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Geology topics

K. E. Peters

Publications and source records attributed to K. E. Peters.

14 recordsLinked to original sources
USGS2008

Restoration of Circum-Arctic Upper Jurassic source rock paleolatitude based on crude oil geochemistry

Tectonic geochemical paleolatitude (TGP) models were developed to predict the paleolatitude of petroleum source rock from the geochemical composition of crude oil. The results validate studies designed to reconstruct ancient source rock depositional environments using oil chemistry and tectonic reconstruction of paleogeography from coordinates of the present day collection site. TGP models can also be used to corroborate tectonic paleolatitude in cases where the predicted paleogeography conflicts with the depositional setting predicted by the oil chemistry, or to predict paleolatitude when the present day collection locality is far removed from the source rock, as might occur due to long distance subsurface migration or transport of tarballs by ocean currents. Biomarker and stable carbon isotope ratios were measured for 496 crude oil samples inferred to originate from Upper Jurassic source rock in West Siberia, the North Sea and offshore Labrador. First, a unique, multi-tiered chemometric (multivariate statistics) decision tree was used to classify these samples into seven oil families and infer the type of organic matter, lithology and depositional environment of each organofacies of source rock [Peters, K.E., Ramos, L.S., Zumberge, J.E., Valin, Z.C., Scotese, C.R., Gautier, D.L., 2007. Circum-Arctic petroleum systems identified using decision-tree chemometrics. American Association of Petroleum Geologists Bulletin 91, 877-913]. Second, present day geographic locations for each sample were used to restore the tectonic paleolatitude of the source rock during Late Jurassic time (???150 Ma). Third, partial least squares regression (PLSR) was used to construct linear TGP models that relate tectonic and geochemical paleolatitude, where the latter is based on 19 source-related biomarker and isotope ratios for each oil family. The TGP models were calibrated using 70% of the samples in each family and the remaining 30% of samples were used for model validation. Positive relationships exist between tectonic and geochemical paleolatitude for each family. Standard error of prediction for geochemical paleolatitude ranges from 0.9?? to 2.6?? of tectonic paleolatitude, which translates to a relative standard error of prediction in the range 1.5-4.8%. The results suggest that the observed effect of source rock paleolatitude on crude oil composition is caused by (i) stable carbon isotope fractionation during photosynthetic fixation of carbon and (ii) species diversity at different latitudes during Late Jurassic time. ?? 2008 Elsevier Ltd. All rights reserved.

Organic Geochemistry↗
USGS2008

Distinguishing solid bitumens formed by thermochemical sulfate reduction and thermal chemical alteration

Insoluble solid bitumens are organic residues that can form by the thermal chemical alteration (TCA) or thermochemical sulfate reduction (TSR) of migrated petroleum. TCA may actually encompass several low temperature processes, such as biodegradation and asphaltene precipitation, followed by thermal alteration. TSR is an abiotic redox reaction where petroleum is oxidized by sulfate. It is difficult to distinguish solid bitumens associated with TCA of petroleum from those associated with TSR when both processes occur at relatively high temperature. The focus of the present work was to characterize solid bitumen samples associated with TCA or TSR using X-ray photoelectron spectroscopy (XPS). XPS is a surface analysis conducted on either isolated or in situ (>25 ??m diameter) solid bitumen that can provide the relative abundance and chemical speciation of carbon, organic and inorganic heteroatoms (NSO). In this study, naturally occurring solid bitumens from three locations, Nisku Fm. Brazeau River area (TSR-related), LaBarge Field Madison Fm. (TSR-related), and the Alaskan Brooks range (TCA-related), are compared to organic solids generated during laboratory simulation of the TSR and TCA processes. The abundance and chemical nature of organic nitrogen and sulfur in solid bitumens can be understood in terms of the nature of (1) petroleum precursor molecules, (2) the concentration of nitrogen by way of thermal stress and (3) the mode of sulfur incorporation. TCA solid bitumens originate from polar materials that are initially rich in sulfur and nitrogen. Aromaticity and nitrogen increase as thermal stress cleaves aliphatic moieties and condensation reactions take place. Organic sulfur in TCA organic solids remains fairly constant with increasing maturation (<3.4 sulfurs per 100 carbons) due to offsetting preservation and H2S elimination reactions. In contrast, TSR solid bitumens are sulfur rich and nitrogen poor solids. These heteroatom distributions are attributed to the ability of TSR to incorporate copious amounts of inorganic sulfur (>3.5 to ???17 sulfur per 100 carbons) into aromatic structures and to the low levels of nitrogen in their hydrocarbon precursors. Hence, XPS results provide organic chemical composition information that helps to distinguish whether solid bitumen, either in situ or removed and concentrated from the rock matrix, was formed via the TCA or TRS process. ?? 2008 Elsevier Ltd.

