-7.8 to -6.4 at 390 Ma) is consistent with a clastic sedimentary component derived from a well-mixed source of fluvial and eolian material of the Grenville orogenic belt. The Sm-Nd isotope system and bulk REE distributions appear to have been minimally affected by post-depositional processes, while the Rb-Sr isotope system shows evidence of limited post-depositional redistribution. While REE are primarily associated with silicate minerals (80-95%), REE patterns of sequentially extracted fractions reflect post-depositional alteration at the intergranular scale. Although the chemical index of alteration (CIA = 54 to 60) suggests the sediment source was not heavily weathered, Li isotope data are consistent with progressively increasing weathering of the source region during Marcellus Shale deposition. δ238U values in bulk shale and reduced phases (oxidizable fraction) are higher than those of modern seawater and upper crust. The isotopically heavy U accumulated in these authigenic phases can be explained by the precipitation of insoluble U in anoxic/euxinic bottom water. Unlike carbonate cement within the shale, the similarity between δ238U values and REE patterns of the limestone units and those of modern seawater indicates that the limestone formed under open ocean (oxic) conditions.

Paleozoic oil/gas shale reservoirs in southern Tunisia: An overview

NASA Astrophysics Data System (ADS)

Soua, Mohamed

2014-12-01

During these last years, considerable attention has been given to unconventional oil and gas shale in northern Africa where the most productive Paleozoic basins are located (e.g. Berkine, Illizi, Kufra, Murzuk, Tindouf, Ahnet, Oued Mya, Mouydir, etc.). In most petroleum systems, which characterize these basins, the Silurian played the main role in hydrocarbon generation with two main 'hot' shale levels distributed in different locations (basins) and their deposition was restricted to the Rhuddanian (Lllandovery: early Silurian) and the Ludlow-Pridoli (late Silurian). A third major hot shale level had been identified in the Frasnian (Upper Devonian). Southern Tunisia is characterized by three main Paleozoic sedimentary basins, which are from North to South, the southern Chotts, Jeffara and Berkine Basin. They are separated by a major roughly E-W trending lower Paleozoic structural high, which encompass the Mehrez-Oued Hamous uplift to the West (Algeria) and the Nefusa uplift to the East (Libya), passing by the Touggourt-Talemzane-PGA-Bou Namcha (TTPB) structure close to southern Tunisia. The forementioned major source rocks in southern Tunisia are defined by hot shales with elevated Gamma ray values often exceeding 1400 API (in Hayatt-1 well), deposited in deep water environments during short lived (c. 2 Ma) periods of anoxia. In the course of this review, thickness, distribution and maturity maps have been established for each hot shale level using data for more than 70 wells located in both Tunisia and Algeria. Mineralogical modeling was achieved using Spectral Gamma Ray data (U, Th, K), SopectroLith logs (to acquire data for Fe, Si and Ti) and Elemental Capture Spectroscopy (ECS). The latter technique provided data for quartz, pyrite, carbonate, clay and Sulfur. In addition to this, the Gamma Ray (GR), Neutron Porosity (ΦN), deep Resistivity (Rt) and Bulk Density (ρb) logs were used to model bulk mineralogy and lithology. Biostratigraphic and complete geochemical review has been undertaken from published papers and unpublished internal reports to better assess these important source intervals.

The evolution of Devonian hydrocarbon gases in shallow aquifers of the northern Appalachian Basin: Insights from integrating noble gas and hydrocarbon geochemistry

NASA Astrophysics Data System (ADS)

Darrah, Thomas H.; Jackson, Robert B.; Vengosh, Avner; Warner, Nathaniel R.; Whyte, Colin J.; Walsh, Talor B.; Kondash, Andrew J.; Poreda, Robert J.

2015-12-01

The last decade has seen a dramatic increase in domestic energy production from unconventional reservoirs. This energy boom has generated marked economic benefits, but simultaneously evoked significant concerns regarding the potential for drinking-water contamination in shallow aquifers. Presently, efforts to evaluate the environmental impacts of shale gas development in the northern Appalachian Basin (NAB), located in the northeastern US, are limited by: (1) a lack of comprehensive ;pre-drill; data for groundwater composition (water and gas); (2) uncertainty in the hydrogeological factors that control the occurrence of naturally present CH4 and brines in shallow Upper Devonian (UD) aquifers; and (3) limited geochemical techniques to quantify the sources and migration of crustal fluids (specifically methane) at various time scales. To address these questions, we analyzed the noble gas, dissolved ion, and hydrocarbon gas geochemistry of 72 drinking-water wells and one natural methane seep all located ≫1 km from shale gas drill sites in the NAB. In the present study, we consciously avoided groundwater wells from areas near active or recent drilling to ensure shale gas development would not bias the results. We also intentionally targeted areas with naturally occurring CH4 to characterize the geochemical signature and geological context of gas-phase hydrocarbons in shallow aquifers of the NAB. Our data display a positive relationship between elevated [CH4], [C2H6], [Cl], and [Ba] that co-occur with high [4He]. Although four groundwater samples show mantle contributions ranging from 1.2% to 11.6%, the majority of samples have [He] ranging from solubility levels (∼45 × 10-6 cm3 STP/L) with below-detectable [CH4] and minor amounts of tritiogenic 3He in low [Cl] and [Ba] waters, up to high [4He] = 0.4 cm3 STP/L with a purely crustal helium isotopic end-member (3He/4He = ∼0.02 times the atmospheric ratio (R/Ra)) in samples with CH4 near saturation for shallow groundwater (P(CH4) = ∼1 atmosphere) and elevated [Cl] and [Ba]. These data suggest that 4He is dominated by an exogenous (i.e., migrated) crustal source for these hydrocarbon gas- and salt-rich fluids. In combination with published inorganic geochemistry (e.g., 87Sr/86Sr, Sr/Ba, Br-/Cl-), new noble gas and hydrocarbon isotopic data (e.g., 20Ne/36Ar, C2+/C1, δ13C-CH4) suggest that a hydrocarbon-rich brine likely migrated from the Marcellus Formation (via primary hydrocarbon migration) as a dual-phase fluid (gas + liquid) and was fractionated by solubility partitioning during fluid migration and emplacement into conventional UD traps (via secondary hydrocarbon migration). Based on the highly fractionated 4He/CH4 data relative to Marcellus and UD production gases, we propose an additional phase of hydrocarbon gas migration where natural gas previously emplaced in UD hydrocarbon traps actively diffuses out into and equilibrates with modern shallow groundwater (via tertiary hydrocarbon migration) following uplift, denudation, and neotectonic fracturing. These data suggest that by integrating noble gas geochemistry with hydrocarbon and dissolved ion chemistry, one can better determine the source and migration processes of natural gas in the Earth's crust, which are two critical factors for understanding the presence of hydrocarbon gases in shallow aquifers.

Petrophysical, Lithological and Mineralogical Characteristics of the Shale Strata of the Volga- Ural Region

NASA Astrophysics Data System (ADS)

Morozov, Vladimir P.; Plotnikova, Irina N.; Pronin, Nikita V.; Nosova, Fidania F.; Pronina, Nailya R.

2014-05-01

The objects of the study are Upper Devonian carbonate rocks in the territory of South-Tatar arch and Melekess basin in the Volga- Urals region. We studied core material of Domanicoid facies from the sediments of Mendymski and Domanik horizons of middle substage of Frasnian stage of the Upper Devonian. Basic analytical research methods included the following: study of the composition, structural and textural features of the rocks, the structure of their voids, filter and reservoir properties and composition of the fluid. The complex research consisted of macroscopic description of the core material, optical microscopy analysis, radiographical analysis, thermal analysis, x-ray tomography, electron microscopy, gas-liquid chromatography, chromate-mass spectrometry, light hydrocarbons analysis using paraphase assay, adsorbed gases analysis, and thermal vacuum degassing method. In addition, we performed isotopic studies of hydrocarbons saturating shale rocks. Shale strata are mainly represented by carbonate-chert rocks. They consist mainly of calcite and quartz. The ratio of these rock-forming minerals varies widely - from 25 to 75 percent. Pyrite, muscovite, albite, and microcline are the most common inclusions. Calcareous and ferruginous dolomite (ankerite), as well as magnesian calcite are tracked down as secondary minerals. While performing the tests we found out that the walls of open fractures filled with oil are stacked by secondary dolomite, which should be considered as an indication moveable oil presence in the open-cut. Electron microscopy data indicate that all the studied samples have porosity - both carbonates and carbonate-siliceous rocks. Idiomorphism of the rock-forming grains and pores that are visible under a microscope bring us to that conclusion. The analysis of the images indicates that the type of reservoir is either porous or granular. The pores are distributed evenly in the volume of rock. Their size is very unstable and varies from 0.5 microns to 100 microns. The lowest value are observed in long carbonate-siliceous rocks, the highest values are found in carbonate rocks. The latter is caused by the fact that there is a very strong recrystallization of calcite and its dolomite substitution in carbonates. Open porosity ranges from 0.65 to 7.98 percent, average value is 4.1percent . Effective porosity has an average value of 0.44 percent, ranging from 0.22 to 1.97. Permeability varies from 0.043 to 1.49 mD, average value is 0,191 mD. Organic matter was found in all samples. Its content varies within the section. The fluctuation range of from 1.0 to 20 percent. The lowest content of carbonates is found in carbonates, while the highest is observed in carbonate-siliceous rocks with a high content of chalcedony. Average organic matter content is 5-7 percent. According to Rock-Eval studies of the core, the catagenetic maturity of organic matter corresponds to MK1 - MK2 degree. We found a connection between the type of organic matter and the composition of adsorbed gas. We also could see that the samples with humic organics present in their organic matter and can be characterized by a fair dominance of methane over other gases. There is a clear relationship between organic matter content and the intensity of the gas saturation of the rock. Organic matter is characteristic mainly of the most siliceous formations. In "pure" carbonates, which are represented by micro-layers with different capacities, OM is not observed at all or its content is quite low.

Two-Stage Fracturing Wastewater Management in Shale Gas Development

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

Zhang, Xiaodong; Sun, Alexander Y.; Duncan, Ian J.

