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Paul G. Lillis

Publications and source records attributed to Paul G. Lillis.

At least 37 records · Page 2Linked to original sources
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↗
USGS2013

Review of oil families and their petroleum systems of the Williston Basin

The petroleum system concept was first applied in 1974 (Dow/Williams) to identify three oil systems in the Williston Basin, and recent studies have expanded the number to at least nine. This paper reviews the petroleum geochemistry, oil-oil, and oil-source correlations of the oil systems of the Williston Basin, providing a new perspective and some new findings. Petroleum systems with a known source (documented oil-source correlation) include the Red River (Ordovician), Winnipegosis (Devonian), Bakken (Devonian-Mississippian), Madison (Mississippian), and Tyler (Pennsylvanian) systems. Petroleum systems with an identified source rock but no documented oil-source correlation are considered hypothetical and include the Winnipeg (Ordovician), Duperow (Devonian), and Birdbear (Devonian). The Deadwood (Cambrian-Ordovician) petroleum system is speculative because a good oil-prone source rock has not been identified. The stratigraphic distribution of the oil families from each system is generally limited to the same formation from which they were sourced due to efficient seals and a paucity of vertical migration pathways, but some notable exceptions do occur. Oil bulk properties such as API gravity, sulfur content, and pour point are much underutilized in the recent geochemical literature and are found to be useful here in differentiating oil families. The Red River petroleum system has two oil families that can be differentiated based on pour point. The oils in the Madison petroleum system can be divided into two families based on API gravity-sulfur content relationships, with one family derived from Type II-S kerogen and the other family derived from Type II kerogen with medium sulfur content. The Tyler petroleum system of the Williston Basin may be distinguished from the Heath-Tyler petroleum system in central Montana based on differences in geology and petroleum geochemistry, with Tyler petroleum system oils having a higher pour point and lower sulfur content.

Williston Basin↗
USGS2013

Hydrocarbon-bearing sandstone in the Upper Jurassic Naknek Formation on the south shore of Kamishak Bay

The presence of an active petroleum system in Kamishak Bay is demonstrated by an outcrop of hydrocarbon-bearing sandstone in the Upper Jurassic Naknek Formation near the south shore of the bay (fig. 1). The outcrop is about 140 km southwest of Homer on a small, unnamed island near the mouth of the Douglas River (fig. 17). The existence of this outcrop was kindly reported to us by Les Magoon (U.S. Geological Survey, emeritus), who also provided a topographic map showing its exact position. The outcrop was mentioned very briefly in publications by Magoon and others (1975, p. 19) and by Lyle and Morehouse (1977, p. E-1), but to our knowledge there are no detailed descriptions of this outcrop or its hydrocarbons in the published scientific literature.

Alaska↗
USGS2012

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

Two oil families in Ordovician reservoirs from the cratonic region of the Tarim Basin are distinguished by the distribution of regular steranes, triaromatic steroids, norcholestanes and dinosteroids. Oils with relatively lower contents of C 28 regular steranes, C 26 20S, C 26 20R + C 27 20S and C 27 20R regular triaromatic steroids, dinosteranes, 24-norcholestanes and triaromatic dinosteroids originated from Middle–Upper Ordovician source rocks. In contrast, oils with abnormally high abundances of the above compounds are derived from Cambrian and Lower Ordovician source rocks. Only a few oils have previously been reported to be of Cambrian and Lower Ordovician origin, especially in the east region of the Tarim Basin. This study further reports the discovery of oil accumulations of Cambrian and Lower Ordovician origin in the Tabei and Tazhong Uplifts, which indicates a potential for further discoveries involving Cambrian and Lower Ordovician sourced oils in the Tarim Basin. Dinosteroids in petroleum and ancient sediments are generally thought to be biomarkers for dinoflagellates and 24-norcholestanes for dinoflagellates and diatoms. Therefore, the abnormally high abundance of these compounds in extracts from the organic-rich sediments in the Cambrian and Lower Ordovician and related oils in the cratonic region of the Tarim Basin suggests that phytoplankton algae related to dinoflagellates have appeared and might have flourished in the Tarim Basin during the Cambrian Period. Steroids with less common structural configurations are underutilized and can expand understanding of the early development history of organisms, as well as define petroleum systems.

