Sample records for nahcolite
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Treating nahcolite containing formations and saline zones
Vinegar, Harold J
2013-06-11
A method for treating a nahcolite containing subsurface formation includes removing water from a saline zone in or near the formation. The removed water is heated using a steam and electricity cogeneration facility. The heated water is provided to the nahcolite containing formation. A fluid is produced from the nahcolite containing formation. The fluid includes at least some dissolved nahcolite. At least some of the fluid is provided to the saline zone.
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Oil shale and nahcolite resources of the Piceance Basin, Colorado
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2010-01-01
This report presents an in-place assessment of the oil shale and nahcolite resources of the Green River Formation in the Piceance Basin of western Colorado. The Piceance Basin is one of three large structural and sedimentary basins that contain vast amounts of oil shale resources in the Green River Formation of Eocene age. The other two basins, the Uinta Basin of eastern Utah and westernmost Colorado, and the Greater Green River Basin of southwest Wyoming, northwestern Colorado, and northeastern Utah also contain large resources of oil shale in the Green River Formation, and these two basins will be assessed separately. Estimated in-place oil is about 1.5 trillion barrels, based on Fischer a ssay results from boreholes drilled to evaluate oil shale, making it the largest oil shale deposit in the world. The estimated in-place nahcolite resource is about 43.3 billion short tons.
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Johnson, Ronald C.; Brownfield, Michael E.
2013-01-01
Halite and the sodium bicarbonate mineral nahcolite were deposited during the saline phase of Eocene Lake Uinta in the Piceance Basin, western Colorado. Variations in the area of saline mineral deposition through time were interpreted from studies of core and outcrop. Saline minerals were extensively leached by groundwater, so the original extent of saline deposition was estimated from the distribution of empty vugs and collapse breccias. Vugs and breccias strongly influence groundwater movement, so determining where leaching has occurred is an important consideration for in-situ oil shale extraction methods currently being developed. Lake Uinta formed when two smaller fresh water lakes, one in the Uinta Basin of eastern Utah and the other in the Piceance Basin of western Colorado, expanded and coalesced across the Douglas Creek arch, an area of comparatively low subsidence rates. Salinity increased shortly after this expansion, but saline mineral deposition did not begin until later, after a period of prolonged infilling created broad lake-margin shelves and a comparatively small deep central lake area. These shelves probably played a critical role in brine evolution. A progression from disseminated nahcolite and nahcolite aggregates to bedded nahcolite and ultimately to bedded nahcolite and halite was deposited in this deep lake area during the early stages of saline deposition along with rich oil shale that commonly shows signs of slumping and lateral transport. The area of saline mineral and rich oil shale deposition subsequently expanded, in part due to infilling of the compact deep area, and in part because of an increase in water flow into Lake Uinta, possibly due to outflow from Lake Gosiute to the north. Finally, as Lake Uinta in the Piceance Basin was progressively filled from north to south by volcano-clastic sediment, the saline depocenter was pushed progressively southward, eventually covering much of the areas that had previously been marginal shelves
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Solution mining and heating by oxidation for treating hydrocarbon containing formations
Vinegar, Harold J.; Stegemeier, George Leo
2009-06-23
A method for treating an oil shale formation comprising nahcolite includes providing a first fluid to a portion of the formation. A second fluid is produced from the portion. The second fluid includes at least some nahcolite dissolved in the first fluid. A controlled amount of oxidant is provided to the portion of the formation. Hydrocarbon fluids are produced from the formation.
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Solution mining systems and methods for treating hydrocarbon containing formations
Vinegar, Harold J [Bellaire, TX; de Rouffignac, Eric Pierre [Rijswijk, NL; Schoeling, Lanny Gene [Katy, TX
2009-07-14
A method for treating an oil shale formation comprising nahcolite is disclosed. The method includes providing a first fluid to a portion of the formation through at least two injection wells. A second fluid is produced from the portion through at least one injection well until at least two injection wells are interconnected such that fluid can flow between the two injection wells. The second fluid includes at least some nahcolite dissolved in the first fluid. The first fluid is injected through one of the interconnected injection wells. The second fluid is produced from at least one of the interconnected injection wells. Heat is provided from one or more heaters to the formation to heat the formation. Hydrocarbon fluids are produced from the formation.
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Ege, John R.; Carroll, R.D.; Way, R.J.; Magner, J.E.