Here, management of shale gas wastewater treatment, disposal, and reuse has become a significant environmental challenge, driven by an ongoing boom in development of U.S. shale gas reservoirs. Systems-analysis based decision support is helpful for effective management of wastewater, and provision of cost-effective decision alternatives from a whole-system perspective. Uncertainties are inherent in many modeling parameters, affecting the generated decisions. In order to effectively deal with the recourse issue in decision making, in this work a two-stage stochastic fracturing wastewater management model, named TSWM, is developed to provide decision support for wastewater management planning in shale plays. Using the TSWMmore » model, probabilistic and nonprobabilistic uncertainties are effectively handled. The TSWM model provides flexibility in generating shale gas wastewater management strategies, in which the first-stage decision predefined by decision makers before uncertainties are unfolded is corrected in the second stage to achieve the whole-system’s optimality. Application of the TSWM model to a comprehensive synthetic example demonstrates its practical applicability and feasibility. Optimal results are generated for allowable wastewater quantities, excess wastewater, and capacity expansions of hazardous wastewater treatment plants to achieve the minimized total system cost. The obtained interval solutions encompass both optimistic and conservative decisions. Trade-offs between economic and environmental objectives are made depending on decision makers’ knowledge and judgment, as well as site-specific information. In conclusion, the proposed model is helpful in forming informed decisions for wastewater management associated with shale gas development.« less

Two-Stage Fracturing Wastewater Management in Shale Gas Development

DOE PAGES

Zhang, Xiaodong; Sun, Alexander Y.; Duncan, Ian J.; ...

2017-01-19

Here, management of shale gas wastewater treatment, disposal, and reuse has become a significant environmental challenge, driven by an ongoing boom in development of U.S. shale gas reservoirs. Systems-analysis based decision support is helpful for effective management of wastewater, and provision of cost-effective decision alternatives from a whole-system perspective. Uncertainties are inherent in many modeling parameters, affecting the generated decisions. In order to effectively deal with the recourse issue in decision making, in this work a two-stage stochastic fracturing wastewater management model, named TSWM, is developed to provide decision support for wastewater management planning in shale plays. Using the TSWMmore » model, probabilistic and nonprobabilistic uncertainties are effectively handled. The TSWM model provides flexibility in generating shale gas wastewater management strategies, in which the first-stage decision predefined by decision makers before uncertainties are unfolded is corrected in the second stage to achieve the whole-system’s optimality. Application of the TSWM model to a comprehensive synthetic example demonstrates its practical applicability and feasibility. Optimal results are generated for allowable wastewater quantities, excess wastewater, and capacity expansions of hazardous wastewater treatment plants to achieve the minimized total system cost. The obtained interval solutions encompass both optimistic and conservative decisions. Trade-offs between economic and environmental objectives are made depending on decision makers’ knowledge and judgment, as well as site-specific information. In conclusion, the proposed model is helpful in forming informed decisions for wastewater management associated with shale gas development.« less

Modeling Dynamic Helium Release as a Tracer of Rock Deformation

DOE PAGES

Gardner, W. Payton; Bauer, Stephen J.; Kuhlman, Kristopher L.; ...

2017-11-03

Here, we use helium released during mechanical deformation of shales as a signal to explore the effects of deformation and failure on material transport properties. A dynamic dual-permeability model with evolving pore and fracture networks is used to simulate gases released from shale during deformation and failure. Changes in material properties required to reproduce experimentally observed gas signals are explored. We model two different experiments of 4He flow rate measured from shale undergoing mechanical deformation, a core parallel to bedding and a core perpendicular to bedding. We also found that the helium signal is sensitive to fracture development and evolutionmore » as well as changes in the matrix transport properties. We constrain the timing and effective fracture aperture, as well as the increase in matrix porosity and permeability. Increases in matrix permeability are required to explain gas flow prior to macroscopic failure, and the short-term gas flow postfailure. Increased matrix porosity is required to match the long-term, postfailure gas flow. This model provides the first quantitative interpretation of helium release as a result of mechanical deformation. The sensitivity of this model to changes in the fracture network, as well as to matrix properties during deformation, indicates that helium release can be used as a quantitative tool to evaluate the state of stress and strain in earth materials.« less

Modeling Dynamic Helium Release as a Tracer of Rock Deformation

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

Gardner, W. Payton; Bauer, Stephen J.; Kuhlman, Kristopher L.

Here, we use helium released during mechanical deformation of shales as a signal to explore the effects of deformation and failure on material transport properties. A dynamic dual-permeability model with evolving pore and fracture networks is used to simulate gases released from shale during deformation and failure. Changes in material properties required to reproduce experimentally observed gas signals are explored. We model two different experiments of 4He flow rate measured from shale undergoing mechanical deformation, a core parallel to bedding and a core perpendicular to bedding. We also found that the helium signal is sensitive to fracture development and evolutionmore » as well as changes in the matrix transport properties. We constrain the timing and effective fracture aperture, as well as the increase in matrix porosity and permeability. Increases in matrix permeability are required to explain gas flow prior to macroscopic failure, and the short-term gas flow postfailure. Increased matrix porosity is required to match the long-term, postfailure gas flow. This model provides the first quantitative interpretation of helium release as a result of mechanical deformation. The sensitivity of this model to changes in the fracture network, as well as to matrix properties during deformation, indicates that helium release can be used as a quantitative tool to evaluate the state of stress and strain in earth materials.« less

Environmental consequences of shale gas exploitation and the crucial role of rock microfracturing

NASA Astrophysics Data System (ADS)

Renard, Francois

2015-04-01

The growing exploitation of unconventional gas and oil resources has dramatically changed the international market of hydrocarbons in the past ten years. However, several environmental concerns have also been identified such as the increased microseismicity, the leakage of gas into freshwater aquifers, and the enhanced water-rock interactions inducing the release of heavy metals and other toxic elements in the produced water. In all these processes, fluids are transported into a network of fracture, ranging from nanoscale microcracks at the interface between minerals and the kerogen of the source rock, to well-developed fractures at the meter scale. Characterizing the fracture network and the mechanisms of its formation remains a crucial goal. A major difficulty when analyzing fractures from core samples drilled at depth is that some of them are produced by the coring process, while some other are produced naturally at depth by the coupling between geochemical and mechanical forces. Here, I present new results of high resolution synchrotron 3D X-ray microtomography imaging of shale samples, at different resolutions, to characterize their microfractures and their mechanisms of formation. The heterogeneities of rock microstructure are also imaged, as they create local stress concentrations where cracks may nucleate or along which they propagate. The main results are that microcracks form preferentially along kerogen-mineral interfaces and propagate along initial heterogeneities according to the local stress direction, connecting to increase the total volume of fractured rock. Their lifetime is also an important parameter because they may seal by fluid circulation, fluid-rock interactions, and precipitation of a cement. Understanding the multi-scale processes of fracture network development in shales and the coupling with fluid circulation represents a key challenge for future research directions.

Integration of Water Resource Models with Fayetteville Shale Decision Support and Information System

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

Cothren, Jackson; Thoma, Greg; DiLuzio, Mauro

2013-06-30

Significant issues can arise with the timing, location, and volume of surface water withdrawals associated with hydraulic fracturing of gas shale reservoirs as impacted watersheds may be sensitive, especially in drought years, during low flow periods, or during periods of the year when activities such as irrigation place additional demands on the surface supply of water. Significant energy production and associated water withdrawals may have a cumulative impact to watersheds over the short-term. Hence, hydraulic fracturing based on water withdrawal could potentially create shifts in the timing and magnitude of low or high flow events or change the magnitude ofmore » river flow at daily, monthly, seasonal, or yearly time scales. These changes in flow regimes can result in dramatically altered river systems. Currently little is known about the impact of fracturing on stream flow behavior. Within this context the objective of this study is to assess the impact of the hydraulic fracturing on the water balance of the Fayetteville Shale play area and examine the potential impacts of hydraulic fracturing on river flow regime at subbasin scale. This project addressed that need with four unique but integrated research and development efforts: 1) Evaluate the predictive reliability of the Soil and Water Assessment Tool (SWAT) model based at a variety of scales (Task/Section 3.5). The Soil and Water Assessment Tool (SWAT) model was used to simulate the across-scale water balance and the respective impact of hydraulic fracturing. A second hypothetical scenario was designed to assess the current and future impacts of water withdrawals for hydraulic fracturing on the flow regime and on the environmental flow components (EFCs) of the river. The shifting of these components, which present critical elements to water supply and water quality, could influence the ecological dynamics of river systems. For this purpose, we combined the use of SWAT model and Richter et al.’s (1996) methodology to assess the shifting and alteration of the flow regime within the river and streams of the study area. 2) Evaluate the effect of measurable land use changes related to gas development (well-pad placement, access road completion, etc.) on surface water flow in the region (Task/Section 3.7). Results showed that since the upsurge in shale-gas related activities in the Fayetteville Shale Play (between 2006 and 2010), shale-gas related infrastructure in the region have increase by 78%. This change in land-cover in comparison with other land-cover classes such as forest, urban, pasture, agricultural and water indicates the highest rate of change in any land-cover category for the study period. A Soil and Water Assessment Tool (SWAT) flow model of the Little Red River watershed simulated from 2000 to 2009 showed a 10% increase in storm water runoff. A forecast scenario based on the assumption that 2010 land-cover does not see any significant change over the forecast period (2010 to 2020) also showed a 10% increase in storm water runoff. Further analyses showed that this change in the stream-flow regime for the forecast period is attributable to the increase in land-cover as introduced by the shale-gas infrastructure. 3) Upgrade the Fayetteville Shale Information System to include information on watershed status. (Tasks/Sections 2.1 and 2.2). This development occurred early in the project period, and technological improvements in web-map API’s have made it possible to further improve the map. The current sites (http://lingo.cast.uark.edu) is available but is currently being upgraded to a more modern interface and robust mapping engine using funds outside this project. 4) Incorporate the methodologies developed in Tasks/Sections 3.5 and 3.7 into a Spatial Decision Support System for use by regulatory agencies and producers in the play. The resulting system is available at http://fayshale.cast.uark.edu and is under review the Arkansas Natural Resources Commission.« less

Impacts on water quality by hydraulic fracturing in Pennsylvania

NASA Astrophysics Data System (ADS)

Yan, B.; Stute, M.; Chillrud, S. N.; Ross, J. M.; Howarth, M.; Panettieri, R.; Saberi, P.

2015-12-01

Shale gas development, including drilling and hydraulic fracturing, is rapidly increasing throughout the United States and, indeed, the rest of the world. Systematic surveys of water quality both pre- and post drilling/production are sparse. To examine the impacts of shale gas production on water quality, pilot studies have been conducted in adjacent counties of western NY (Chemung, Tioga, Broome, and Delaware) and northern PA (Bradford, Susquehanna, and Wayne). These 7 counties along the border of NY and PA share similar geology and demographic compositions and have been identified as a key area to develop shale gas with the key difference that active fracking is occurring in PA but there is no fracking yet in NY. Measurements include a suite of major and trace elements, methane and its stable isotopes, noble gases and tritium for dating purposes, and the primary radioactive elements of potential concern, radon and radium. We found elevated methane levels on both sides of the border. Higher levels of major ions were observed in PA samples close to the gas wells in the valley, possibly from hydraulic fracturing activities. The lab analysis of samples collected in recently launched 100 Bottom Project is ongoing and the results will be presented in this conference.