Tarim Basin↗
USGS2012

Re–Os geochronology of the lacustrine Green River Formation: Insights into direct depositional dating of lacustrine successions, Re–Os systematics and paleocontinental weathering

Lacustrine sedimentary successions provide exceptionally high-resolution records of continental geological processes, responding to tectonic, climatic and magmatic influences. These successions are therefore essential for correlating geological and climatic phenomena across continents and furthermore the globe. Producing accurate geochronological frameworks within lacustrine strata is challenging because the stratigraphy is often bereft of biostratigraphy and directly dateable tuff horizons. The rhenium–osmium (Re–Os) geochronometer is a well-established tool for determining precise and accurate depositional ages of marine organic-rich rocks. Lake systems with stratified water columns are predisposed to the preservation of organic-rich rocks and thus should permit direct Re–Os geochronology of lacustrine strata. We present Re–Os systematics from one of the world's best documented lacustrine systems, the Eocene Green River Formation, providing accurate Re–Os depositional dates that are supported by Ar–Ar and U–Pb ages of intercalated tuff horizons. Precision of the Green River Formation Re–Os dates is controlled by the variation in initial 187 Os/ 188 Os and the range of 187 Re/ 188 Os ratios, as also documented in marine systems. Controls on uptake and fractionation of Re and Os are considered to relate mainly to depositional setting and the type of organic matter deposited, with the need to further understand the chelating precursors of Re and Os in organic matter highlighted. In addition to geochronology, the Re–Os data records the 187Os/188Os composition of lake water (1.41–1.54) at the time of deposition, giving an insight into continental runoff derived from weathering of the geological hinterland of the Green River Formation. Such insights enable us to evaluate fluctuations in continental climatic, tectonic and magmatic processes and provide the ability for chemostratigraphic correlation combined with direct depositional dates. Furthermore, initial 187Os/188Os values can be used as a diagnostic tool to distinguish between lacustrine and marine depositional settings when compared to known oceanic 187 Os/ 188 Os values.

Colorado;Utah;Wyoming↗
USGS2011

Assessment of undiscovered oil and gas resources of the Cook Inlet region, south-central Alaska, 2011

The U.S. Geological Survey (USGS) recently completed a new assessment of undiscovered, technically recoverable oil and gas resources in the Cook Inlet region of south-central Alaska. Using a geology-based assessment methodology, the USGS estimates that mean undiscovered volumes of nearly 600 million barrels of oil, about 19 trillion cubic feet of natural gas, and 46 million barrels of natural gas liquids remain to be found in this area.

Alaska↗
USGS2010

Geology and undiscovered oil and gas resources in the Madison Group, Williston Basin, North Dakota and Montana