1969-01-01
USBM/AEC Colorado Core Hole No. 3 (Bronco BR-1) is located in the SW1/4SW1/4SW1/4 sec. 14, T. 1 N., R. 98 W., Rio Blanco County, Colorado. The collar is at a ground elevation of 6,356 feet. The hole was core drilled between depths of 964 and 3,325 feet with a total depth of 3,797 feet. The hole was drilled to investigate geologic, geophysical and hydrological conditions at a possible in situ oil-shale retorting experiment site. The drill hole passed through 1,157 feet of alluvium and the Evacuation Creek Member of the Green River Formation, 1,603 feet of the Parachute Creek Member and penetrated into the Garden Gulch Member of the Green River Formation. In-bole density log/oil yield ratio interpretation indicates that two oil-shale zones exist which yield more than 20 gallons of shale oil per ton of rock; an upper zone lying between 1,271 and 1,750 feet in depth and a lower zone lying between 1,900 and 2,964 feet. Halite (sodium chloride salt) is found between 2,140 and 2,185 feet and nahcolite (sodium bicarbonate salt) between 2,195 and 2,700 feet. Nahcolite was present at one time above 2,195 feet but has been subsequently dissolved out by ground water. The core can be divided into six structural units based upon degree of fracturing. A highly fractured interval is found between 1,646 and 1,899 feet, which coincides with the dissolution or leached nahcolite zone. Physical property tests made on core samples between 1,356 and 3,253 feet give average values of 11,988 psi for uniaxial compressive strength, 1.38 X 10[superscript]6[superscript] psi for static Young's modulus and 11,809 fps for compressional velocity.
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Johnson, Ronald C.; Mercier, Tracey J.; Brownfield, Michael E.
2014-01-01
The spatial and stratigraphic distribution of water in oil shale of the Eocene Green River Formation in the Piceance Basin of northwestern Colorado was studied in detail using some 321,000 Fischer assay analyses in the U.S. Geological Survey oil-shale database. The oil-shale section was subdivided into 17 roughly time-stratigraphic intervals, and the distribution of water in each interval was assessed separately. This study was conducted in part to determine whether water produced during retorting of oil shale could provide a significant amount of the water needed for an oil-shale industry. Recent estimates of water requirements vary from 1 to 10 barrels of water per barrel of oil produced, depending on the type of retort process used. Sources of water in Green River oil shale include (1) free water within clay minerals; (2) water from the hydrated minerals nahcolite (NaHCO3), dawsonite (NaAl(OH)2CO3), and analcime (NaAlSi2O6.H20); and (3) minor water produced from the breakdown of organic matter in oil shale during retorting. The amounts represented by each of these sources vary both stratigraphically and areally within the basin. Clay is the most important source of water in the lower part of the oil-shale interval and in many basin-margin areas. Nahcolite and dawsonite are the dominant sources of water in the oil-shale and saline-mineral depocenter, and analcime is important in the upper part of the formation. Organic matter does not appear to be a major source of water. The ratio of water to oil generated with retorting is significantly less than 1:1 for most areas of the basin and for most stratigraphic intervals; thus water within oil shale can provide only a fraction of the water needed for an oil-shale industry.
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Johnson, Ronald C.; Mercier, Tracey J.; Brownfield, Michael E.
2014-01-01
The spatial and stratigraphic distribution of water in oil shale of the Eocene Green River Formation in the Piceance Basin of northwestern Colorado was studied in detail using some 321,000 Fischer assay analyses in the U.S. Geological Survey oil-shale database. The oil-shale section was subdivided into 17 roughly time-stratigraphic intervals, and the distribution of water in each interval was assessed separately. This study was conducted in part to determine whether water produced during retorting of oil shale could provide a significant amount of the water needed for an oil-shale industry. Recent estimates of water requirements vary from 1 to 10 barrels of water per barrel of oil produced, depending on the type of retort process used. Sources of water in Green River oil shale include (1) free water within clay minerals; (2) water from the hydrated minerals nahcolite (NaHCO3), dawsonite (NaAl(OH)2CO3), and analcime (NaAlSi2O6.H20); and (3) minor water produced from the breakdown of organic matter in oil shale during retorting. The amounts represented by each of these sources vary both stratigraphically and areally within the basin. Clay is the most important source of water in the lower part of the oil-shale interval and in many basin-margin areas. Nahcolite and dawsonite are the dominant sources of water in the oil-shale and saline-mineral depocenter, and analcime is important in the upper part of the formation. Organic matter does not appear to be a major source of water. The ratio of water to oil generated with retorting is significantly less than 1:1 for most areas of the basin and for most stratigraphic intervals; thus water within oil shale can provide only a fraction of the water needed for an oil-shale industry.
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Studies of quaternary saline lakes-I. Hydrogen isotope fractionation in saline minerals
Matsuo, S.; Friedman, I.; Smith, G.I.