Adsorption of hydraulic fracturing fluid components 2-butoxyethanol and furfural onto granular activated carbon and shale rock.

PubMed

Manz, Katherine E; Haerr, Gregory; Lucchesi, Jessica; Carter, Kimberly E

2016-12-01

The objective of this study was to understand the adsorption ability of a surfactant and a non-surfactant chemical additive used in hydraulic fracturing onto shale and GAC. Experiments were performed at varying temperatures and sodium chloride concentrations to establish these impacts on the adsorption of the furfural (a non-surfactant) and 2-Butoxyethanol (2-BE) (a surfactant). Experiments were carried out in continuously mixed batch experiments with Langmuir and Freundlich isotherm modeling. The results of the experiments showed that adsorption of these compounds onto shale does not occur, which may allow these compounds to return to the surface in flowback and produced waters. The adsorption potential for these chemicals onto GAC follows the assumptions of the Langmuir model more strongly than those of the Freundlich model. The results show uptake of furfural and 2-BE occurs within 23 h in the presence of DI water, 0.1 mol L -1 sodium chloride, and in lab synthesized hydraulic fracturing brine. Based on the data, 83% of the furfural and 62% of the 2-BE was adsorbed using GAC. Copyright © 2016 Elsevier Ltd. All rights reserved.

Element mobilization from Bakken shales as a function of water chemistry.

PubMed

Wang, Lin; Burns, Scott; Giammar, Daniel E; Fortner, John D

2016-04-01

Waters that return to the surface after injection of a hydraulic fracturing fluid for gas and oil production contain elements, including regulated metals and metalloids, which are mobilized through interactions between the fracturing fluid and the shale formation. The rate and extent of mobilization depends on the geochemistry of the formation and the chemical characteristics of the fracturing fluid. In this work, laboratory scale experiments investigated the influence of water chemistry on element mobilization from core samples taken from the Bakken formation, one of the most productive shale oil plays in the US. Fluid properties were systematically varied and evaluated with regard to pH, oxidant level, solid:water ratio, temperature, and chemical additives. Element mobilization strongly depended on solution pH and redox conditions and to a lesser extent on the temperature and solid:water ratio. The presence of oxygen and addition of hydrogen peroxide or ammonium persulfate led to pyrite oxidation, resulting in elevated sulfate concentrations. Further, depending on the mineral carbonates available to buffer the system pH, pyrite oxidation could lower the system pH and enhance the mobility of several metals and metalloids. Copyright © 2016 Elsevier Ltd. All rights reserved.

Investigating the Potential Impacts of Energy Production in the Marcellus Shale Region Using the Shale Network Database

NASA Astrophysics Data System (ADS)

Brantley, S.; Pollak, J.

2016-12-01

The Shale Network's extensive database of water quality observations in the Marcellus Shale region enables educational experiences about the potential impacts of resource extraction and energy production with real data. Through tools that are open source and free to use, interested parties can access and analyze the very same data that the Shale Network team has used in peer-reviewed publications about the potential impacts of hydraulic fracturing on water. The development of the Shale Network database has been made possible through efforts led by an academic team and involving numerous individuals from government agencies, citizen science organizations, and private industry. With these tools and data, the Shale Network team has engaged high school students, university undergraduate and graduate students, as well as citizens so that all can discover how energy production impacts the Marcellus Shale region, which includes Pennsylvania and other nearby states. This presentation will describe these data tools, how the Shale Network has used them in educational settings, and the resources available to learn more.

Spatial arrangement of faults and opening-mode fractures

NASA Astrophysics Data System (ADS)

Laubach, S. E.; Lamarche, J.; Gauthier, B. D. M.; Dunne, W. M.; Sanderson, David J.

2018-03-01

Spatial arrangement is a fundamental characteristic of fracture arrays. The pattern of fault and opening-mode fracture positions in space defines structural heterogeneity and anisotropy in a rock volume, governs how faults and fractures affect fluid flow, and impacts our understanding of the initiation, propagation and interactions during the formation of fracture patterns. This special issue highlights recent progress with respect to characterizing and understanding the spatial arrangements of fault and fracture patterns, providing examples over a wide range of scales and structural settings. Five papers describe new methods and improvements of existing techniques to quantify spatial arrangement. One study unravels the time evolution of opening-mode fracture spatial arrangement, which are data needed to compare natural patterns with progressive fracture growth in kinematic and mechanical models. Three papers investigate the role of evolving diagenesis in localizing fractures by mechanical stratigraphy and nine discuss opening-mode fracture spatial arrangement. Two papers show the relevance of complex cluster patterns to unconventional reservoirs through examples of fractures in tight gas sandstone horizontal wells, and a study of fracture arrangement in shale. Four papers demonstrate the roles of folds in fracture localization and the development spatial patterns. One paper models along-fault friction and fluid pressure and their effects on fault-related fracture arrangement. Contributions address deformation band patterns in carbonate rocks and fault size and arrangement above a detachment fault. Three papers describe fault and fracture arrangements in basement terrains, and three document fracture patterns in shale. This collection of papers points toward improvement in field methods, continuing improvements in computer-based data analysis and creation of synthetic fracture patterns, and opportunities for further understanding fault and fracture attributes in the subsurface through coupled spatial, size, and pattern analysis.

A Guide for Selecting Remedies for Subsurface Releases of Chlorinated Solvents

DTIC Science & Technology

2011-03-01

exception of secondary permeability features (e.g., fractures , root holes, animal burrows), high displacement pressures typically preclude DNAPL from...1 to 40 percent. Fractured media with high matrix porosity are commonly encountered in sedimentary rock (e.g., limestone, dolomite , shale, and...Low Permeability .......... 21 Type III – Granular Media with Moderate to High Heterogeneity ........................ 21 Type IV - Fractured Media

Draft Genome Sequence of Methanohalophilus mahii Strain DAL1 Reconstructed from a Hydraulic Fracturing-Produced Water Metagenome

PubMed Central

Lipus, Daniel; Vikram, Amit

2016-01-01

We report here the 1,882,100-bp draft genome sequence of Methanohalophilus mahii strain DAL1, recovered from Marcellus Shale hydraulic fracturing-produced water using metagenomic contig binning. Genome annotation revealed several key methanogenesis genes and provides valuable information on archaeal activity associated with hydraulic fracturing-produced water environments. PMID:27587817

The Influence of Fracturing Fluids on Fracturing Processes: A Comparison Between Water, Oil and SC-CO2

NASA Astrophysics Data System (ADS)

Wang, Jiehao; Elsworth, Derek; Wu, Yu; Liu, Jishan; Zhu, Wancheng; Liu, Yu

2018-01-01

Conventional water-based fracturing treatments may not work well for many shale gas reservoirs. This is due to the fact that shale gas formations are much more sensitive to water because of the significant capillary effects and the potentially high contents of swelling clay, each of which may result in the impairment of productivity. As an alternative to water-based fluids, gaseous stimulants not only avoid this potential impairment in productivity, but also conserve water as a resource and may sequester greenhouse gases underground. However, experimental observations have shown that different fracturing fluids yield variations in the induced fracture. During the hydraulic fracturing process, fracturing fluids will penetrate into the borehole wall, and the evolution of the fracture(s) then results from the coupled phenomena of fluid flow, solid deformation and damage. To represent this, coupled models of rock damage mechanics and fluid flow for both slightly compressible fluids and CO2 are presented. We investigate the fracturing processes driven by pressurization of three kinds of fluids: water, viscous oil and supercritical CO2. Simulation results indicate that SC-CO2-based fracturing indeed has a lower breakdown pressure, as observed in experiments, and may develop fractures with greater complexity than those developed with water-based and oil-based fracturing. We explore the relation between the breakdown pressure to both the dynamic viscosity and the interfacial tension of the fracturing fluids. Modeling demonstrates an increase in the breakdown pressure with an increase both in the dynamic viscosity and in the interfacial tension, consistent with experimental observations.

Re-injection feasibility study of fracturing flow-back fluid in shale gas mining

NASA Astrophysics Data System (ADS)

Kang, Dingyu; Xue, Chen; Chen, Xinjian; Du, Jiajia; Shi, Shengwei; Qu, Chengtun; Yu, Tao

2018-02-01

Fracturing flow-back fluid in shale gas mining is usually treated by re-injecting into formation. After treatment, the fracturing flow-back fluid is injected back into the formation. In order to ensure that it will not cause too much damage to the bottom layer, feasibility evaluations of re-injection of two kinds of fracturing fluid with different salinity were researched. The experimental research of the compatibility of mixed water samples based on the static simulation method was conducted. Through the analysis of ion concentration, the amount of scale buildup and clay swelling rate, the feasibility of re-injection of different fracturing fluid were studied. The result shows that the swelling of the clay expansion rate of treated fracturing fluid is lower than the mixed water of treated fracturing fluid and the distilled water, indicating that in terms of clay expansion rate, the treated fracturing flow-back fluid is better than that of water injection after re-injection. In the compatibility test, the maximum amount of fouling in the Yangzhou oilfield is 12mg/L, and the maximum value of calcium loss rate is 1.47%, indicating that the compatibility is good. For the fracturing fluid with high salinity in the Yanchang oilfield, the maximum amount of scaling is 72mg/L, and the maximum calcium loss rate is 3.50%, indicating that the compatibility is better.

Evaporite karst of northern lower Michigan

USGS Publications Warehouse

Black, T.J.

1997-01-01

Michigan has three main zones of evaporite karst: collapse breccia in Late Silurian deposits of the Mackinac Straits region; breccia, collapse sinks, and mega-block collapse in Middle Devonian deposits of Northern Lower Michigan, which overlaps the preceding area; and areas of soil swallows in sinks of Mississippian deposits between Turner and Alabaster in Arenac and Iosco counties, and near Grand Rapids in Kent County. The author has focused his study on evaporite karst of the Middle Devonian deposits. The Middle Devonian depos its are the Detroit River Group: a series consisting of limestone, dolomite, shale, salt, gypsum, and anhydrite. The group occurs from subcrop, near the surface, to nearly 1400 feet deep from the northern tip of the Southern Peninsula to the south edge of the "solution front" Glacial drift is from zero to 350 feet thick. Oil and gas exploration has encountered some significant lost-circulation zones throughout the area. Drilling without fluid returns, casing-seal failures, and lost holes are strong risks in some parts of the region. Lost fluid returns near the top of the group in nearby areas indicate some karst development shortly after deposition. Large and irregular lost-circulation zones, linear and patch trends of large sink holes, and 0.25 mile wide blocks of down-dropped land in the northern Lower Peninsula of Michigan were caused by surface- and ground-water movement along faults into the Detroit River Group. Glaciation has removed some evidence of the karst area at the surface. Sinkhole development, collapse valleys, and swallows developed since retreat of the glacier reveal an active solution front in the Detroit River Group.