Two of the total petroleum systems (TPS) defined as part of the U.S. Geological Survey (USGS) assessment of the Williston Basin contain Mississippian Madison Group strata: 1) the Bakken-Lodgepole TPS, which includes the Lodgepole Formation; and 2) the Madison TPS, which includes the Mission Canyon, Charles, and Spearfish formations. The Bakken-Lodgepole TPS is defined as the area in which oil generated from the upper and lower shales of the Upper Devonian-Lower Mississippian Bakken Formation has accumulated in reservoirs in the Three Forks, Bakken, and Lodgepole formations. Two conventional assessment units (AU) have been identified within the Bakken-Lodgepole TPS, including one in the Bakken Formation and another in the Waulsortian mound reservoirs of the lower Lodgepole Formation. Lodgepole Formation Waulsortian mound oil production has been restricted to a small part of Stark County, North Dakota. Reservoirs are sealed by middle and upper Lodgepole Formation tight argillaceous limestones. Several nonproductive mounds and mound-like structures have also been identified in the Lodgepole Formation. Productivity correlates closely with the oil window of the Bakken Formation shales, and also indicates the likelihood of limited lateral migration of Bakken Formation oil into Lodgepole Formation reservoirs in North Dakota and Montana. Such considerations limit the estimated mean of undiscovered, technically recoverable resources to 8 million barrels of oil (MMBO) for the Lodgepole Formation conventional reservoirs. The Madison TPS is defined as the area where oil generated from Mission Canyon and Charles formation source rocks has accumulated in reservoirs of the Mission Canyon and Charles formations and in reservoirs within the Triassic Spearfish Formation. One continuous reservoir AU, the Mission Canyon-Charles AU, was defined within the Madison TPS; its boundary coincides with the TPS boundary. There is extensive conventional production throughout the AU on major structures and in stratigraphic-structural traps. The largest fields are on the Little Knife, Billings Nose, and Nesson anticlines. Recent studies show that Madison Group oils were generated from organic-rich Mission Canyon Formation and Ratcliffe Interval carbonates adjacent to the reservoirs. Seals were formed by overlying or lateral evaporites or tight carbonates. Based on available geologic and production data, the undiscovered oil resources for conventional reservoirs in the Mission Canyon-Charles AU were estimated to have a mean of 45 MMBO.

Mountain Geologist↗
USGS2009

Petroleum systems used to determine the assessment units in the San Joaquin Basin Province, California

For the San Joaquin Basin Province in California (fig. 8.1), six petroleum systems were identified, mapped, and described to provide the basis for the five total petroleum systems (TPS) and ten related assessment units (AU) used in the 2003 U.S. Geological Survey (USGS) National Oil and Gas Assessment (table 8.1; Gautier and others, 2004; Hosford Scheirer, 2007). The petroleum pools in the province were allocated to each petroleum system on the basis of (1) geochemical composition as described by Lillis and Magoon (this volume, chapter 9) and Lillis and others (this volume, chapter 10), (2) reservoir rock nomenclature (fig 8.2; appendix 8.1 and appendix 8.2) as described by Hosford Scheirer and Magoon (this volume, chapter 5), and (3) the volume of oil and gas discovered for each petroleum system by system, flank, and trap type (tables 8.2, 8.3 and 8.4). For this assessment, each petroleum system was determined, followed by the TPS from one or more petroleum systems. For example, the Miocene TPS includes two petroleum systems, the McLure-Tulare(!) and Antelope-Stevens(!) (notation described in Petroleum System Name section, below). Magoon and Schmoker (2000) describe how the TPS is used in this and the USGS world assessments. This chapter describes the six petroleum systems used to make five total petroleum systems in this San Joaquin Basin Province assessment. The figures and tables for each petroleum system and TPS are as follows: (1) the San Joaquin(?) petroleum system or the Neogene Nonassociated Gas TPS is a natural gas system in the southeast part of the province (figs. 8.3 through 8.8; table 8.5; this volume, chapter 22); (2) the Miocene TPS (this volume, chapters 13, 14, 15, 16, and 17) includes the McLure-Tulare(!) petroleum system north of the Bakersfield Arch (figs. 8.9 through 8.13; table 8.6), and the Antelope-Stevens(!) petroleum system south of the arch (figs. 8.14 through 8.18; table 8.7), and is summarized in figure 8.19; (3) the Eocene TPS (this volume, chapters 18 and 19) combines two petroleum systems, the Tumey-Temblor(.) covering much of the province (figs. 8.20 through 8.24; table 8.8) and the underlying Kreyenhagen-Temblor(!) (figs. 8.25 through 8.29: table 8.9), and is summarized in figure 8.30; (4) the Eocene-Miocene Composite TPS, formed by combining the Miocene and Eocene TPS (this volume, chapter 20); and (5) the Moreno-Nortonville(.) is both a petroleum system and a TPS consisting mainly of natural gas in the northern part of the province (figs. 8.31 through 8.36: table 8.10; this volume, chapter 21). Oil samples with geochemistry from surface seeps and wells used to map these petroleum systems are listed in table 8.11. Finally, the volume of oil and gas expelled by each pod of active source rock was calculated and compared with the discovered hydrocarbons in each petroleum system (figs. 8.37 through 8.39; tables 8.12 and 8.13).

