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P. G. Lillis

Publications and source records attributed to P. G. Lillis.

13 recordsLinked to original sources
USGS2014

Asphaltene content and composition as a measure of Deepwater Horizon oil spill losses within the first 80 days

The composition and content of asphaltenes in spilled and original wellhead oils from the Deepwater Horizon (DWH) incident provide information on the amount of original oil lost and the processes most responsible for the losses within the first 80 days of the active spill. Spilled oils were collected from open waters, coastal waters and coastal sediments during the incident. Asphaltenes are the most refractory component of crude oils but their alteration in the spilled oils during weathering prevents them from being used directly as a conservative component to calculate original oil losses. The alteration is reflected by their increase in oxygen content and depletion in 12 C. Reconnaissance experiments involving evaporation, photo-oxidation, microbial degradation, dissolution, dispersion and burning indicate that the combined effects of photo-oxidation and evaporation are responsible for these compositional changes. Based on measured losses and altered asphaltenes from these experiments, a mean of 61 ± 3 vol% of the original oil was lost from the surface spilled oils during the incident. This mean percentage of original oil loss is considerably larger than previous estimates of evaporative losses based on only gas chromatography (GC) amenable hydrocarbons (32–50 vol%), and highlights the importance of using asphaltenes, as well as GC amenable parameters in evaluating original oil losses and the processes responsible for the losses.

Gulf Of Mexico↗
USGS2012

Evaluating Re-Os systematics in organic-rich sedimentary rocks in response to petroleum generation using hydrous pyrolysis experiments

Successful application of the 187 Re– 187 Os geochronometer has enabled the determination of accurate and precise depositional ages for organic-rich sedimentary rocks (ORS) as well as establishing timing constraints of petroleum generation. However, we do not fully understand the systematics and transfer behaviour of Re and Os between ORS and petroleum products (e.g., bitumen and oil). To more fully understand the behaviour of Re–Os systematics in both source rocks and petroleum products we apply hydrous pyrolysis to two immature hydrocarbon source rocks: the Permian Phosphoria Formation (TOC = 17.4%; Type II-S kerogen) and the Jurassic Staffin Formation (TOC = 2.5%; Type III kerogen). The laboratory-based hydrous pyrolysis experiments were carried out for 72 h at 250, 300, 325 and 350 °C. These experiments provided us with whole rock, extracted rock and bitumen and in some cases expelled oil and asphaltene for evaluation of Re–Os isotopic and elemental abundance. The data from these experiments demonstrate that the majority (>95%) of Re and Os are housed within extracted rock and that thermal maturation does not result in significant transfer of Re or Os from the extracted rock into organic phases. Based on existing thermodynamic data our findings suggest that organic chelating sites have a greater affinity for the quadravalent states of Re and Os than sulphides. Across the temperature range of the hydrous pyrolysis experiments both whole rock and extracted rock 187 Re/ 188 Os ratios show small variations (3.3% and 4.7%, for Staffin, respectively and 6.3% and 4.9% for Phosphoria, respectively). Similarly, the 187 Os/ 188 Os ratios show only minor variations for the Staffin and Phosphoria whole rock and extracted rock samples (0.6% and 1.4% and 1.3% and 2.2%). These isotopic data strongly suggest that crude oil generation through hydrous pyrolysis experiments does not disturb the Re–Os systematics in ORS as supported by various studies on natural systems. The elemental abundance data reveal limited transfer of Re and Os into the bitumen from a Type III kerogen in comparison to Type II-S kerogen (0.02% vs. 3.7%), suggesting that these metals are very tightly bound in Type III kerogen structure. The 187 Os/ 188 Os data from the pyrolysis generated Phosphoria bitumens display minor variation (4%) across the experimental temperatures, with values similar to that of the source rock. This indicates that the isotopic composition of the bitumen reflects the isotopic composition of the source rock at the time of petroleum generation. These data further support the premise that the Os isotopic composition of oils and bitumens can be used to fingerprint petroleum deposits to specific source rocks. Oil generated through the hydrous pyrolysis experiments does not contain appreciable quantities of Re or Os (~120 and ~3 ppt, respectively), in contrast to natural oils (2–50 ppb and 34–288 ppt for Re and Os, respectively), which may suggest that kinetic parameters are fundamental to the transfer of Re and Os from source rocks to oils. From this we hypothesise that, at the temperatures employed in hydrous pyrolysis, Re and Os are assimilated into the extracted rock as a result of cross-linking reactions.