Increased likelihood of induced seismicity in highly overpressured shale formations

NASA Astrophysics Data System (ADS)

Eaton, David W.; Schultz, Ryan

2018-05-01

Fluid-injection processes such as disposal of saltwater or hydraulic fracturing can induce earthquakes by increasing pore pressure and/or shear stress on faults. Natural processes, including transformation of organic material (kerogen) into hydrocarbon and cracking to produce gas, can similarly cause fluid overpressure. Here we document two examples from the Western Canada Sedimentary Basin where earthquakes induced by hydraulic fracturing are strongly clustered within areas characterized by pore-pressure gradient in excess of 15 kPa/m. Despite extensive hydraulic-fracturing activity associated with resource development, induced earthquakes are virtually absent in the Montney and Duvernay Formations elsewhere. Statistical analysis suggests a negligible probability that this spatial correlation developed by chance. This implies that, in addition to known factors such as anthropogenic pore-pressure increase and proximity to critically stressed faults, high in-situ overpressure of shale formations may also represent a controlling factor for inducing earthquakes by hydraulic fracturing. On a geological timescale, natural pore-pressure generation may lead to fault-slip episodes that regulate magnitude of formation-overpressure.

The impact of intensity on perceived risk from unconventional shale gas development.

PubMed

Livy, Mitchell R; Gopalakrishnan, Sathya; Klaiber, H Allen; Roe, Brian E

2018-07-15

The recent boom in the extraction of natural gas from subsurface shale deposits due to advances in hydraulic fracturing and horizontal drilling technologies has raised concern around environmental risks. Reliable measures of how residents view these risks are therefore a necessary first step in evaluating policies that regulate the industry through risk mitigation measures. We conduct a choice experiment targeting residents in an area of Ohio with significant shale drilling activity, and find that households are willing to pay to avoid high intensities of shale development and truck traffic. Our analysis presents new policy-relevant evidence of preferences associated with unconventional shale gas reserves, and highlights the tradeoffs between activity intensity at each site and the number of sites in aggregate. Copyright © 2018 Elsevier Ltd. All rights reserved.

Studying Petrophysical and Geomechanical Properties of Utica Point-Pleasant Shale and its Variations Across the Northern Appalachian Basin

NASA Astrophysics Data System (ADS)

Raziperchikolaee, S.; Kelley, M. E.; Burchwell, A.

2017-12-01

Understanding petrophysical and geomechanical parameters of shale formations and their variations across the basin are necessary to optimize the design of a hydraulic fracturing program aimed at enhancing long term oil/gas production from unconventional wells. Dipole sonic logging data (compressional-wave and shear-wave slowness) from multiple wells across the study area, coupled with formation bulk density log data, were used to calculate dynamic elastic parameters, including shear modulus, bulk modulus, Poisson's ratio, and Young's modulus for the shale formations. The individual-well data were aggregated into a single histogram for each parameter to gain an understanding of the variation in the properties (including brittleness) of the Utica Point-Pleasant formations across the entire study area. A crossplot of the compressional velocity and bulk density and a crossplot between the compressional velocity, the shear velocity, and depth of the measurement were used for a high level petrophysical characterization of the Utica Point-Pleasant. Detailed interpretation of drilling induced fractures recorded in image logs, and an analysis of shear wave anisotropy using multi-receiver sonic logs were also performed. Orientation of drilling induced fractures was measured to determine the maximum horizontal stress azimuth. Also, an analysis of shear wave anisotropy to predict stress anisotropy around the wellbore was performed to determine the direction of maximum horizontal stress. Our study shows how the detailed interpretation of borehole breakouts, drilling induced fractures, and sonic wave data can be used to reduce uncertainty and produce a better hydraulic fracturing design in the Utica Point Pleasant formations across the northern Appalachian Basin region of Ohio.

Shallow Aquifer Vulnerability From Subsurface Fluid Injection at a Proposed Shale Gas Hydraulic Fracturing Site

NASA Astrophysics Data System (ADS)

Wilson, M. P.; Worrall, F.; Davies, R. J.; Hart, A.

2017-11-01

Groundwater flow resulting from a proposed hydraulic fracturing (fracking) operation was numerically modeled using 91 scenarios. Scenarios were chosen to be a combination of hydrogeological factors that a priori would control the long-term migration of fracking fluids to the shallow subsurface. These factors were induced fracture extent, cross-basin groundwater flow, deep low hydraulic conductivity strata, deep high hydraulic conductivity strata, fault hydraulic conductivity, and overpressure. The study considered the Bowland Basin, northwest England, with fracking of the Bowland Shale at ˜2,000 m depth and the shallow aquifer being the Sherwood Sandstone at ˜300-500 m depth. Of the 91 scenarios, 73 scenarios resulted in tracked particles not reaching the shallow aquifer within 10,000 years and 18 resulted in travel times less than 10,000 years. Four factors proved to have a statistically significant impact on reducing travel time to the aquifer: increased induced fracture extent, absence of deep high hydraulic conductivity strata, relatively low fault hydraulic conductivity, and magnitude of overpressure. Modeling suggests that high hydraulic conductivity formations can be more effective barriers to vertical flow than low hydraulic conductivity formations. Furthermore, low hydraulic conductivity faults can result in subsurface pressure compartmentalization, reducing horizontal groundwater flow, and encouraging vertical fluid migration. The modeled worst-case scenario, using unlikely geology and induced fracture lengths, maximum values for strata hydraulic conductivity and with conservative tracer behavior had a particle travel time of 130 years to the base of the shallow aquifer. This study has identified hydrogeological factors which lead to aquifer vulnerability from shale exploitation.

Microchemical evidence for episodic growth of antitaxial veins during fracture-controlled fluid flow

NASA Astrophysics Data System (ADS)

Barker, Shaun L. L.; Cox, Stephen F.; Eggins, Stephen M.; Gagan, Michael K.

2006-10-01

The mechanism by which syntectonic hydrothermal veins form is widely debated, with some workers suggesting that certain vein textures are related to specific fluid flow regimes. Central to the debate is whether vein formation involves advective fluid flow, or occurs by local diffusion of material from the surrounding wall rock. To address this issue, we integrated textural observations and microchemical analyses of a hydrothermal vein from the Lachlan Orogen, southeast Australia, to reveal information about vein growth history, changes in fluid chemistry, and the evolution of fluid flow pathways during vein growth. The study area is part of a regional-scale fault-fracture network in an interbedded limestone-shale sequence, which formed at depths of ˜ 5-10 km (˜ 150-200 °C) during late Devonian crustal shortening. This integrated approach demonstrates that the zonation of textures, Sr isotopes, stable isotopes (C, O), and trace and rare earth elements is distinctly asymmetrical about the median growth-line of the vein. δ 18O values in vein calcite (17.0-18.8‰, VSMOW) are lower than those in surrounding unaltered limestones (23-25‰, VSMOW), and vary systematically across the vein. In contrast, δ 13C values are relatively constant across most of the vein, but become markedly depleted ( ca. 4‰) immediately adjacent to the wall rock. This strong depletion in δ 13C was probably caused by the influx of more oxidised fluids during the latest stages of vein growth. Strontium isotope ratios ( 87Sr/ 86Sr) vary between 0.70912 and 0.70931 across the vein. Abrubt changes in 87Sr/ 86Sr, δ 18O, Ce/Ce *, Eu/Eu * and trace element concentrations indicate that vein growth was accompanied by stepwise changes in the fluid flow pathway and consequent variations in fluid chemistry. Taken together, our findings are not consistent with growth of fibrous antitaxial veins by diffusional transfer of material from the surrounding wall rock. Instead, they suggest that externally sourced fluids migrated along episodically changing fracture-controlled flow pathways. This has implications for the dynamics of crustal permeability and mineralisation.

Sulfide Generation by Dominant Halanaerobium Microorganisms in Hydraulically Fractured Shales

PubMed Central

Booker, Anne E.; Borton, Mikayla A.; Daly, Rebecca A.; Welch, Susan A.; Nicora, Carrie D.; Hoyt, David W.; Wilson, Travis; Purvine, Samuel O.; Wolfe, Richard A.; Sharma, Shikha; Mouser, Paula J.; Cole, David R.; Lipton, Mary S.; Wrighton, Kelly C.

2017-01-01

ABSTRACT Hydraulic fracturing of black shale formations has greatly increased United States oil and natural gas recovery. However, the accumulation of biomass in subsurface reservoirs and pipelines is detrimental because of possible well souring, microbially induced corrosion, and pore clogging. Temporal sampling of produced fluids from a well in the Utica Shale revealed the dominance of Halanaerobium strains within the in situ microbial community and the potential for these microorganisms to catalyze thiosulfate-dependent sulfidogenesis. From these field data, we investigated biogenic sulfide production catalyzed by a Halanaerobium strain isolated from the produced fluids using proteogenomics and laboratory growth experiments. Analysis of Halanaerobium isolate genomes and reconstructed genomes from metagenomic data sets revealed the conserved presence of rhodanese-like proteins and anaerobic sulfite reductase complexes capable of converting thiosulfate to sulfide. Shotgun proteomics measurements using a Halanaerobium isolate verified that these proteins were more abundant when thiosulfate was present in the growth medium, and culture-based assays identified thiosulfate-dependent sulfide production by the same isolate. Increased production of sulfide and organic acids during the stationary growth phase suggests that fermentative Halanaerobium uses thiosulfate to remove excess reductant. These findings emphasize the potential detrimental effects that could arise from thiosulfate-reducing microorganisms in hydraulically fractured shales, which are undetected by current industry-wide corrosion diagnostics. IMPORTANCE Although thousands of wells in deep shale formations across the United States have been hydraulically fractured for oil and gas recovery, the impact of microbial metabolism within these environments is poorly understood. Our research demonstrates that dominant microbial populations in these subsurface ecosystems contain the conserved capacity for the reduction of thiosulfate to sulfide and that this process is likely occurring in the environment. Sulfide generation (also known as “souring”) is considered deleterious in the oil and gas industry because of both toxicity issues and impacts on corrosion of the subsurface infrastructure. Critically, the capacity for sulfide generation via reduction of sulfate was not detected in our data sets. Given that current industry wellhead tests for sulfidogenesis target canonical sulfate-reducing microorganisms, these data suggest that new approaches to the detection of sulfide-producing microorganisms may be necessary. PMID:28685163

Sulfide Generation by Dominant Halanaerobium Microorganisms in Hydraulically Fractured Shales

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

Booker, Anne E.; Borton, Mikayla A.; Daly, Rebecca A.

