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Michael D. Lewan

Publications and source records attributed to Michael D. Lewan.

At least 19 recordsLinked to original sources
USGS2016

Input-form data for the U.S. Geological Survey assessment of the Mississippian Barnett Shale of the Bend Arch-Fort Worth Basin Province, 2015

In 2015, the U.S. Geological Survey (USGS) released an updated assessment of undiscovered, technically recoverable shale gas and shale oil resources of the Mississippian Barnett Shale in north-central Texas (Marra and others, 2015). The Barnett Shale was assessed using the standard continuous (unconventional) methodology established by the USGS for two assessment units (AUs): (1) Barnett Continuous Gas AU, and (2) Barnett Mixed Continuous Gas and Oil AU. A third assessment unit, the Western Barnett Continuous Oil AU, was also defined but was not quantitatively assessed because of limited data within the extent of the AU. The purpose of this report is to provide supplemental documentation of the quantitative input parameters applied in the Barnett Shale assessment.

Texas↗
USGS2014

Mineralogical, chemical and K-Ar isotopic changes in Kreyenhagen Shale whole rocks and <2 µm clay fractions during natural burial and hydrous-pyrolysis experimental maturation

Progressive maturation of the Eocene Kreyenhagen Shale from the San Joaquin Basin of California was studied by combining mineralogical and chemical analyses with K&ndash;Ar dating of whole rocks and <2 &mu;m clay fractions from naturally buried samples and laboratory induced maturation by hydrous pyrolysis of an immature outcrop sample. The K&ndash;Ar age decreases from 89.9 &plusmn; 3.9 and 72.4 &plusmn; 4.2 Ma for the outcrop whole rock and its <2 &mu;m fraction, respectively, to 29.7 &plusmn; 1.5 and 21.0 &plusmn; 0.7 Ma for the equivalent materials buried to 5167 m. The natural maturation does not produce K&ndash;Ar ages in the historical sense, but rather K/Ar ratios of relative K and radiogenic 40 Ar amounts resulting from a combined crystallization of authigenic and alteration of initial detrital K-bearing minerals of the rocks. The Al/K ratio of the naturally matured rocks is essentially constant for the entire depth sequence, indicating that there is no detectable variation in the crystallo-chemical organization of the K-bearing alumino-silicates with depth. No supply of K from outside of the rock volumes occurred, which indicates a closed-system behavior for it. Conversely, the content of the total organic carbon (TOC) content decreases significantly with burial, based on the progressive increasing Al/TOC ratio of the whole rocks. The initial varied mineralogy and chemistry of the rocks and their <2 &mu;m fractions resulting from differences in detrital sources and depositional settings give scattered results that homogenize progressively during burial due to increased authigenesis, and concomitant increased alteration of the detrital material. Hydrous pyrolysis was intended to alleviate the problem of mineral and chemical variations in initially deposited rocks of naturally matured sequences. However, experiments on aliquots from thermally immature Kreyenhagen Shale outcrop sample did not mimic the results from naturally buried samples. Experiments conducted for 72 h at temperatures from 270 to 365 &deg;C did not induce significant changes at temperatures above 310 &deg;C in the mineralogical composition and K&ndash;Ar ages of the rock and <2 &mu;m fraction. The K&ndash;Ar ages of the <2 &mu;m fraction range from 72.4 &plusmn; 4.2 Ma in the outcrop sample to 62.4 &plusmn; 3.4 Ma in the sample heated the most at 365 &deg;C for 216 h. This slight decrease in age outlines some loss of radiogenic 40 Ar, together with losses of organic matter as oil, gas, and aqueous organic species. Large amounts of smectite layers in the illite&ndash;smectite mixed layers of the pyrolyzed outcrop <2 &mu;m fraction remain during thermal experiments, especially above 310 &deg;C. With no illitization detected above 310 &deg;C, smectite appears to have inhibited rather than promoted generation of expelled oil from decomposition of bitumen. This hindrance is interpreted to result from bitumen impregnating the smectite interlayer sites and rock matrix. Bitumen remains in the <2 &mu;m fraction despite leaching with H 2 O 2 . Its presence in the smectite interlayers is apparent by the inability of the clay fraction to fully expand or collapse once bitumen generation from the thermal decomposition of the kerogen is completed, and by almost invariable K&ndash;Ar ages confirming for the lack of any K supply and/or radiogenic 40 Ar removal. This suggests that once bitumen impregnates the porosity of a progressively maturing source rock, the pore system is no longer wetted by water and smectite to illite conversion ceases. Experimental attempts to evaluate the smectite conversion to illite should preferentially use low-TOC rocks to avoid inhibition of the reaction by bitumen impregnation.