Geochimica et Cosmochimica Acta↗
USGS2012

Migrated hydrocarbons in exposure of Maastrichtian nonmarine strata near Saddle Mountain, lower Cook Inlet, Alaska

Magoon and others (1980) described an 83-meter- (272-foot-) thick succession of Maastrichtian (Upper Cretaceous) conglomerate, sandstone, mudstone, and coal exposed on the south side of an unnamed drainage, approximately 3 kilometers (1.8 miles) east of Saddle Mountain in lower Cook Inlet (figs. 1 and 2). The initial significance of this exposure was that it was the first reported occurrence of nonmarine rocks of this age in outcrop in lower Cook Inlet, which helped constrain the Late Cretaceous paleogeography of the area and provided important information on the composition of latest Mesozoic sandstones in the basin. The Saddle Mountain section is thought to be an outcrop analog for Upper Cretaceous nonmarine strata penetrated in the OCS Y-0097 #1 (Raven) well, located approximately 40 kilometers (25 miles) to the south–southeast in Federal waters (fig. 1). Atlantic Richfield Company (ARCO) drilled the Raven well in 1980 and encountered oil-stained rocks and moveable liquid hydrocarbons between the depths of 1,760 and 3,700 feet. Completion reports on file with the Bureau of Ocean Energy Management (BOEM; formerly Bureau of Ocean Energy Management, Regulation and Enforcement, and prior to 2010, U.S. Minerals Management Service) either show flow rates of zero or do not mention flow rates. A fluid analysis report on file with BOEM suggests that a wireline tool sampled some oil beneath a 2,010-foot diesel cushion during the fl ow test of the 3,145–3,175 foot interval, but the recorded fl ow rate was still zero (Kirk Sherwood, written commun., January 9, 2012). Further delineation and evaluation of the apparent accumulation was never performed and the well was plugged and abandoned. As part of a 5-year comprehensive evaluation of the geology and petroleum systems of the Cook Inlet forearc basin, the Alaska Division of Geological & Geophysical Surveys obtained a research permit from the National Park Service to access the relatively poorly understood ‘Saddle Mountain exposure’ that is located in the Lake Clark National Park and Preserve. This work was done in cooperation with the Alaska Division of Oil & Gas and U.S. Geological Survey (USGS) research geologists. This report expands on Magoon and others’ (1980) description of the exposure, presents new data on sandstone composition and reservoir quality, presents new geochemical data on petroleum extracted from the outcropping sandstone, and describes oil-bearing correlative strata penetrated by the Raven well. Although the exposure is more than a kilometer (0.6 mile) east of Saddle Mountain (fig. 2), in this report we variously refer to it as the Saddle Mountain succession, Saddle Mountain section, or the rocks at Saddle Mountain underlain by Upper Jurassic strata of the Naknek Formation.

Alaska↗
USGS2007

Chapter 3: Geologic Assessment of Undiscovered Oil and Gas Resources in the Phosphoria Total Petroleum System of the Wind River Basin Province, Wyoming

The Phosphoria Total Petroleum System (TPS) encompasses the entire Wind River Basin Province, an area of 4.7 million acres in central Wyoming. The source rocks most likely are black, organic-rich shales of the Meade Peak and Retort Phosphatic Shale Members of the Permian Phosphoria Formation located in the Wyoming and Idaho thrust belt to the west and southwest of the province. Petroleum was generated and expelled during Jurassic and Cretaceous time in westernmost Wyoming and is interpreted to have migrated into the province through carrier beds of the Pennsylvanian Tensleep Sandstone where it was preserved in hypothesized regional stratigraphic traps in the Tensleep and Permian Park City Formation. Secondary migration occurred during the development of structural traps associated with the Laramide orogeny. The main reservoirs are in the Tensleep Sandstone and Park City Formation and minor reservoirs are in the Mississippian Madison Limestone, Mississippian-Pennsylvanian Amsden Formation, Triassic Chugwater Group, and Jurassic Nugget Sandstone and Sundance Formation. The traps are sealed by shale or evaporite beds of the Park City, Amsden, and Triassic Dinwoody Formations, Triassic Chugwater Group, and Jurassic Gypsum Spring Formation. A single conventional oil and gas assessment unit (AU), the Tensleep-Park City AU, was defined for the Phosphoria TPS. Both the AU and TPS cover the entire Wind River Basin Province. Oil is produced from 18 anticlinal fields, the last of which was discovered in 1957, and the possibility of discovering new structural oil accumulations is considered to be relatively low. Nonassociated gas is produced from only two fields, but may be underexplored in the province. The discovery of new gas is more promising, but will be from deep structures. The bulk of new oil and gas accumulations is dependent on the discovery of hypothesized stratigraphic traps in isolated carbonate reservoirs of the Park City Formation. Mean resource estimates for the Tensleep-Park City Conventional Oil and Gas AU total 18 million barrels of oil, 294 billion cubic feet of gas, and 5.9 million barrels of natural gas liquids.

Data Series↗
USGS2003

Petroleum systems of the Alaskan North Slope: a numerical journey from source to trap

The complex petroleum province of the Alaskan North Slope contains six petroleum systems (Magoon and others, this session). Source rocks for four of these systems include the Hue-gamma ray zone (Hue-GRZ), pebble shale unit, Kingak Shale, and Shublik Formation. Geochemical data for these source rocks are investigated in greater detail and provide the basis for numerical petroleum migration models.