1972-01-01
Borax, gaylussite, nahcolite and trona were synthesized in aqueous solution at temperatures ranging from 8?? to 35??C. Except for borax, deuterium was always depleted in these hydrated minerals relative to the solutions from which they were crystallized. In borax, no significant fractionation was found. The fractionation factor of D H for the trona-water system exhibited a marked temperature dependence. By combining the deuterium contents of trona and the solution from which trona was crystallized, the following thermometer scale was obtained: In ( D H) trona ( D H)water = 1.420 ?? 104 T2 + 23.56 T (1). An attempt to establish a geothermometer based on C13 C12 fractionation between carbonate minerals and carbonate ions in aqueous solution was not successful. ?? 1972.
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Ege, John R.; Leavesley, G.H.; Steele, G.S.; Weeks, J.B.
1978-01-01
The U.S. Geological Survey is cooperating with the U.S. Bureau of Mines in the selection of a site for a shaft and experimental mine to be constructed in the Piceance Creek basin, Rio Blanco County, Colo. The Piceance Creek basin, an asymmetric, northwest-trending large structural downwarp, is located approximately 40 km (25 mi) west of the town of Meeker in Rio Blanco County, Colo. The oil-shale, dawsonite, nahcolite, and halite deposits of the Piceance Creek basin occur in the lacustrine Green River Formation of Eocene age. In the basin the Green River Formation comprises three members. In ascending order, they are the Douglas Creek, the Garden Gulch, and the Parachute Creek Members, Four sites are presented for consideration and evaluated on geology and hydrology with respect to shale-oil economics. Evaluated criteria include: (1) stratigraphy, (2) size of site, (3) oil-shale yield, (4) representative quantities of the saline minerals dawsonite and nahcolite, which must be present with a minimum amount of halite, (5) thickness of a 'leached' saline zone, (6) geologic structure, (7) engineering characteristics of rock, (8) representative surface and ground-water conditions, with emphasis on waste disposal and dewatering, and (9) environmental considerations. Serious construction and support problems are anticipated in sinking a deep shaft in the Piceance Creek basin. The two major concerns will be dealing with incompetent rock and large inflow of saline ground water, particularly in the leached zone. Engineering support problems will include stabilizing and hardening the rock from which a certain amount of ground water has been removed. The relative suitability of the four potential oil-shale experimental shaft sites in the Piceance Creek basin has been considered on the basis of all available geologic, hydrologic, and engineering data; site 2 is preferred to sites 1, 3, and 4, The units in this report are presented in the form: metric (English). Both units of
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Dietrich, John D.; Brownfield, Michael E.; Johnson, Ronald C.; Mercier, Tracey J.
2014-01-01
Recent studies indicate that the Piceance Basin in northwestern Colorado contains over 1.5 trillion barrels of oil in place, making the basin the largest known oil-shale deposit in the world. Previously published histograms display oil-yield variations with depth and widely correlate rich and lean oil-shale beds and zones throughout the basin. Histograms in this report display oil-yield data plotted alongside either water-yield or oil specific-gravity data. Fischer assay analyses of core and cutting samples collected from exploration drill holes penetrating the Eocene Green River Formation in the Piceance Basin can aid in determining the origins of those deposits, as well as estimating the amount of organic matter, halite, nahcolite, and water-bearing minerals. This report focuses only on the oil yield plotted against water yield and oil specific gravity.
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NASA Astrophysics Data System (ADS)
Perova, E. N.; Zaitsev, A. N.
2017-12-01
Carbonatites from the Oldoinyo Lengai volcano, northern Tanzania, are unstable under normal atmospheric conditions. Owing to carbonatite interaction with water, the major minerals—gregoryite Na2(CO3), nyerereite Na2Ca(CO3)2, and sylvite KCl—are dissolved and replaced with secondary low-temperature minerals: thermonatrite Na2(CO3) · H2O, trona Na3(CO3)(HCO3) · 2H2O, nahcolite Na(HCO3), pirssonite Na2Ca(CO3)2 · 2H2O, calcite Ca(CO3), and shortite Na2Ca2(CO3)3. Thermodynamic calculations show that the formation of secondary minerals in Oldoinyo Lengai carbonatites are controlled by the pH of the pore solution, H2O and CO2 fugacity, and the ratio of Ca and Na activity in the Na2O-CaO-CO2-H2O system.
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Birdwell, Justin E.; Mercier, Tracey J.; Johnson, Ronald C.; Brownfield, Michael E.; Dietrich, John D.