California↗
USGS2014

Re-Os geochronology and Os isotope fingerprinting of petroleum sourced from a Type I lacustrine kerogen: insights from the natural Green River petroleum system in the Uinta Basin and hydrous pyrolysis experiments

Rhenium–osmium (Re–Os) geochronology of marine petroleum systems has allowed the determination of the depositional age of source rocks as well as the timing of petroleum generation. In addition, Os isotopes have been applied as a fingerprinting tool to correlate oil to its source unit. To date, only classic marine petroleum systems have been studied. Here we present Re–Os geochronology and Os isotope fingerprinting of different petroleum phases (oils, tar sands and gilsonite) derived from the lacustrine Green River petroleum system in the Uinta Basin, USA. In addition we use an experimental approach, hydrous pyrolysis experiments, to compare to the Re–Os data of naturally generated petroleum in order to further understand the mechanisms of Re and Os transfer to petroleum. The Re–Os geochronology of petroleum from the lacustrine Green River petroleum system (19 ± 14 Ma – all petroleum phases) broadly agrees with previous petroleum generation basin models (∼25 Ma) suggesting that Re–Os geochronology of variable petroleum phases derived from lacustrine Type I kerogen has similar systematics to Type II kerogen (e.g., Selby and Creaser, 2005a, Selby and Creaser, 2005b and Finlay et al., 2010). However, the large uncertainties (over 100% in some cases) produced for the petroleum Re–Os geochronology are a result of multiple generation events occurring through a ∼3000-m thick source unit that creates a mixture of initial Os isotope compositions in the produced petroleum phases. The 187Os/188Os values for the petroleum and source rocks at the time of oil generation vary from 1.4 to 1.9, with the mode at ∼1.6. Oil-to-source correlation using Os isotopes is consistent with previous correlation studies in the Green River petroleum system, and illustrates the potential utility of Os isotopes to characterize the spatial variations within a petroleum system. Hydrous pyrolysis experiments on the Green River Formation source rocks show that Re and Os transfer are mimicking the natural system. This transfer from source to bitumen to oil does not affect source rock Re–Os systematics or Os isotopic compositions. This confirms that Os isotope compositions are transferred intact from source to petroleum during petroleum generation and can be used as a powerful correlation tool. These experiments further confirm that Re–Os systematics in source rocks are not adversely affected by petroleum maturation. Overall this study illustrates that the Re–Os petroleum geochronometer and Os isotope fingerprinting tools can be used on a wide range of petroleum types sourced from variable kerogen types.

Utah↗
USGS2014

Experimental investigation of changes in methane adsorption of bitumen-free Woodford Shale with thermal maturation induced by hydrous pyrolysis