Organic Geochemistry↗
USGS2008

Families of miocene monterey crude oil, seep, and tarball samples, coastal California

Biomarker and stable carbon isotope ratios were used to infer the age, lithology, organic matter input, and depositional environment of the source rocks for 388 samples of produced crude oil, seep oil, and tarballs to better assess their origins and distributions in coastal California. These samples were used to construct a chemometric (multivariate statistical) decision tree to classify 288 additional samples. The results identify three tribes of 13C-rich oil samples inferred to originate from thermally mature equivalents of the clayey-siliceous, carbonaceous marl and lower calcareous-siliceous members of the Monterey Formation at Naples Beach near Santa Barbara. An attempt to correlate these families to rock extracts from these members in the nearby COST (continental offshore stratigraphic test) (OCS-Cal 78-164) well failed, at least in part because the rocks are thermally immature. Geochemical similarities among the oil tribes and their widespread distribution support the prograding margin model or the banktop-slope-basin model instead of the ridge-and-basin model for the deposition of the Monterey Formation. Tribe 1 contains four oil families having geochemical traits of clay-rich marine shale source rock deposited under suboxic conditions with substantial higher plant input. Tribe 2 contains four oil families with traits intermediate between tribes 1 and 3, except for abundant 28,30-bisnorhopane, indicating suboxic to anoxic marine marl source rock with hemipelagic input. Tribe 3 contains five oil families with traits of distal marine carbonate source rock deposited under anoxic conditions with pelagic but little or no higher plant input. Tribes 1 and 2 occur mainly south of Point Conception in paleogeographic settings where deep burial of the Monterey source rock favored petroleum generation from all three members or their equivalents. In this area, oil from the clayey-siliceous and carbonaceous marl members (tribes 1 and 2) may overwhelm that from the lower calcareous-siliceous member (tribe 3) because the latter is thinner and less oil-prone than the overlying members. Tribe 3 occurs mainly north of Point Conception where shallow burial caused preferential generation from the underlying lower calcareous-siliceous member or another unit with similar characteristics. In a test of the decision tree, 10 tarball samples collected from beaches in Monterey and San Mateo counties in early 2007 were found to originate from natural seeps representing different organofacies of Monterey Formation source rock instead from one anthropogenic pollution event. The seeps apparently became more active because of increased storm activity. Copyright ?? 2008. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2007

Origins of thiadiamondoids and diamondoidthiols in petroleum

Thiadiamondoids and diamondoidthiols are orders of magnitude more abundant in oil altered by thermochemical sulfate reduction (TSR) than they are in nonaltered oil. This suggests that thiadiamondoids and diamondoidthiols form during TSR. In order to prove this hypothesis, we perform laboratory TSR experiments on diverse organic compounds using sodium sulfate as an oxidant in the presence of elemental sulfur and deionized water at 200 and 350 °C for 48 and 96 h under acidic conditions (pH = 4). Our results show that thiadiamondoids and diamondoidthiols can be created from non-sulfur-containing diamondoids by TSR. It seems likely that diamondoid species are organic precursors of thiadiamondoids and diamondoidthiols. In addition, thiocholesterol yields trace quantities of dimethyl-2-thiaadamantanes when heated with montmorillonite at 200 °C, suggesting that these diamondoid derivatives may partly originate by molecular rearrangement of polycyclic sulfides and thiols in the presence of acidic clay minerals since they also exist in crude oil that has not undergone TSR. The present study of these heteroatomic cage compounds improves understanding of TSR and can be used to reduce risk in petroleum exploration.

Energy and Fuels↗
USGS2007

Circum-Arctic petroleum systems identified using decision-tree chemometrics

Source- and age-related biomarker and isotopic data were measured for more than 1000 crude oil samples from wells and seeps collected above approximately 55??N latitude. A unique, multitiered chemometric (multivariate statistical) decision tree was created that allowed automated classification of 31 genetically distinct circumArctic oil families based on a training set of 622 oil samples. The method, which we call decision-tree chemometrics, uses principal components analysis and multiple tiers of K-nearest neighbor and SIMCA (soft independent modeling of class analogy) models to classify and assign confidence limits for newly acquired oil samples and source rock extracts. Geochemical data for each oil sample were also used to infer the age, lithology, organic matter input, depositional environment, and identity of its source rock. These results demonstrate the value of large petroleum databases where all samples were analyzed using the same procedures and instrumentation. Copyright ?? 2007. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2006

North Slope, Alaska: Source rock distribution, richness, thermal maturity, and petroleum charge