2014-01-01
A recent U.S. Geological Survey analysis of the Green River Formation of the Piceance Basin in western Colorado shows that about 920 and 352 billion barrels of oil are potentially recoverable from oil shale resources using oil-yield cutoffs of 15 and 25 gallons per ton (GPT), respectively. This represents most of the high-grade oil shale in the United States. Much of this rich oil shale is found in the dolomitic Parachute Creek Member of the Green River Formation and is associated with the saline minerals nahcolite and halite, or in the interval where these minerals have been leached by groundwater. The remaining high-grade resource is located primarily in the underlying illitic Garden Gulch Member of the Green River Formation. Of the 352 billion barrels of potentially recoverable oil resources in high-grade (≥25 GPT) oil shale, the relative proportions present in the illitic interval, non-saline R-2 zone, saline-mineral interval, leached interval (excluding leached Mahogany zone), and Mahogany zone were 3.1, 4.5, 36.6, 23.9, and 29.9 percent of the total, respectively. Only 2 percent of high-grade oil shale is present in marginal areas where saline minerals were never deposited.
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DOE Office of Scientific and Technical Information (OSTI.GOV)
Kalyoncu, R.S.; Boyer, J.P.; Snyder, M.J.
Partial data on the characterization of Well 0-1 (Christian County, Kentucky) shales were first reported in the Fifth Quarterly Technical Progress Report on January 1978. This report presents all the characterization data and its analysis on the 0-1 shales. Coring of Well 0-1 was accomplished in October 1976. A total of 17 samples were obtained, 13 for Battelle and 4 for other DOE Contractors. Methane is almost the sole hydrocarbon gas present in these shales, with higher chain hydrocarbon gases nearly nonexistent. An apparent increase in hydrocarbon gas contents with shale depth is observed. Other organic contents (in the formmore » of carbon and hydrogen) also show an increase with increasing shale depth. An increase in hydrocarbon gas contents with carbon and hydrogen contents is also noticeable. Natural gas, carbon and hydrogen contents all vary inversely with bulk densities. 0-1 shales show low mercury intrusion porosities and very low to negligible gas permeabilities. Lithology of these shales is very similar to those previously reported, quartz being the most abundant single mineral. Illite and kaolin are the major clay minerals with a number of carbonates (nahcolite, sortite, siderite) present in moderate quantities. Pyrite is also observed in significant quantities.« less
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Fitzpatrick, J.J.; Muhs, D.R.
1989-01-01
During the 1987-1988 austral summer field season, membersof the south party of the antarctic search for meteorites south-ern team* working in the Lewis Cliff/Colbert Hills region dis-covered several areas of unusual mineralization within theLewis Cliff ice tongue and its associated moraine field (figure1). The Lewis Cliff ice tongue (84°15'S 161°25'E) is a meteorite-stranding surface of ablating blue ice, about 2.3 by 7.0 kilo-meters, bounded on the west by the Lewis Cliff, on the northand northeast by a large supraglacial moraine, and on the eastby the Colbert Hills. To the south it opens to the Walcott Névé.Because it is a meteorite-stranding surface, the major component of ice motion in the area is believed to be vertical(Whillans and Cassidy 1983). The presence of Thule-Baffinmoraines at the northern terminus of the blue ice tends tosupport the hypothesis that the area underlying the moraineis essentially stagnant and that ice arriving from the south ispiling up against it. Areas containing mineral deposits werefound within the moraine field to the north and east of theblue ice margin and also along the east margins of the blue iceitself. Subsequent X-ray diffraction analyses of these depositshave shown that they are composed predominantly of nah-colite (NaHCO3), trona [Na3(CO3)(HCO3) · 2H20], borax[Na2B405(OH)4 · 8H20], and a new hexagonal hydrous sulfatespecies. This paper reports the details of the borax occurrence,because it is the first known on the continent.
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Carbonate, Halide, and Other New Mineral Inclusions in Diamond and Deep-Seated Carbonatitic Magma
NASA Astrophysics Data System (ADS)
Kaminsky, F.; Wirth, R.; Matsyuk, S.