ABSTRACT Hydraulic fracturing of black shale formations has greatly increased United States oil and natural gas recovery. However, the accumulation of biomass in subsurface reservoirs and pipelines is detrimental because of possible well souring, microbially induced corrosion, and pore clogging. Temporal sampling of produced fluids from a well in the Utica Shale revealed the dominance ofHalanaerobiumstrains within thein situmicrobial community and the potential for these microorganisms to catalyze thiosulfate-dependent sulfidogenesis. From these field data, we investigated biogenic sulfide production catalyzed by aHalanaerobiumstrain isolated from the produced fluids using proteogenomics and laboratory growth experiments. Analysis ofHalanaerobiumisolate genomes and reconstructed genomes frommore » metagenomic data sets revealed the conserved presence of rhodanese-like proteins and anaerobic sulfite reductase complexes capable of converting thiosulfate to sulfide. Shotgun proteomics measurements using aHalanaerobiumisolate verified that these proteins were more abundant when thiosulfate was present in the growth medium, and culture-based assays identified thiosulfate-dependent sulfide production by the same isolate. Increased production of sulfide and organic acids during the stationary growth phase suggests that fermentativeHalanaerobiumuses thiosulfate to remove excess reductant. These findings emphasize the potential detrimental effects that could arise from thiosulfate-reducing microorganisms in hydraulically fractured shales, which are undetected by current industry-wide corrosion diagnostics. IMPORTANCEAlthough thousands of wells in deep shale formations across the United States have been hydraulically fractured for oil and gas recovery, the impact of microbial metabolism within these environments is poorly understood. Our research demonstrates that dominant microbial populations in these subsurface ecosystems contain the conserved capacity for the reduction of thiosulfate to sulfide and that this process is likely occurring in the environment. Sulfide generation (also known as “souring”) is considered deleterious in the oil and gas industry because of both toxicity issues and impacts on corrosion of the subsurface infrastructure. Critically, the capacity for sulfide generation via reduction of sulfate was not detected in our data sets. Given that current industry wellhead tests for sulfidogenesis target canonical sulfate-reducing microorganisms, these data suggest that new approaches to the detection of sulfide-producing microorganisms may be necessary.« less

Reactivity of Dazomet, a Hydraulic Fracturing Additive: Hydrolysis and Interaction with Pyrite

NASA Astrophysics Data System (ADS)

Consolazio, N.; Lowry, G. V.; Karamalidis, A.; Hakala, A.

2015-12-01

The Marcellus Shale is currently the largest shale gas formation in play across the world. The low-permeability formation requires hydraulic fracturing to be produced. In this process, millions of gallons of water are blended with chemical additives and pumped into each well to fracture the reservoir rock. Although additives account for less than 2% of the fracking fluid mixture, they amount to hundreds of tons per frack job. The environmental properties of some of these additives have been studied, but their behavior under downhole conditions is not widely reported in the peer-reviewed literature. These compounds and their reaction products may return to the surface as produced or waste water. In the event of a spill or release, this water has the potential to contaminate surface soil and water. Of these additives, biocides may present a formidable challenge to water quality. Biocides are toxic compounds (by design), typically added to the Marcellus Shale to control bacteria in the well. An assessment of the most frequently used biocides indicated a need to study the chemical dazomet under reservoir conditions. The Marcellus Shale contains significant deposits of pyrite. This is a ubiquitous mineral within black shales that is known to react with organic compounds in both oxic and anoxic settings. Thus, the objective of our study was to determine the effect of pyrite on the hydrolysis of dazomet. Liquid chromatography-triple quadrupole mass spectrometry (LC-QQQ) was used to calculate the loss rate of aqueous dazomet. Gas chromatography-mass spectrometry (GC-MS) was used to identify the reaction products. Our experiments show that in water, dazomet rapidly hydrolyses in water to form organic and inorganic transformation products. This reaction rate was unaffected when performed under anoxic conditions. However, with pyrite we found an appreciable increase in the removal rate of dazomet. This was accompanied by a corresponding change in the distribution of observed reaction products. Our results indicate the need to determine specific mineral-additive interactions to evaluate the potential risks of chemical use in hydraulic fracturing.

Mechanical Properties of Gas Shale During Drilling Operations

NASA Astrophysics Data System (ADS)

Yan, Chuanliang; Deng, Jingen; Cheng, Yuanfang; Li, Menglai; Feng, Yongcun; Li, Xiaorong

2017-07-01

The mechanical properties of gas shale significantly affect the designs of drilling, completion, and hydraulic fracturing treatments. In this paper, the microstructure characteristics of gas shale from southern China containing up to 45.1% clay were analyzed using a scanning electron microscope. The gas shale samples feature strongly anisotropic characteristics and well-developed bedding planes. Their strength is controlled by the strength of both the matrix and the bedding planes. Conventional triaxial tests and direct shear tests are further used to study the chemical effects of drilling fluids on the strength of shale matrix and bedding planes, respectively. The results show that the drilling fluid has a much larger impact on the strength of the bedding plane than that of the shale matrix. The impact of water-based mud (WBM) is much larger compared with oil-based mud. Furthermore, the borehole collapse pressure of shale gas wells considering the effects of drilling fluids are analyzed. The results show that the collapse pressure increases gradually with the increase of drilling time, especially for WBM.

Development of Porosity Measurement Method in Shale Gas Reservoir Rock

NASA Astrophysics Data System (ADS)

Siswandani, Alita; Nurhandoko, BagusEndar B.

2016-08-01

The pore scales have impacts on transport mechanisms in shale gas reservoirs. In this research, digital helium porosity meter is used for porosity measurement by considering real condition. Accordingly it is necessary to obtain a good approximation for gas filled porosity. Shale has the typical effective porosity that is changing as a function of time. Effective porosity values for three different shale rocks are analyzed by this proposed measurement. We develop the new measurement method for characterizing porosity phenomena in shale gas as a time function by measuring porosity in a range of minutes using digital helium porosity meter. The porosity of shale rock measured in this experiment are free gas and adsorbed gas porosoty. The pressure change in time shows that porosity of shale contains at least two type porosities: macro scale porosity (fracture porosity) and fine scale porosity (nano scale porosity). We present the estimation of effective porosity values by considering Boyle-Gay Lussaac approximation and Van der Waals approximation.

Investigating the Potential Impacts of Energy Production in the Marcellus Shale Region Using the Shale Network Database

NASA Astrophysics Data System (ADS)

Brantley, S.; Brazil, L.

2017-12-01

The Shale Network's extensive database of water quality observations enables educational experiences about the potential impacts of resource extraction with real data. Through tools that are open source and free to use, researchers, educators, and citizens can access and analyze the very same data that the Shale Network team has used in peer-reviewed publications about the potential impacts of hydraulic fracturing on water. The development of the Shale Network database has been made possible through efforts led by an academic team and involving numerous individuals from government agencies, citizen science organizations, and private industry. Thus far, these tools and data have been used to engage high school students, university undergraduate and graduate students, as well as citizens so that all can discover how energy production impacts the Marcellus Shale region, which includes Pennsylvania and other nearby states. This presentation will describe these data tools, how the Shale Network has used them in developing lesson plans, and the resources available to learn more.

Using flowmeter pulse tests to define hydraulic connections in the subsurface: A fractured shale example

USGS Publications Warehouse

Williams, J.H.; Paillet, Frederick L.

2002-01-01

Cross-borehole flowmeter pulse tests define subsurface connections between discrete fractures using short stress periods to monitor the propagation of the pulse through the flow system. This technique is an improvement over other cross-borehole techniques because measurements can be made in open boreholes without packers or previous identification of water-producing intervals. The method is based on the concept of monitoring the propagation of pulses rather than steady flow through the fracture network. In this method, a hydraulic stress is applied to a borehole connected to a single, permeable fracture, and the distribution of flow induced by that stress monitored in adjacent boreholes. The transient flow responses are compared to type curves computed for several different types of fracture connections. The shape of the transient flow response indicates the type of fracture connection, and the fit of the data to the type curve yields an estimate of its transmissivity and storage coefficient. The flowmeter pulse test technique was applied in fractured shale at a volatile-organic contaminant plume in Watervliet, New York. Flowmeter and other geophysical logs were used to identify permeable fractures in eight boreholes in and near the contaminant plume using single-borehole flow measurements. Flowmeter cross-hole pulse tests were used to identify connections between fractures detected in the boreholes. The results indicated a permeable fracture network connecting many of the individual boreholes, and demonstrated the presence of an ambient upward hydraulic-head gradient throughout the site.

Controls on fracture distribution in the Giddings Austin Chalk

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

Wagner, D.T.

1990-09-01

Fracture distribution in the Giddings Austin Chalk is controlled by both structure and the stratigraphy of the Austin Group. Parameters that most affect reservoir performance include fracture width, height, and spacing, as well as the number of fracture sets and their orientations. Lateral variance of these parameters is a function of structural position, while vertical change is related to stratigraphy. The Austin Chalk productive trend is thought to coincide with the hingeline of the Gulf Coast basin, where extension has been concentrated during subsidence of the basin. Fracturing is attributed to a number of mechanisms including normal faulting, bending overmore » buried structures, gravity creep, differential compaction, and aquathermal pressuring. A change in structural style from faulting to flexure takes place from west to east across the Giddings field, accompanied by a change in fracture distribution. In the west, fractures develop only in close proximity to faults whereas in the east they are more widely distributed over broad warps. Stratigraphic controls include lithology, porosity, bed thickness, and ductility contrast between adjacent beds. The Austin Chalk consists of sparse biomicrite interbedded with marls, shales, and clay seams. In general, thin beds are more highly fractured than thick beds, and clean limestone is more highly fractured than marl or shale. Where the more ductile marls and clays exceed a critical thickness, fractures tend to terminate within individual chalk beds, resulting in barriers to vertical flow within the reservoir.« less

Devonian Terrestrial Revolution: the palaeoenvironment of the oldest known tetrapod tracks, Zachełmie Quarry, Poland

NASA Astrophysics Data System (ADS)

Niedźwiedzki, G.