This study quantifies the effects of organic-matter (OM) thermal maturity on methane (CH 4 ) sorption, on the basis of five samples that were artificially matured through hydrous pyrolysis achieved by heating samples of immature Woodford Shale under five different time–temperature conditions. CH 4 -sorption isotherms at 35 °C, 50 °C, and 65 °C, and pressures up to 14 MPa on dry, solvent-extracted samples of the artificially matured Woodford Shale were measured. The results showed that CH 4 -sorption capacity, normalized to TOC, varied with thermal maturity, following the trend: maximum oil (367 °C) > oil cracking (400 °C) > maximum bitumen/early oil (333 °C) > early bitumen (300 °C) > immature stage (130 °C). The Langmuir constants for the samples at maximum-oil and oil-cracking stages are larger than the values for the bitumen-forming stages. The total pore volume, determined by N 2 physisorption at 77 K, increases with increased maturation: mesopores, 2–50 nm in width, were created during the thermal conversion of organic-matter and a dramatic increase in porosity appeared when maximum-bitumen and maximum-oil generation stages were reached. A linear relationship between thermal maturity and Brunauer–Emmett–Teller (BET) surface area suggests that the observed increase in CH 4 -sorption capacity may be the result of mesopores produced during OM conversion. No obvious difference is observed in pore-size distribution and pore volume for samples with pores <2.0 nm with the increase of thermal maturity based on CO 2 physisorption at 273 K. The isosteric heat of adsorption and the standard entropy for artificially matured samples ranged from 17.9 kJ mol −1 to 21.9 kJ mol −1 and from −85.4 J mol −1 K −1 to −101.8 J mol −1 K −1 , respectively. These values are similar to the values of immature Woodford kerogen concentrate previously observed, but are larger than naturally matured organic-rich shales. High-temperature hydrous pyrolysis might have induced Lewis acid sites on both organic and mineral surfaces, resulting to some extent, in chemical interactions between the adsorption site and the methane C–H bonds. The formation of abundant mesopores (2–50 nm) within organic matter during organic-matter thermal maturation makes a great contribution to the increase in both BET surface area and pore volume, and a significant increase in 2–6 nm pores occurs at maximum-oil-generation and oil-cracking to gas, ultimately controlling the methane-adsorption capacity. Therefore, consideration of pore-size effects and thermal maturity is very important for gas in place (GIP) prediction in organic-rich shales.

Marine and Petroleum Geology↗
USGS2014

Differentiation of pre-existing trapped methane from thermogenic methane in an igneous-intruded coal by hydrous pyrolysis

So as to better understand how the gas generation potential of coal changes with increasing rank, same-seam samples of bituminous coal from the Illinois Basin that were naturally matured to varying degrees by the intrusion of an igneous dike were subjected to hydrous pyrolysis (HP) conditions of 360 °C for 72 h. The accumulated methane in the reactor headspace was analyzed for δ 13 C and δ2H, and mol percent composition. Maximum methane production (9.7 mg/g TOC) occurred in the most immature samples (0.5 %R o ), waning to minimal methane values at 2.44 %Ro (0.67 mg/g TOC), and rebounding to 3.6 mg/g TOC methane in the most mature sample (6.76 %R o ). Methane from coal with the highest initial thermal maturity (6.76 %R o ) shows no isotopic dependence on the reactor water and has a microbial δ 13 C value of −61‰. However, methane from coal of minimal initial thermal maturity (0.5 %R o ) shows hydrogen isotopic dependence on the reaction water and has a δ 13 C value of −37‰. The gas released from coals under hydrous pyrolysis conditions represents a quantifiable mixture of ancient (270 Ma) methane (likely microbial) that was generated in situ and trapped within the rock during the rapid heating by the dike, and modern (laboratory) thermogenic methane that was generated from the indigenous organic matter due to thermal maturation induced by hydrous pyrolysis conditions. These findings provide an analytical framework for better assessment of natural gas sources and for differentiating generated gas from pre-existing trapped gas in coals of various ranks.

Organic Geochemistry↗
USGS2014

Effects of smectite on the oil-expulsion efficiency of the Kreyenhagen Shale, San Joaquin Basin, California, based on hydrous-pyrolysis experiments