California↗
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

Petroleum systems of the San Joaquin Basin Province -- geochemical characteristics of gas types

The San Joaquin Basin Province is a petroliferous basin filled with predominantly Late Cretaceous to Pliocene-aged sediments, with organic-rich marine rocks of Late Cretaceous, Eocene, and Miocene age providing the source of most of the oil and gas. Previous geochemical studies have focused on the origin of the oil in the province, but the origin of the natural gas has received little attention. To identify and characterize natural gas types in the San Joaquin Basin, 66 gas samples were analyzed and combined with analyses of 15 gas samples from previous studies. For the purpose of this resource assessment, each gas type was assigned to the most likely petroleum system. Three general gas types are identified on the basis of bulk and stable carbon isotopic composition—thermogenic dry (TD), thermogenic wet (TW) and biogenic (B). The thermogenic gas types are further subdivided on the basis of the δ 13 C values of methane and ethane and nitrogen content into TD-1, TD-2, TD-Mixed, TW-1, TW-2, and TW-Mixed. Gas types TD-1 and TD-Mixed, a mixture of biogenic and TD-1 gases, are produced from gas fields in the northern San Joaquin Basin. Type TD-1 gas most likely originated from the Late Cretaceous to Paleocene Moreno Formation, a gas-prone source rock. The biogenic component of the TD-Mixed gas existed in the trap prior to the influx of thermogenic gas. For the assessment, these gas types were assigned to the Winters- Domengine Total Petroleum System, but subsequent to the assessment were reclassified as part of the Moreno-Nortonville gas system. Dry thermogenic gas produced from oil fields in the southern San Joaquin Basin (TD-2 gas) most likely originated from the oil-prone source rock of Miocene age. These samples have low wetness values due to migration fractionation or biodegradation. The thermogenic wet gas types (TW-1, TW-2, TW-Mixed) are predominantly associated gas produced from oil fields in the southern and central San Joaquin Basin. Type TW-1 gas most likely originates from source rocks within the Eocene Kreyenhagen Formation or the Eocene Tumey formation of Atwill (1935). Type TW-2 gas most likely originates from the Miocene Monterey Formation and equivalents. TW-Mixed gas is likely a mixture of biogenic and wet thermogenic gas (TW-1 or TW-2) derived from source rocks mentioned above. The thermogenic wet gas types are included in the corresponding Eocene or Miocene total petroleum systems. Type B gas is a dry, nonassociated gas produced from the Pliocene San Joaquin Formation in the central and southern San Joaquin Basin. This gas type most likely originated from Pliocene marine source rocks as a product of methanogenesis, and defines the Neogene Nonassociated Gas Total Petroleum System.

California↗
USGS2008

A four-dimensional petroleum systems model for the San Joaquin Basin Province, California:

A calibrated numerical model depicts the geometry and three-dimensional (3-D) evolution of petroleum systems through time (4-D) in a 249 x 309 km (155 x 192 mi) area covering all of the San Joaquin Basin Province of California. Model input includes 3-D structural and stratigraphic data for key horizons and maps of unit thickness, lithology, paleobathymetry, heat flow, original total organic carbon, and original Rock-Eval pyrolysis hydrogen index for each source rock. The four principal petroleum source rocks in the basin are the Miocene Antelope shale of Graham and Williams (1985; hereafter referred to as Antelope shale), the Eocene Kreyenhagen Formation, the Eocene Tumey formation of Atwill (1935; hereafter referred to as Tumey formation), and the Cretaceous to Paleocene Moreno Formation. Due to limited Rock-Eval/total organic carbon data, the Tumey formation was modeled using constant values of original total organic carbon and original hydrogen index. Maps of original total organic carbon and original hydrogen index were created for the other three source rocks. The Antelope shale was modeled using Type IIS kerogen kinetics, whereas Type II kinetics were used for the other source rocks. Four-dimensional modeling and geologic field evidence indicate that maximum burial of the three principal Cenozoic source rocks occurred in latest Pliocene to Holocene time. For example, a 1-D extraction of burial history from the 4-D model in the Tejon depocenter shows that the bottom of the Antelope shale source rock began expulsion (10 percent transformation ratio) about 4.6 Ma and reached peak expulsion (50 percent transformation ratio) about 3.6 Ma. Except on the west flank of the basin, where steep dips in outcrop and seismic data indicate substantial uplift, little or no section has been eroded. Most petroleum migration occurred during late Cenozoic time in distinct stratigraphic intervals along east-west pathways from pods of active petroleum source rock in the Tejon and Buttonwillow depocenters to updip sandstone reservoirs. Satisfactory runs of the model required about 18 hours of computation time for each simulation using parallel processing on a Linux-based cluster.