2012-04-01

Numerous trackways and isolated prints with digit impressions, which are similar to the foot anatomy of early tetrapods such as Ichthyostega, were found on the three dolomite bed-surfaces in the lower part of the Wojciechowice Formation exposed in the Zachełmie Quarry in the Holy Cross Mountains (south-central Poland), (Niedźwiedzki et al., 2010). The age of the tetrapod track-bearing strata is well-constrained, but the detailed sedimentology of the lower section with tetrapod ichnites is still under study. The Wojciechowice Formation represent one of the first carbonate stages of a transgressive succession that begins with Early Devonian continental to marginal marine clastics and culminates in the development of a Givetian coral-stromatoporoid carbonate platform. The tetrapod track-bearing complex is composed of grey to reddish, thin- to medium-bedded dolomitic shales and marly dolomite mudstones. These deposits from the tetrapod track-bearing horizon lack definitive marine body fossils, and may have formed in a marginal marine environment, e.g. around a coastal lagoon. Mudcracks, columnar peds, root traces, and microbially induced sedimentary structures were found in three distinct pedotypes of very weakly to weakly developed paleosols (Retallack, 2011). Conodonts of the costatus zone (mid-Eifelian) were found 20 m above the uppermost surface with tetrapod tracks in limestones of the upper Wojciechowice Formation, which contain also brachiopod and crinoidal debris. The overlying Kowala Formation is a marine coral limestone and dolostone. The parts of profile with tetrapod ichnites and invertebrate and conodont fossils contain also records of invertebrate traces. Seven ichnotaxa are distributed among four recognized ichnoassemblages. The recognized ichnocoenoses are typical for the shallow-marine (Cruziana ichnofacies) and land-water transitional (Skolithos/Psilonichnus ichnofacies) carbonate depositional environments. The ichnocoenoses are dominated by trace fossils produced by arthropods (probably crustaceans), a group that can create large and distinctive burrows. The palaeoecological information from the Zachełmie section has direct bearing on the interpretation of environmental aspects of tetrapod emergence and terrestrialization. It should be fully integrated with data from other Devonian tetrapod tracksites. Niedźwiedzki, G., Szrek P., Narkiewicz K., Narkiewicz M. and Ahlberg P.E. 2010. Tetrapod trackways from the early Middle Devonian period of Poland. Nature, 463: 43-48. Retallack, G.J. 2011. Woodland Hypothesis for Devonian Tetrapod Evolution. The Journal of Geology, 119, 3: 235-258

Gas Flow Tightly Coupled to Elastoplastic Geomechanics for Tight- and Shale-Gas Reservoirs: Material Failure and Enhanced Permeability

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

Kim, Jihoon; Moridis, George J.

We investigate coupled flow and geomechanics in gas production from extremely low permeability reservoirs such as tight and shale gas reservoirs, using dynamic porosity and permeability during numerical simulation. In particular, we take the intrinsic permeability as a step function of the status of material failure, and the permeability is updated every time step. We consider gas reservoirs with the vertical and horizontal primary fractures, employing the single and dynamic double porosity (dual continuum) models. We modify the multiple porosity constitutive relations for modeling the double porous continua for flow and geomechanics. The numerical results indicate that production of gasmore » causes redistribution of the effective stress fields, increasing the effective shear stress and resulting in plasticity. Shear failure occurs not only near the fracture tips but also away from the primary fractures, which indicates generation of secondary fractures. These secondary fractures increase the permeability significantly, and change the flow pattern, which in turn causes a change in distribution of geomechanical variables. From various numerical tests, we find that shear failure is enhanced by a large pressure drop at the production well, high Biot's coefficient, low frictional and dilation angles. Smaller spacing between the horizontal wells also contributes to faster secondary fracturing. When the dynamic double porosity model is used, we observe a faster evolution of the enhanced permeability areas than that obtained from the single porosity model, mainly due to a higher permeability of the fractures in the double porosity model. These complicated physics for stress sensitive reservoirs cannot properly be captured by the uncoupled or flow-only simulation, and thus tightly coupled flow and geomechanical models are highly recommended to accurately describe the reservoir behavior during gas production in tight and shale gas reservoirs and to smartly design production scenarios.« less

Gas Flow Tightly Coupled to Elastoplastic Geomechanics for Tight- and Shale-Gas Reservoirs: Material Failure and Enhanced Permeability

DOE PAGES

Kim, Jihoon; Moridis, George J.

2014-12-01

We investigate coupled flow and geomechanics in gas production from extremely low permeability reservoirs such as tight and shale gas reservoirs, using dynamic porosity and permeability during numerical simulation. In particular, we take the intrinsic permeability as a step function of the status of material failure, and the permeability is updated every time step. We consider gas reservoirs with the vertical and horizontal primary fractures, employing the single and dynamic double porosity (dual continuum) models. We modify the multiple porosity constitutive relations for modeling the double porous continua for flow and geomechanics. The numerical results indicate that production of gasmore » causes redistribution of the effective stress fields, increasing the effective shear stress and resulting in plasticity. Shear failure occurs not only near the fracture tips but also away from the primary fractures, which indicates generation of secondary fractures. These secondary fractures increase the permeability significantly, and change the flow pattern, which in turn causes a change in distribution of geomechanical variables. From various numerical tests, we find that shear failure is enhanced by a large pressure drop at the production well, high Biot's coefficient, low frictional and dilation angles. Smaller spacing between the horizontal wells also contributes to faster secondary fracturing. When the dynamic double porosity model is used, we observe a faster evolution of the enhanced permeability areas than that obtained from the single porosity model, mainly due to a higher permeability of the fractures in the double porosity model. These complicated physics for stress sensitive reservoirs cannot properly be captured by the uncoupled or flow-only simulation, and thus tightly coupled flow and geomechanical models are highly recommended to accurately describe the reservoir behavior during gas production in tight and shale gas reservoirs and to smartly design production scenarios.« less

Draft Genome Sequence of Methanohalophilus mahii Strain DAL1 Reconstructed from a Hydraulic Fracturing-Produced Water Metagenome.

PubMed

Lipus, Daniel; Vikram, Amit; Ross, Daniel E; Bibby, Kyle

2016-09-01

We report here the 1,882,100-bp draft genome sequence of Methanohalophilus mahii strain DAL1, recovered from Marcellus Shale hydraulic fracturing-produced water using metagenomic contig binning. Genome annotation revealed several key methanogenesis genes and provides valuable information on archaeal activity associated with hydraulic fracturing-produced water environments. Copyright © 2016 Lipus et al.

Strontium isotopic study of subsurface brines from Illinois basin

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

hetherington, E.A.; Stueber, A.M.; Pushkar, P.

1986-05-01

The abundance of the radiogenic isotope /sup 87/Sr in a subsurface brine can be used as a tracer of brine origin, evolution, and diagenetic effects. The authors have determined the /sup 87/Sr//sup 86/Sr ratios of over 60 oil-field waters from the Illinois basin, where brine origin is perplexing because of the absence of any significant evaporite strata. Initially, they analyzed brines from 15 petroleum-producing sandstone and carbonate units; waters from Ordovician, Silurian, Devonian, and Mississippian strata have /sup 87/Sr//sup 86/Sr ratios in the range 0.7079-0.7108. All but those from the Ste. Genevieve Limestone (middle Mississippian) are more radiogenic in /supmore » 87/Sr//sup 86/Sr than seawater values for this interval of geologic time. The detrital source of the more radiogenic /sup 87/Sr may be the New Albany Shale group, considered to be a major petroleum source rock in the basin. The /sup 87/Sr//sup 86/Sr ratios of Ste. Genevieve brines apparently evolved without a contribution from fluid-shale interaction.« less

Petroleum potential of the Reggane Basin, Algeria

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

Boudjema, A.; Hamel, M.; Mohamedi, A.

1990-05-01

The intracratonic Reggane basin is located on the Saharan platform, southwest of Algeria. The basin covers an area of approximately 140,000 km{sup 2}, extending between the Eglab shield in the south and the Ougarta ranges in the north. Although exploration started in the early 1950s, only a few wells were drilled in this basin. Gas was discovered with a number of oil shows. The sedimentary fill, mainly Paleozoic shales and sandstones, has a thickness exceeding 5,000 m in the central part of the basin. The reservoirs are Cambrian-Ordovician, Siegenian, Emsian, Tournaisian, and Visean sandstones with prospective petrophysical characteristics. Silurian Uppermore » Devonian and, to a lesser extent Carboniferous shales are the main source rocks. An integrated study was done to assess the hydrocarbon potential of this basin. Tectonic evolution source rocks and reservoirs distribution maturation analyses followed by kinetic modeling, and hydrogeological conditions were studied. Results indicate that gas accumulations could be expected in the central and deeper part of the basin, and oil reservoirs could be discovered on the basin edge.« less

SERDP and ESTCP Expert Panel Workshop on Reducing the Uncertainty of DNAPL Source Zone Remediation

DTIC Science & Technology

2006-09-01

Conventional – Wells – Geoprobe • Pneumatic Fracturing • Hydraulic Fracturing • Pressure Pulse Success is achieved when enough Oxidant/Reductant is...al, 2003; Parker et al, 2004). In fractured aquitards (i.e., silts/clays and shales/mudstones), where the bulk hydraulic conductivity is...relatively low, DNAPL can readily migrate into these units via the fractures and, after a few years to decades, nearly all the mass resides in the low

Water Resources and Natural Gas Production from the Marcellus Shale

USGS Publications Warehouse

Soeder, Daniel J.; Kappel, William M.

2009-01-01

The Marcellus Shale is a sedimentary rock formation deposited over 350 million years ago in a shallow inland sea located in the eastern United States where the present-day Appalachian Mountains now stand (de Witt and others, 1993). This shale contains significant quantities of natural gas. New developments in drilling technology, along with higher wellhead prices, have made the Marcellus Shale an important natural gas resource. The Marcellus Shale extends from southern New York across Pennsylvania, and into western Maryland, West Virginia, and eastern Ohio (fig. 1). The production of commercial quantities of gas from this shale requires large volumes of water to drill and hydraulically fracture the rock. This water must be recovered from the well and disposed of before the gas can flow. Concerns about the availability of water supplies needed for gas production, and questions about wastewater disposal have been raised by water-resource agencies and citizens throughout the Marcellus Shale gas development region. This Fact Sheet explains the basics of Marcellus Shale gas production, with the intent of helping the reader better understand the framework of the water-resource questions and concerns.

Hydraulic Fracturing Mineback Experiment in Complex Media

NASA Astrophysics Data System (ADS)

Green, S. J.; McLennan, J. D.