The amount of oil that maturing source rocks expel is expressed as their expulsion efficiency, which is usually stated in milligrams of expelled oil per gram of original total organic carbon (TOC O ). Oil-expulsion efficiency can be determined by heating thermally immature source rocks in the presence of liquid water (i.e., hydrous pyrolysis) at temperatures between 350&deg;C and 365&deg;C for 72 hr. This pyrolysis method generates oil that is compositionally similar to natural crude oil and expels it by processes operative in the subsurface. Consequently, hydrous pyrolysis provides a means to determine oil-expulsion efficiencies and the rock properties that influence them. Smectite in source rocks has previously been considered to promote oil generation and expulsion and is the focus of this hydrous-pyrolysis study involving a representative sample of smectite-rich source rock from the Eocene Kreyenhagen Shale in the San Joaquin Basin of California. Smectite is the major clay mineral (31 wt. %) in this thermally immature sample, which contains 9.4 wt. % total organic carbon (TOC) comprised of type II kerogen. Compared to other immature source rocks that lack smectite as their major clay mineral, the expulsion efficiency of the Kreyenhagen Shale was significantly lower. The expulsion efficiency of the Kreyenhagen whole rock was reduced 88% compared to that of its isolated kerogen. This significant reduction is attributed to bitumen impregnating the smectite interlayers in addition to the rock matrix. Within the interlayers, much of the bitumen is converted to pyrobitumen through crosslinking instead of oil through thermal cracking. As a result, smectite does not promote oil generation but inhibits it. Bitumen impregnation of the rock matrix and smectite interlayers results in the rock pore system changing from water wet to bitumen wet. This change prevents potassium ion (K + ) transfer and dissolution and precipitation reactions needed for the conversion of smectite to illite. As a result, illitization only reaches 35% to 40% at 310&deg;C for 72 hr and remains unchanged to 365&deg;C for 72 hr. Bitumen generation before or during early illitization in these experiments emphasizes the importance of knowing when and to what degree illitization occurs in natural maturation of a smectite-rich source rock to determine its expulsion efficiency. Complete illitization prior to bitumen generation is common for Paleozoic source rocks (e.g., Woodford Shale and Retort Phosphatic Shale Member of the Phosphoria Formation), and expulsion efficiencies can be determined on immature samples by hydrous pyrolysis. Conversely, smectite is more common in Cenozoic source rocks like the Kreyenhagen Shale, and expulsion efficiencies determined by hydrous pyrolysis need to be made on samples that reflect the level of illitization at or near bitumen generation in the subsurface.

California↗
USGS2013

Geochemical changes and fracture development in Woodford Shale cores following hydrous pyrolysis under uniaxial confinement

A uniaxial confinement clamp was used on Woodford Shale cores in hydrous pyrolysis experiments to study fracture development during thermal maturation. The clamp simulates overburden in that it prevents cores from expanding perpendicular to bedding fabric during the volume-increasing reactions associated with petroleum generation. Cores were cut from a slab of immature Woodford Shale and subjected to hydrous pyrolysis under confinement at 300, 330, and 365 °C for 72 hours to induce thermal maturities ranging from early bitumen to maximum expelled-oil generation. Two additional cores were used as experimental controls: (1) a confined core was saturated with water by heating it to 100 °C under hydrous pyrolysis conditions for 72 hours to use for characterization of the original rock, and (2) an unconfined core was heated at 365 °C for 72 hours to evaluate the effects of confinement on petroleum generation and expulsion. X-ray computed tomography (X-CT) imaging and other analyses identified five distinct beds within the cored interval. Using a tentative classification system, beds 1, 2, and 3 are described as dolomitic marlstone (DM) with total organic carbon (TOC) contents of 7.7, 5.8, and 7.7 wt. %, respectively; bed 4 is a cherty quartzose claystone (CQC) with TOC content of 5.5 wt. %; and bed 5 is a quartzose claystone with TOC content of 10.9 wt. %. Bed samples all had similar Rock-Eval hydrogen indices (600 ± 46 mg S2/g-TOC) and Tmax values (433 ± 2 °C), demonstrating organic matter uniformity and low thermal maturity. The X-CT scan of the core heated to 100 °C showed preexisting fractures that were nearly perpendicular to the bedding fabric primarily in the low-TOC DM bed 2 and CQC bed 4. Heating led to enhancement of preexisting fractures in the confined cores with the greatest enhancement occurring in CQC bed 4. The fractures increased in size and intensity with temperature. This is attributed to the internal pressure generated by volume-increasing reactions during the conversion of kerogen to bitumen and bitumen to oil and gas. The unconfined core heated to 365 °C showed no enhanced fracturing and its X-CT-scan resembled that of the 100 °C confined core. Comparison of the oil and gas yields from the confined and unconfined cores heated to 365 °C showed no significant differences, indicating that product expulsion is not inhibited by the procedure used in this study. These results also indicate that fracturing during thermal maturation is driven primarily by the enhancement of existing fractures.