California↗
USGS2007

Executive Summary — Assessment of undiscovered oil and gas resources of the San Joaquin Basin Province of California, 2003

In 2003, the U.S. Geological Survey (USGS) completed an assessment of the oil and gas resource potential of the San Joaquin Basin Province of California (fig. 1.1). The assessment is based on the geologic elements of each Total Petroleum System defined in the province, including hydrocarbon source rocks (source-rock type and maturation and hydrocarbon generation and migration), reservoir rocks (sequence stratigraphy and petrophysical properties), and hydrocarbon traps (trap formation and timing). Using this geologic framework, the USGS defined five total petroleum systems and ten assessment units within these systems. Undiscovered oil and gas resources were quantitatively estimated for the ten assessment units (table 1.1). In addition, the potential was estimated for further growth of reserves in existing oil fields of the San Joaquin Basin.

California↗
USGS2007

Regional Fluid Flow and Basin Modeling in Northern Alaska

The foothills of the Brooks Range contain an enormous accumulation of zinc (Zn) in the form of zinc sulfide and barium (Ba) in the form of barite in Carboniferous shale, chert, and mudstone. Most of the resources and reserves of Zn occur in the Red Dog deposit and others in the Red Dog district; these resources and reserves surpass those of most deposits worldwide in terms of size and grade. In addition to zinc and lead sulfides (which contain silver, Ag) and barite, correlative strata host phosphate deposits. Furthermore, prolific hydrocarbon source rocks of Carboniferous and Triassic to Early Jurassic age generated considerable amounts of petroleum that may have contributed to the world-class petroleum resources of the North Slope. Deposits of Zn-Pb-Ag or barite as large as those in the Brooks Range are very rare on a global basis and, accordingly, multiple coincident favorable factors must be invoked to explain their origins. To improve our understanding of these factors and to contribute to more effective assessments of resources in sedimentary basins of northern Alaska and throughout the world, the Mineral Resources Program and the Energy Resources Program of the U.S. Geological Survey (USGS) initiated a project that was aimed at understanding the petroleum maturation and mineralization history of parts of the Brooks Range that were previously poorly characterized. The project, titled “Regional Fluid Flow and Basin Modeling in Northern Alaska,” was undertaken in collaboration with industry, academia, and other government agencies. This Circular contains papers that describe the results of the recently completed project. The studies that are highlighted in these papers have led to a better understanding of the following: The complex sedimentary facies relationships and depositional settings and the geochemistry of the sedimentary rocks that host the deposits (sections 2 and 3). The factors responsible for formation of the barite and zinc deposits (sections 4 and 5). The geochemical indicators or exploration tools that might be used to locate other large deposits of similar character in the Red Dog district and elsewhere (section 6). The isotopic compositions of barite and sulfide deposits (sections 7 and 8) The distribution and nature of phosphate and metalliferous oil shale localities (sections 9 and 10). The architecture, kinematics, and timing of the complex thrust systems that disrupted and redistributed the Carboniferous and younger rocks; these studies are necessary in order to make a realistic palinspastic reconstruction of the basin (sections 11 and 12). The nature and extent of the petroleum system sourced from Mississippian rocks (section 13).

Circular↗