2012-12-01

Hydraulic fracturing (or "fracking") for the recovery of gas and liquids from tight shale formations has gained much attention. This operation which involves horizontal well drilling and massive hydraulic fracturing has been developed over the last decade to produce fluids from extremely low permeability mudstone and siltstone rocks with high organic content. Nearly thirteen thousand wells and about one hundred and fifty thousand stages within the wells were fractured in the US in 2011. This operation has proven to be successful, causing hundreds of billions of dollars to be invested and has produced an abundance of natural gas and is making billions of barrels of hydrocarbon liquids available for the US. But, even with this commercial success, relatively little is clearly known about the complexity--or lack of complexity--of the hydraulic fracture, the extent that the newly created surface area contacts the high Reservoir Quality rock, nor the connectivity and conductivity of the hydraulic fractures created. To better understand this phenomena in order to improve efficiency, a large-scale mine-back experiment is progressing. The mine-back experiment is a full-scale hydraulic fracture carried out in a well-characterized environment, with comprehensive instrumentation deployed to measure fracture growth. A tight shale mudstone rock geologic setting is selected, near the edge of a formation where one to two thousand feet difference in elevation occurs. From the top of the formation, drilling, well logging, and hydraulic fracture pumping will occur. From the bottom of the formation a horizontal tunnel will be mined using conventional mining techniques into the rock formation towards the drilled well. Certain instrumentation will be located within this tunnel for observations during the hydraulic fracturing. After the hydraulic fracturing, the tunnel will be extended toward the well, with careful mapping of the created hydraulic fracture. Fracturing fluid will be traceable, as will injected proppant, in order to demarcate in-situ fracture paths and fluid and proppant progression. This underground experiment is referred to as a "mine-back experiment". Several mine-back experiments have been conducted in the past, and have demonstrated complex, diffuse fracture systems in coals and bundled fracture systems in some sandstones. No mine-back experiment has been conducted in the tight shales; but, economics and environmental considerations dictate that more definitive measurements will be extremely helpful to establish fracture growth patterns and to validate monitoring methods such as micro-seismic measurements. This presentation discusses the mine-back experiment and presents details of geologic setting, hydraulic fracturing, and the excavation required before and after the hydraulic fracture. The mine-back experiment will provide ground-truth assessment of hydraulic fracturing, geologic forecasting, micro-seismicity, and other information.

Looking for the Kellwasser Event in all the wrong places: a multiproxy study of island arc paleoenvironments in the Central Asian Orogenic Belt

NASA Astrophysics Data System (ADS)

Carmichael, S. K.; Wang, Z.; Waters, J. A.; Dombrowski, A. D.; Batchelor, C. J.; Coleman, D. S.; Suttner, T.; Kido, E.

2017-12-01

The Late Devonian Frasnian-Famennian (F-F) boundary at 372 Ma is associated with the Kellwasser Event, an ocean anoxia event that is often associated with positive δ13C excursions and commonly represented by black shales. However, approximately 88% of the studies of the Kellwasser Event are based on sites from deep epicontinental basins and epeiric seas, and most of these sites are located on the Euramerican paleocontinent. In contrast to the positive δ13C excursions found in most basinal study sites, the δ13C signatures in three separate shallow water, island-arc F-F sections in the Junggar Basin in northwestern China (Wulankeshun, Boulongour Reservoir, and Genare) all show negative excursions in the stratigraphic location of the Kellwasser Event [1-3]. The δ18O values in both carbonates and/or conodont apatite likewise show negative excursions within the shallow water facies at each site, but have relatively constant signatures within the deeper water facies. 87Sr/86Sr values range from 0.70636-0.70906 at the base of the Boulongour Reservoir section and 0.70746-0.71383 at the base of the Wulankeshun section but both Sr signaures stabilize with relatively constant values closer to modeled Late Devonian seawater in deeper water and/or offshore facies. The fossil assemblages at the base of the Boulongour and Wulankeshun sections each correspond to euryhaline/brackish conditions, while microtextures in Ti-bearing phases within clastic sediments as well as isotope mixing models suggest submarine groundwater discharge signatures rather than diagenetic alteration. Preliminary framboidal pyrite distributions in these sections also show evidence for sub/dysoxic (rather than euxinic or anoxic) conditions that correspond to the stratigraphic Kellwasser interval. Positive δ13C excursions and the presence of black shales are thus not prerequisites for recognition of the Kellwasser Event, particularly in shallow water paleoenvironments that are not topographically favorable to shale accumulation and may have significant coastal groundwater or surface water inputs. [1] Suttner et al. (2014) J. of Asian Earth Sci. 80, 101-118. [2] Carmichael et al. (2014) Paleo3 399, 394-403. [3] Wang et al. (2016) Paleo3 448, 279-297.

The earliest seeds

USGS Publications Warehouse

Gillespie, W.H.; Rothwell, G.W.; Scheckler, S.E.

1981-01-01

Lagenostomalean-type seeds in bifurcating cupule systems have been discovered in the late Devonian Hampshire Formation of Randolph County, West Virginia, USA (Fig. 1). The associated megaflora, plants from coal balls, and vertebrate and invertebrate faunas demonstrate that the material is Famennian; the microflora indicates a more specific Fa2c age. Consequently, these seeds predate Archaeosperma arnoldii1 from the Fa2d of northeastern Pennsylvania, the oldest previously reported seed. By applying precision fracture, transfer, de??gagement, and thin-section techniques to selected cupules from the more than 100 specimens on hand, we have determined the three-dimensional morphology and histology of the seeds (Fig. 2a-h, k) and cupule systems. A comparison with known late Devonian to early Carboniferous seeds reveals that ours are more primitively organized than all except Genomosperma2,3. ?? 1981 Nature Publishing Group.

Impact of shale gas development on regional water quality.

PubMed

Vidic, R D; Brantley, S L; Vandenbossche, J M; Yoxtheimer, D; Abad, J D

2013-05-17

Unconventional natural gas resources offer an opportunity to access a relatively clean fossil fuel that could potentially lead to energy independence for some countries. Horizontal drilling and hydraulic fracturing make the extraction of tightly bound natural gas from shale formations economically feasible. These technologies are not free from environmental risks, however, especially those related to regional water quality, such as gas migration, contaminant transport through induced and natural fractures, wastewater discharge, and accidental spills. We review the current understanding of environmental issues associated with unconventional gas extraction. Improved understanding of the fate and transport of contaminants of concern and increased long-term monitoring and data dissemination will help manage these water-quality risks today and in the future.

Evaluating the oxidation of shale during hydraulic fracturing using SEM-EDS and spectrocolorimetry

NASA Astrophysics Data System (ADS)

Tan, X. Y.; Nakashima, S.

2017-12-01

During hydraulic fracturing (fracking) for shale gas/oil extraction, oxygen is introduced into deep oxygen-poor environments, and Fe2+-bearing minerals in rocks can be oxidized thus leading to the degradation of rock quality. Akita diatomaceous shale is considered to be one of the source rocks for oil and gas fields in northwestern Japan. Outcrops of Akita shale often show presence of jarosite (Fe sulfate: yellow) and/or goethite (Fe hydroxide: brown to orange) as oxidation products of pyrite (FeS2). Several series of oxidation experiments of Akita shale under dry, humid, and wet conditions were conducted at temperatures of around 30 oC and 50oC for 30-40 days. Portable color spectro-colorimeters were used to monitor color changes of the rock surfaces every hour. SEM-EDS, UV-Vis, and Raman spectroscopic analyses were performed on the rock sample surface to examine the chemical and mineralogical compositions of Akita shale before and after the dry, humid, and wet experiments. In SEM-EDS analyses before the humid experiment, Fe and S containing phases show their atomic ratio close to 1:2 indicating that this is pyrite (FeS2). After the experiment, the ratio changed to around 1:1 suggesting a conversion from pyrite (FeS2) to mackinawite-like mineral (FeS). In addition, the formation of Ca sulfate (possibly gypsum: CaSO4.2H2O) and goethite-like Fe hydroxide were identified which were not present initially. Therefore, oxidation pathways of iron sulfide (pyrite: FeS2) via FeS to sulfate is confirmed by our humid experiments around 30oC on Akita shale. These oxidation processes might occur during the fracking of shale within relatively short time periods associated with precipitation of sulfates and hydroxides. Therefore, further studies are needed for their effects on rock properties and gas/oil production.

MX Siting Investigation. Water Resources Program Progress Report.

DTIC Science & Technology

1981-02-13

avoided. o Limestones and dolomites (carbonates) of Devonian age appear to be the major regional aquifers which hydrologically con- nect many valleys...that of the aquifer itself. Carbonate Aquifer. A aquifer, contained in limestone or dolomite rock, which occurs beneath the unconsolidated valley-fill...sediments and in the mountain ranges. Flow is believed to be primarily through fracture and solution openings rather than through normal inter

Study on interaction between induced and natural fractures by extended finite element method

NASA Astrophysics Data System (ADS)

Xu, DanDan; Liu, ZhanLi; Zhuang, Zhuo; Zeng, QingLei; Wang, Tao

2017-02-01

Fracking is one of the kernel technologies in the remarkable shale gas revolution. The extended finite element method is used in this paper to numerically investigate the interaction between hydraulic and natural fractures, which is an important issue of the enigmatic fracture network formation in fracking. The criteria which control the opening of natural fracture and crossing of hydraulic fracture are tentatively presented. Influence factors on the interaction process are systematically analyzed, which include the approach angle, anisotropy of in-situ stress and fluid pressure profile.

Organic substances in produced and formation water from unconventional natural gas extraction in coal and shale

USGS Publications Warehouse

Orem, William H.; Tatu, Calin A.; Varonka, Matthew S.; Lerch, Harry E.; Bates, Anne L.; Engle, Mark A.; Crosby, Lynn M.; McIntosh, Jennifer

2014-01-01

Organic substances in produced and formation water from coalbed methane (CBM) and gas shale plays from across the USA were examined in this study. Disposal of produced waters from gas extraction in coal and shale is an important environmental issue because of the large volumes of water involved and the variable quality of this water. Organic substances in produced water may be environmentally relevant as pollutants, but have been little studied. Results from five CBM plays and two gas shale plays (including the Marcellus Shale) show a myriad of organic chemicals present in the produced and formation water. Organic compound classes present in produced and formation water in CBM plays include: polycyclic aromatic hydrocarbons (PAHs), heterocyclic compounds, alkyl phenols, aromatic amines, alkyl aromatics (alkyl benzenes, alkyl biphenyls), long-chain fatty acids, and aliphatic hydrocarbons. Concentrations of individual compounds range from < 1 to 100 μg/L, but total PAHs (the dominant compound class for most CBM samples) range from 50 to 100 μg/L. Total dissolved organic carbon (TOC) in CBM produced water is generally in the 1–4 mg/L range. Excursions from this general pattern in produced waters from individual wells arise from contaminants introduced by production activities (oils, grease, adhesives, etc.). Organic substances in produced and formation water from gas shale unimpacted by production chemicals have a similar range of compound classes as CBM produced water, and TOC levels of about 8 mg/L. However, produced water from the Marcellus Shale using hydraulic fracturing has TOC levels as high as 5500 mg/L and a range of added organic chemicals including, solvents, biocides, scale inhibitors, and other organic chemicals at levels of 1000 s of μg/L for individual compounds. Levels of these hydraulic fracturing chemicals and TOC decrease rapidly over the first 20 days of water recovery and some level of residual organic contaminants remain up to 250 days after hydraulic fracturing. Although the environmental impacts of the organics in produced water are not well defined, results suggest that care should be exercised in the disposal and release of produced waters containing these organic substances into the environment because of the potential toxicity of many of these substances.