Conference Paper↗
USGS2013

Changes in porosity and organic matter phase distribution monitored by NMR relaxometry following hydrous pyrolysis under uniaxial confinement

Artificial maturation methods are used to induce changes in source rock thermal maturity without the uncertainties that arise when comparing natural samples from a particular basin that often represent different levels of maturation and different lithofacies. A novel uniaxial confinement clamp was used on Woodford Shale cores in hydrous pyrolysis experiments to limit sample expansion by simulating the effect of overburden present during thermal maturation in natural systems. These samples were then subjected to X-ray computed tomography (X-CT) imaging and low-field nuclear magnetic resonance (LF-NMR) relaxometry measurements. LF-NMR relaxometry is a noninvasive technique commonly used to measure porosity and pore-size distributions in fluid-filled porous media, but may also measure hydrogen present in hydrogen-bearing organic solids. Standard T 1 and T 2 relaxation distributions were determined and two dimensional T 1 -T 2 correlation measurements were performed on the Woodford Shale cores. The T 1 -T 2 correlations facilitate resolution of organic phases in the system. The changes observed in NMR-relaxation times correspond to bitumen and lighter hydrocarbon production that occur as source rock organic matter matures. The LF-NMR porosities of the core samples at maximum oil generation are significantly higher than porosities measured by other methods. This discrepancy likely arises from the measurement of highly viscous organic constituents in addition to fluid-filled porosity. An unconfined sample showed shorter relaxation times and lower porosity. This difference is attributed to the lack of fractures observed in the unconfined sample by X-CT.

Conference Paper↗
USGS2013

Application of uniaxial confining-core clamp with hydrous pyrolysis in petrophysical and geochemical studies of source rocks at various thermal maturities

Understanding changes in petrophysical and geochemical parameters during source rock thermal maturation is a critical component in evaluating source-rock petroleum accumulations. Natural core data are preferred, but obtaining cores that represent the same facies of a source rock at different thermal maturities is seldom possible. An alternative approach is to induce thermal maturity changes by laboratory pyrolysis on aliquots of a source-rock sample of a given facies of interest. Hydrous pyrolysis is an effective way to induce thermal maturity on source-rock cores and provide expelled oils that are similar in composition to natural crude oils. However, net-volume increases during bitumen and oil generation result in expanded cores due to opening of bedding-plane partings. Although meaningful geochemical measurements on expanded, recovered cores are possible, the utility of the core for measuring petrophysical properties relevant to natural subsurface cores is not suitable. This problem created during hydrous pyrolysis is alleviated by using a stainless steel uniaxial confinement clamp on rock cores cut perpendicular to bedding fabric. The clamp prevents expansion just as overburden does during natural petroleum formation in the subsurface. As a result, intact cores can be recovered at various thermal maturities for the measurement of petrophysical properties as well as for geochemical analyses. This approach has been applied to 1.7-inch diameter cores taken perpendicular to the bedding fabric of a 2.3- to 2.4-inch thick slab of Mahogany oil shale from the Eocene Green River Formation. Cores were subjected to hydrous pyrolysis at 360 °C for 72 h, which represents near maximum oil generation. One core was heated unconfined and the other was heated in the uniaxial confinement clamp. The unconfined core developed open tensile fractures parallel to the bedding fabric that result in a 38 % vertical expansion of the core. These open fractures did not occur in the confined core, but short, discontinuous vertical fractures on the core periphery occurred as a result of lateral expansion.