2009-05-01
A series of uncommon micro- and nano-inclusions was identified in diamonds from the Juina area: carbonates, halides, and others. Carbonates are represented by calcite (with Sr and Ba), K-rich nyerereite (K2O = 10.0-13.78 wt. %), and nahcolite. Halides are NaCl, KCl, CaCl2 and PbCl2. Minerals of the periclase- wüstite series belong to two separate groups: wüstite and Mg-wüstite with Mg# = 1.9-15.3, and Fe-periclase and periclase with Mg# = 84.9-92.1. Wollastonite-II (high, Ca: Si = 0.992) has a triclinic structure. Ca-rich garnet has a noticeable admixture of Zr; it belongs to the andradite - kimzeyite - schorlomite group. Two types of spinel were distinguished among mineral inclusions in diamond: zoned magnesioferrite (with Mg# varying from 13.5 in a core to 90.8 in a rim) and Fe-spinel (magnetite). Olivine (Mg# = 93.6), intergrown with nyerereite, forms elongated, lath-shaped crystal and, probably, is a retrograde transformation of ringwoodite or wadsleyite. Some apatite grains are enriched in La, Ce and Nd. Among other minerals, there are anhydrite, cuspidine, phlogopite, TiO2 with an α-PbO2 structure, native Fe. All inclusions are polymineralic solid inclusions. These minerals form a carbonatitic-type mineral association in diamond which may have been originated in lower mantle and/or transition zone. Wüstite inclusions with Mg# = 1.9-3.4, according to the experimental data, may have been formed in the lowermost mantle. The source for the observed carbonatitic-type mineral association in diamond is deep-seated carbonatitic, most likely natrocarbonatitic magma.
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Smith, G.I.; Friedman, I.; McLaughlin, R.J.
1987-01-01
As a consequence of the 1969-1970 flooding of normally dry Owens Lake, a 2.4-m-deep lake formed and 20% of the 2-m-thick salt bed dissolved in it. Its desiccation began August 1969, and salts started crystallizing September 1970, ending August 1971. Mineralogic, brine-composition, and stable-isotope data plus field observations showed that while the evolving brine composition established the general crystallization timetable and range of primary and secondary mineral assemblages, it was the daily, monthly, and seasonal temperature changes that controlled the details of timing and mineralogy during this depositional process. Deuterium analyses of lake brine, interstitial brine, and hydrated saline phases helped confirm the sequence of mineral crystallizations and transformations, and they documented the sources and temperatures of waters involved in the reactions. Salts first crystallized as floating rafts on the lake surface. Natron and mirabilite, salts whose solubilities decrease greatly with lowering temperatures, crystallized late at night in winter, when surface-water temperatures reached their minima; trona, nahcolite, burkeite, and halite, salts with solubilities less sensitive to temperature, crystallized during the afternoon in summer, when surface salinities reached their maxima. However, different temperatures were generally associated with crystallization (at the surface) and accumulation (on the lake floor) because short-term temperature changes were transmitted to surface and bottom waters at different rates. Consequently, even when solubilities were exceeded at the surface, salts were preserved or not as a function of bottom-water temperatures. Halite, a nearly temperature-insensitive salt, was always preserved. Monitoring the lake-brine chemistry and mineralogy of the accumulating salts shows: (1) An estimated 0.9 ?? 106 tons of CO2 was released to the atmosphere or consumed by the lake's biomass prior to most salt crystallization. (2) After
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Ege, J.R.; Carroll, R.D.; Welder, F.A.
1967-01-01
Approximately 1,400 feet of continuous core was taken .between 800-2,214 feet in depth from USBM/AEC Colorado core hole No. 2. The drill, site is located in the Piceance Creek basin, Rio Blanco County, Colorado. From ground surface the drill hole penetrated 1,120 feet of the Evacuation Creek Member and 1,094 feet of oil shale in the Parachute Creek Member of the Green River Formation. Oil shale yielding more than 20 gallons per ton occurs between 1,260-2,214 feet in depth. A gas explosion near the bottom of the hole resulted in abandonment of the exploratory hole which was still in oil shale. The top of the nahcolite zone is at 1,693 feet. Below this depth the core contains common to abundant amounts of sodium bicarbonate salt intermixed with oil shale. The core is divided into seven structural zones that reflect changes in joint intensity, core loss and broken core due to natural causes. The zone of poor core recovery is in the Interval between 1,300-1,450 feet. Results of preliminary geophysical log analyses indicate that oil yields determined by Fischer assay compare favorably with yields determined by geophysical log analyses. There is strong evidence that analyses of complete core data from Colorado core holes No. 1 and No. 2 reveal a reliable relationship between geophysical log response and oil yield. The quality of the logs is poor in the rich shale section and the possibility of repeating the logging program should be considered. Observations during drilling, coring, and hydrologic testing of USBM/AEC Colorado core hole No. 2 reveal that the Parachute Creek Member of the Green River Formation is the principal aquifer water in the Parachute Creek Member is under artesian pressure. The upper part of the aquifer has a higher hydrostatic head than, and is hydrologically separated from the lower part of the aquifer. The transmissibility of the aquifer is about 3500 gpd per foot. The maximum water yield of the core hole during testing was about 500 gpm. Chemical