Effects of spatial heterogeneity and material anisotropy on the fracture pattern and macroscopic effective toughness of Mancos Shale in Brazilian tests

NASA Astrophysics Data System (ADS)

Na, SeonHong; Sun, WaiChing; Ingraham, Mathew D.; Yoon, Hongkyu

2017-08-01

For assessing energy-related activities in the subsurface, it is important to investigate the impact of the spatial variability and anisotropy on the geomechanical behavior of shale. The Brazilian test, an indirect tensile-splitting method, is performed in this work, and the evolution of strain field is obtained using digital image correlation. Experimental results show the significant impact of local heterogeneity and lamination on the crack pattern characteristics. For numerical simulations, a phase field method is used to simulate the brittle fracture behavior under various Brazilian test conditions. In this study, shale is assumed to consist of two constituents including the stiff and soft layers to which the same toughness but different elastic moduli are assigned. Microstructural heterogeneity is simplified to represent mesoscale (e.g., millimeter scale) features such as layer orientation, thickness, volume fraction, and defects. The effect of these structural attributes on the onset, propagation, and coalescence of cracks is explored. The simulation results show that spatial heterogeneity and material anisotropy highly affect crack patterns and effective fracture toughness, and the elastic contrast of two constituents significantly alters the effective toughness. However, the complex crack patterns observed in the experiments cannot completely be accounted for by either an isotropic or transversely isotropic effective medium approach. This implies that cracks developed in the layered system may coalesce in complicated ways depending on the local heterogeneity, and the interaction mechanisms between the cracks using two-constituent systems may explain the wide range of effective toughness of shale reported in the literature.

Evaluating a groundwater supply contamination incident attributed to Marcellus Shale gas development

PubMed Central

Llewellyn, Garth T.; Dorman, Frank; Westland, J. L.; Yoxtheimer, D.; Grieve, Paul; Sowers, Todd; Humston-Fulmer, E.; Brantley, Susan L.

2015-01-01

High-volume hydraulic fracturing (HVHF) has revolutionized the oil and gas industry worldwide but has been accompanied by highly controversial incidents of reported water contamination. For example, groundwater contamination by stray natural gas and spillage of brine and other gas drilling-related fluids is known to occur. However, contamination of shallow potable aquifers by HVHF at depth has never been fully documented. We investigated a case where Marcellus Shale gas wells in Pennsylvania caused inundation of natural gas and foam in initially potable groundwater used by several households. With comprehensive 2D gas chromatography coupled to time-of-flight mass spectrometry (GCxGC-TOFMS), an unresolved complex mixture of organic compounds was identified in the aquifer. Similar signatures were also observed in flowback from Marcellus Shale gas wells. A compound identified in flowback, 2-n-Butoxyethanol, was also positively identified in one of the foaming drinking water wells at nanogram-per-liter concentrations. The most likely explanation of the incident is that stray natural gas and drilling or HF compounds were driven ∼1–3 km along shallow to intermediate depth fractures to the aquifer used as a potable water source. Part of the problem may have been wastewaters from a pit leak reported at the nearest gas well pad—the only nearby pad where wells were hydraulically fractured before the contamination incident. If samples of drilling, pit, and HVHF fluids had been available, GCxGC-TOFMS might have fingerprinted the contamination source. Such evaluations would contribute significantly to better management practices as the shale gas industry expands worldwide. PMID:25941400

Effects of spatial heterogeneity and material anisotropy on the fracture pattern and macroscopic effective toughness of Mancos Shale in Brazilian tests

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

Na, SeonHong; Sun, WaiChing; Ingraham, Mathew D.

For assessing energy-related activities in the subsurface, it is important to investigate the impact of the spatial variability and anisotropy on the geomechanical behavior of shale. The Brazilian test, an indirect tensile-splitting method, is performed in this work, and the evolution of strain field is obtained using digital image correlation. Experimental results show the significant impact of local heterogeneity and lamination on the crack pattern characteristics. For numerical simulations, a phase field method is used to simulate the brittle fracture behavior under various Brazilian test conditions. In this study, shale is assumed to consist of two constituents including the stiffmore » and soft layers to which the same toughness but different elastic moduli are assigned. Microstructural heterogeneity is simplified to represent mesoscale (e.g., millimeter scale) features such as layer orientation, thickness, volume fraction, and defects. The effect of these structural attributes on the onset, propagation, and coalescence of cracks is explored. The simulation results show that spatial heterogeneity and material anisotropy highly affect crack patterns and effective fracture toughness, and the elastic contrast of two constituents significantly alters the effective toughness. However, the complex crack patterns observed in the experiments cannot completely be accounted for by either an isotropic or transversely isotropic effective medium approach. In conclusion, this implies that cracks developed in the layered system may coalesce in complicated ways depending on the local heterogeneity, and the interaction mechanisms between the cracks using two-constituent systems may explain the wide range of effective toughness of shale reported in the literature.« less

Effects of spatial heterogeneity and material anisotropy on the fracture pattern and macroscopic effective toughness of Mancos Shale in Brazilian tests

DOE PAGES

Na, SeonHong; Sun, WaiChing; Ingraham, Mathew D.; ...

2017-07-31

For assessing energy-related activities in the subsurface, it is important to investigate the impact of the spatial variability and anisotropy on the geomechanical behavior of shale. The Brazilian test, an indirect tensile-splitting method, is performed in this work, and the evolution of strain field is obtained using digital image correlation. Experimental results show the significant impact of local heterogeneity and lamination on the crack pattern characteristics. For numerical simulations, a phase field method is used to simulate the brittle fracture behavior under various Brazilian test conditions. In this study, shale is assumed to consist of two constituents including the stiffmore » and soft layers to which the same toughness but different elastic moduli are assigned. Microstructural heterogeneity is simplified to represent mesoscale (e.g., millimeter scale) features such as layer orientation, thickness, volume fraction, and defects. The effect of these structural attributes on the onset, propagation, and coalescence of cracks is explored. The simulation results show that spatial heterogeneity and material anisotropy highly affect crack patterns and effective fracture toughness, and the elastic contrast of two constituents significantly alters the effective toughness. However, the complex crack patterns observed in the experiments cannot completely be accounted for by either an isotropic or transversely isotropic effective medium approach. In conclusion, this implies that cracks developed in the layered system may coalesce in complicated ways depending on the local heterogeneity, and the interaction mechanisms between the cracks using two-constituent systems may explain the wide range of effective toughness of shale reported in the literature.« less

Evaluating a groundwater supply contamination incident attributed to Marcellus Shale gas development.

PubMed

Llewellyn, Garth T; Dorman, Frank; Westland, J L; Yoxtheimer, D; Grieve, Paul; Sowers, Todd; Humston-Fulmer, E; Brantley, Susan L

2015-05-19

High-volume hydraulic fracturing (HVHF) has revolutionized the oil and gas industry worldwide but has been accompanied by highly controversial incidents of reported water contamination. For example, groundwater contamination by stray natural gas and spillage of brine and other gas drilling-related fluids is known to occur. However, contamination of shallow potable aquifers by HVHF at depth has never been fully documented. We investigated a case where Marcellus Shale gas wells in Pennsylvania caused inundation of natural gas and foam in initially potable groundwater used by several households. With comprehensive 2D gas chromatography coupled to time-of-flight mass spectrometry (GCxGC-TOFMS), an unresolved complex mixture of organic compounds was identified in the aquifer. Similar signatures were also observed in flowback from Marcellus Shale gas wells. A compound identified in flowback, 2-n-Butoxyethanol, was also positively identified in one of the foaming drinking water wells at nanogram-per-liter concentrations. The most likely explanation of the incident is that stray natural gas and drilling or HF compounds were driven ∼ 1-3 km along shallow to intermediate depth fractures to the aquifer used as a potable water source. Part of the problem may have been wastewaters from a pit leak reported at the nearest gas well pad-the only nearby pad where wells were hydraulically fractured before the contamination incident. If samples of drilling, pit, and HVHF fluids had been available, GCxGC-TOFMS might have fingerprinted the contamination source. Such evaluations would contribute significantly to better management practices as the shale gas industry expands worldwide.

Compaction bands in shale revealed through digital volume correlation of time-resolved X-ray tomography scans

NASA Astrophysics Data System (ADS)

McBeck, J.; Kobchenko, M.; Hall, S.; Tudisco, E.; Cordonnier, B.; Renard, F.

2017-12-01

Previous studies have identified compaction bands primarily within sandstones, and in fewer instances, within other porous rocks and sediments. Using Digital Volume Correlation (DVC) of X-ray microtomography scans, we find evidence of localized zones of high axial contraction that form tabular structures sub-perpendicular to maximum compression, σ1, in Green River shale. To capture in situ strain localization throughout loading, two shale cores were deformed in the HADES triaxial deformation apparatus installed on the X-ray microtomography beamline ID19 at the European Synchrotron Radiation Facility. In these experiments, we increase σ1 in increments of two MPa, with constant confining pressure (20 MPa), until the sample fails in macroscopic shear. After each stress step, a 3D image of the sample inside the rig is acquired at a voxel resolution of 6.5 μm. The evolution of lower density regions within 3D reconstructions of linear attenuation coefficients reveal the development of fractures that fail with some opening. If a fracture produces negligible dilation, it may remain undetected in image segmentation of the reconstructions. We use the DVC software TomoWarp2 to identify undetected fractures and capture the 3D incremental displacement field between each successive pair of microtomography scans acquired in each experiment. The corresponding strain fields reveal localized bands of high axial contraction that host minimal shear strain, and thus match the kinematic definition of compaction bands. The bands develop sub-perpendicular to σ1 in the two samples in which pre-existing bedding laminations were oriented parallel and perpendicular to σ1. As the shales deform plastically toward macroscopic shear failure, the number of bands and axial contraction within the bands increase, while the spacing between the bands decreases. Compaction band development accelerates the rate of overall axial contraction, increasing the mean axial contraction throughout the sample, and strengthens the shale sufficiently to localize shear faults. These results are critical to robust assessment of deformation patterns in shale rocks in contexts such as nuclear waste storage, hydrocarbon recovery and groundwater access.