Conference Paper↗
USGS2013

Assessment of undiscovered oil resources in the Bakken and Three Forks Formations, Williston Basin Province, Montana, North Dakota, and South Dakota, 2013

Using a geology-based assessment methodology, the U.S. Geological Survey estimated mean undiscovered volumes of 7.4 billion barrels of oil, 6.7 trillion cubic feet of associated/dissolved natural gas, and 0.53 billion barrels of natural gas liquids in the Bakken and Three Forks Formations in the Williston Basin Province of Montana, North Dakota, and South Dakota.

Montana, North Dakota, South Dakota↗
USGS2013

Input-form data for the U.S. Geological Survey assessment of the Devonian and Mississippian Bakken and Devonian Three Forks Formations of the U.S. Williston Basin Province, 2013

In 2013, the U.S. Geological Survey assessed the technically recoverable oil and gas resources of the Bakken and Three Forks Formations of the U.S. portion of the Williston Basin. The Bakken and Three Forks Formations were assessed as continuous and hypothetical conventional oil accumulations using a methodology similar to that used in the assessment of other continuous- and conventional-type assessment units throughout the United States. The purpose of this report is to provide supplemental documentation and information used in the Bakken-Three Forks assessment.

Montana;North Dakota;South Dakota↗
USGS2012

Assessment of undiscovered oil and gas resources in conventional and continuous petroleum systems in the Upper Cretaceous Eagle Ford Group, U.S. Gulf Coast region, 2011

Using a geology-based assessment methodology, the U.S. Geological Survey assessed means of (1) 141 million barrels of oil (MMBO), 502 billion cubic feet of natural gas (BCFG), and 16 million barrels of natural gas liquids (MMBNGL) in the conventional Eagle Ford Updip Sandstone Oil and Gas Assessment Unit (AU); (2) 853 MMBO, 1,707 BCFG, and 34 MMBNGL in the continuous Eagle Ford Shale Oil AU; and (3) 50,219 BCFG and 2,009 MMBNGL in the continuous Eagle Ford Shale Gas AU in onshore lands and State waters of the Gulf Coast.

Gulf Coast Region↗
USGS2008

Assessment of undiscovered oil and gas resources of the Williston Basin Province of North Dakota, Montana, and South Dakota, 2008

Using a geology-based assessment method, the U.S. Geological Survey estimated mean undiscovered volumes of 3.8 billion barrels of undiscovered oil, 3.7 trillion cubic feet of associated/dissolved natural gas, and 0.2 billion barrels of undiscovered natural gas liquids in the Williston Basin Province, North Dakota, Montana, and South Dakota. (See “Introduction” in Fact Sheet for additional information.)

Montana, North Dakota, South Dakota↗
USGS2008

Burial History, Thermal Maturity, and Oil and Gas Generation History of Source Rocks in the Bighorn Basin, Wyoming and Montana

Burial history, thermal maturity, and timing of oil and gas generation were modeled for seven key source-rock units at eight well locations throughout the Bighorn Basin in Wyoming and Montana. Also modeled was the timing of cracking to gas of Phosphoria Formation-sourced oil in the Permian Park City Formation reservoirs at two well locations. Within the basin boundary, the Phosphoria is thin and only locally rich in organic carbon; it is thought that the Phosphoria oil produced from Park City and other reservoirs migrated from the Idaho-Wyoming thrust belt. Other petroleum source rocks include the Cretaceous Thermopolis Shale, Mowry Shale, Frontier Formation, Cody Shale, Mesaverde and Meeteetse Formations, and the Tertiary (Paleocene) Fort Union Formation. Locations (wells) selected for burial history reconstructions include three in the deepest parts of the Bighorn Basin (Emblem Bench, Red Point/Husky, and Sellers Draw), three at intermediate depths (Amoco BN 1, Santa Fe Tatman, and McCulloch Peak), and two at relatively shallow locations (Dobie Creek and Doctor Ditch). The thermal maturity of source rocks is greatest in the deep central part of the basin and decreases to the south, east, and north toward the basin margins. The Thermopolis and Mowry Shales are predominantly gas-prone source rocks, containing a mix of Type-III and Type-II kerogens. The Frontier, Cody, Mesaverde, Meeteetse, and Fort Union Formations are gas-prone source rocks containing Type-III kerogen. Modeling results indicate that in the deepest areas, (1) the onset of petroleum generation from Cretaceous rocks occurred from early Paleocene through early Eocene time, (2) peak petroleum generation from Cretaceous rocks occurred during Eocene time, and (3) onset of gas generation from the Fort Union Formation occurred during early Eocene time and peak generation occurred from late Eocene to early Miocene time. Only in the deepest part of the basin did the oil generated from the Thermopolis and Mowry Shales start generating gas from secondary cracking, which occurred in the late Eocene to Miocene. Also, based on modeling results, gas generation from the cracking of Phosphoria oil reservoired in the Park City Formation began in the late Eocene in the deep part of the basin but did not anywhere reach peak generation.