Alaska↗
USGS2003

Distribution, richness, quality, and thermal maturity of source rock units on the North Slope of Alaska

Four source rock units on the North Slope were identified, characterized, and mapped to better understand the origin of petroleum in the area: Hue-gamma ray zone (Hue-GRZ), pebble shale unit, Kingak Shale, and Shublik Formation. Rock-Eval pyrolysis, total organic carbon analysis, and well logs were used to map the present-day thickness, organic quantity (TOC), quality (hydrogen index, HI), and thermal maturity (Tmax) of each unit. To map these units, we screened all available geochemical data for wells in the study area and assumed that the top and bottom of the oil window occur at Tmax of ~440° and 470°C, respectively. Based on several assumptions related to carbon mass balance and regional distributions of TOC, the present-day source rock quantity and quality maps were used to determine the extent of fractional conversion of the kerogen to petroleum and to map the original organic richness prior to thermal maturation.

Alaska↗
USGS2003

Alaskan North Slope petroleum systems

Six North Slope petroleum systems are identified, described, and mapped using oil-to-oil and oil-to-source rock correlations, pods of active source rock, and overburden rock packages. To map these systems, we assumed that: a) petroleum source rocks contain 3.2 wt. % organic carbon (TOC); b) immature oil-prone source rocks have hydrogen indices (HI) >300 (mg HC/gm TOC); c) the top and bottom of the petroleum (oil plus gas) window occur at vitrinite reflectance values of 0.6 and 1.0% Ro, respectively; and d) most hydrocarbons are expelled within the petroleum window. The six petroleum systems we have identified and mapped are: a) a southern system involving the Kuna-Lisburne source rock unit that was active during the Late Jurassic and Early Cretaceous; b) two western systems involving source rock in the Kingak-Blankenship, and GRZ-lower Torok source rock units that were active during the Albian; and c) three eastern systems involving the Shublik-Otuk, Hue Shale and Canning source rock units that were active during the Cenozoic. The GRZ-lower Torok in the west is correlative with the Hue Shale to the east. Four overburden rock packages controlled the time of expulsion and gross geometry of migration paths: a) a southern package of Early Cretaceous and older rocks structurally-thickened by early Brooks Range thrusting; b) a western package of Early Cretaceous rocks that filled the western part of the foreland basin; c) an eastern package of Late Cretaceous and Paleogene rocks that filled the eastern part of the foreland basin; and d) an offshore deltaic package of Neogene rocks deposited by the Colville, Canning, and Mackenzie rivers. This petroleum system poster is part of a series of Northern Alaska posters on modeling. The poster in this session by Saltus and Bird present gridded maps for the greater Northern Alaskan onshore and offshore that are used in the 3D modeling poster by Lampe and others. Posters on source rock units are by Keller and Bird as well as Peters and others. Sandstone and shale compaction properties used in sedimentary basin modeling are covered in a poster by Rowan and others. The results of this modeling exercise will be used in our next Northern Alaska oil and gas resource assessment.

Alaska↗
USGS1998

Organic geochemistry of oils from Oil Spring and Florence oil field near Canon City, Colorado

Oil Spring is an oil seep located approximately 6 miles north of Ca?on City, Colorado. The purpose of this study is to determine whether the oil from Oil Spring and the oil from nearby Florence oil field share a common source. Bulk and molecular geochemical analyses show that the oil seep is most likely derived from a group of geochemically similar Cretaceous source rocks including the Carlile Shale, Greenhorn Limestone, Graneros Shale, and the Mowry Shale. The Florence oil is derived from the Sharon Springs Member of the Upper Cretaceous Pierre Shale.

Open-File Report↗
USGS1997

Geochemistry of oils from the Junggar basin, northwest China

The Junggar basin of northwestern China is a structural basin containing a thick sequence of Paleozoic-Pleistocene rocks with estimated oil reserves of as much as 5 billion bbl. Analyses of 19 oil samples from nine producing fields and two oil-stained cores in the Junggar basin revealed the presence of at least five genetic oil types. The geochemistry of the oils indicates source organic matter deposited in fresh to brackish lake and marine environments, including coaly organic matter sources. The volumetrically most important oil type discovered to date is produced from Late Carboniferous-Middle Triassic reservoirs in the giant Karamay field and nearby fields located along the northwestern margin of the Junggar basin. Oil produced from the Mahu field, located downdip in a depression east of the Karamay field, is from a different source than Karamay oils. Unique oil types are also produced from an upper Permian reservoir at Jimusar field in the southeastern part of the basin, and from Tertiary (Oligocene) rocks at Dushanzi field and Lower Jurassic rocks at Qigu field, both located along the southern margin of the basin. Previous studies have demonstrated the presence of Upper Permian source rocks, and the possibility of Mesozoic or Tertiary sources has been proposed, but not tested by geochemical analysis, although analyses of some possible Jurassic coal source rocks have been reported. Our findings indicate that several effective source rocks are present in the basin, including local sources of Mesozoic or younger age for oil accumulations along the southern and southeastern margins of the basin. Future exploration or assessment of petroleum potential of the basin can be improved by considering the geological relationships among oil types, possible oil source rocks, and reservoirs.

Junggar Basin↗