Scientific Investigations Report↗
USGS2007

Burial history, thermal maturity, and oil and gas generation history of petroleum systems in the Wind River Basin Province, central Wyoming: Chapter 6 in Petroleum systems and geologic assessment of oil and gas resources in the Wind River Basin Province, Wyoming

Burial history, thermal maturity, and timing of oil and gas generation were modeled for eight key source rock units at nine well locations throughout the Wind River Basin Province. Petroleum source rocks include the Permian Phosphoria Formation, the Cretaceous Mowry Shale, Cody Shale, and Mesaverde, Meeteetse, and Lance Formations, and the Tertiary (Paleocene) Fort Union Formation, including the Waltman Shale Member. Within the province boundary, the Phosphoria is thin and only locally rich in organic carbon. Phosphoria oil produced from reservoirs in the province is thought to have migrated from the Wyoming and Idaho thrust belt. Locations (wells) selected for burial history reconstructions include three in the deepest parts of the province (Adams OAB-17, Bighorn 1-5, and Coastal Owl Creek); three at intermediate depths (Hells Half Acre, Shell 33X-10, and West Poison Spider); and three at relatively shallow locations (Young Ranch, Amoco Unit 100, and Conoco-Coal Bank). The thermal maturity of source rocks is greatest in the deep northern and central parts of the province and decreases to the south and east toward the basin margins. The results of the modeling indicate that, in the deepest areas, (1) peak petroleum generation from Cretaceous rocks occurred from Late Cretaceous through middle Eocene time, and (2) onset of oil generation from the Waltman Shale Member occurred from late Eocene to early Miocene time. Based on modeling results, gas generation from the cracking of Phosphoria oil reservoired in the Park City Formation reached a peak in the late Paleocene/early Eocene (58 to 55 Ma) only in the deepest parts of the province. The Mowry Shale and Cody Shale (in the eastern half of the basin) contain a mix of Type-II and Type-III kerogens. Oil generation from predominantly Type-II source rocks of these units in the deepest parts of the province reached peak rates during the latest Cretaceous to early Eocene (65 to 55 Ma). Only in these areas of the basin did these units reach peak gas generation from the cracking of oil, which occurred in the early to middle Eocene (55 to 42 Ma). Gas-prone source rocks of the Mowry and Cody Shales (predominantly Type-III kerogen), and the Mesaverde, Meeteetse, Lance, and Fort Union Formations (Type –III kerogen) reached peak gas generation in the latest Cretaceous to late Eocene (67 to 38 Ma) in the deepest parts of the province. Gas generation from the Mesaverde source rocks started at all of the modeled locations but reached peak generation at only the deepest locations and at the Hells Half Acre location in the middle Paleocene to early Eocene (59 to 48 Ma). Also at the deepest locations, peak gas generation occurred from the late Paleocene to the early Eocene (57 to 49 Ma) for the Meeteetse Formation, and during the Eocene for the Lance Formation (55 to 48 Ma) and the Fort Union Formation (44 to 38 Ma). The Waltman Shale Member of the Fort Union Formation contains Type-II kerogen. The base of the Waltman reached a level of thermal maturity to generate oil only at the deep-basin locations (Adams OAB-17 and Bighorn 1-5 locations) in the middle Eocene to early Miocene (36 to 20 Ma).

Wyoming↗