Four key marine petroleum source rock units were identified, characterized, and mapped in the subsurface to better understand the origin and distribution of petroleum on the North Slope of Alaska. These marine source rocks, from oldest to youngest, include four intervals: (1) Middle-Upper Triassic Shublik Formation, (2) basal condensed section in the Jurassic-Lower Cretaceous Kingak Shale, (3) Cretaceous pebble shale unit, and (4) Cretaceous Hue Shale. Well logs for more than 60 wells and total organic carbon (TOC) and Rock-Eval pyrolysis analyses for 1183 samples in 125 well penetrations of the source rocks were used to map the present-day thickness of each source rock and the quantity (TOC), quality (hydrogen index), and thermal maturity (Tmax) of the organic matter. Based on 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 TOC (TOCo) and the original hydrogen index (HIo) prior to thermal maturation. The quantity and quality of oil-prone organic matter in Shublik Formation source rock generally exceeded that of the other units prior to thermal maturation (commonly TOCo > 4 wt.% and HIo > 600 mg hydrocarbon/g TOC), although all are likely sources for at least some petroleum on the North Slope. We used Rock-Eval and hydrous pyrolysis methods to calculate expulsion factors and petroleum charge for each of the four source rocks in the study area. Without attempting to identify the correct methods, we conclude that calculations based on Rock-Eval pyrolysis overestimate expulsion factors and petroleum charge because low pressure and rapid removal of thermally cracked products by the carrier gas retards cross-linking and pyrobitumen formation that is otherwise favored by natural burial maturation. Expulsion factors and petroleum charge based on hydrous pyrolysis may also be high compared to nature for a similar reason. Copyright ?? 2006. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2006

Evaluation of kinetic uncertainty in numerical models of petroleum generation

Oil-prone marine petroleum source rocks contain type I or type II kerogen having Rock-Eval pyrolysis hydrogen indices greater than 600 or 300-600 mg hydrocarbon/g total organic carbon (HI, mg HC/g TOC), respectively. Samples from 29 marine source rocks worldwide that contain mainly type II kerogen (HI = 230-786 mg HC/g TOC) were subjected to open-system programmed pyrolysis to determine the activation energy distributions for petroleum generation. Assuming a burial heating rate of 1??C/m.y. for each measured activation energy distribution, the calculated average temperature for 50% fractional conversion of the kerogen in the samples to petroleum is approximately 136 ?? 7??C, but the range spans about 30??C (???121-151??C). Fifty-two outcrop samples of thermally immature Jurassic Oxford Clay Formation were collected from five locations in the United Kingdom to determine the variations of kinetic response for one source rock unit. The samples contain mainly type I or type II kerogens (HI = 230-774 mg HC/g TOC). At a heating rate of 1??C/m.y., the calculated temperatures for 50% fractional conversion of the Oxford Clay kerogens to petroleum differ by as much as 23??C (127-150??C). The data indicate that kerogen type, as defined by hydrogen index, is not systematically linked to kinetic response, and that default kinetics for the thermal decomposition of type I or type II kerogen can introduce unacceptable errors into numerical simulations. Furthermore, custom kinetics based on one or a few samples may be inadequate to account for variations in organofacies within a source rock. We propose three methods to evaluate the uncertainty contributed by kerogen kinetics to numerical simulations: (1) use the average kinetic distribution for multiple samples of source rock and the standard deviation for each activation energy in that distribution; (2) use source rock kinetics determined at several locations to describe different parts of the study area; and (3) use a weighted-average method that combines kinetics for samples from different locations in the source rock unit by giving the activation energy distribution for each sample a weight proportional to its Rock-Eval pyrolysis S2 yield (hydrocarbons generated by pyrolytic degradation of organic matter). Copyright ?? 2006. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2005

Egret-Hibernia(!), a significant petroleum system, northern Grand Banks area, offshore eastern Canada

Egret-Hibernia(!) is a well-explored petroleum system (3.25 billion barrels oil equivalent [BOE]) located in the Jeanne d'Arc Basin on the Labrador - Newfoundland shelf. Rifting and sediment fill began in the Late Triassic. Egret source rock was deposited in the Late Jurassic at about 153 Ma. After this time, alternating reservoir rock and seal rock were deposited with some syndepositional faulting. By the end of the Early Cretaceous, faults and folds had formed numerous structural traps. For the next 100 m.y., overburden rock thermally matured the source rock when it reached almost 4 km (2.5 mi) burial depth. For 2 km (1.25 mi) below this depth, oil and gas were expelled, until the source was depleted. The expelled petroleum migrated updip to nearby faulted, anticlinal traps, where much of it migrated across faults and upsection to the Hibernia Formation (44% recoverable oil) and Avalon Formation (28%). Accumulation size decreased, and gas content increased from west to east, independent of trap size. These changes correspond to a decrease in source rock richness and quality from west to east. Almost all (96%) of the discovered petroleum resides in the Lower Cretaceous or older reservoir rock units. All accumulations found to date are normally pressured in structural traps. Fifty-two exploration wells found eighteen discoveries. Their size ranges from 1.2 to 0.01 billion BOE. Most discoveries were made between 1979 and 1991. The discovery cycle began with larger accumulations and progressed to smaller accumulations. The estimated sizes of the larger accumulations have grown since 1990. Estimated mean value for undiscovered hydrocarbons is 3.8 billion BOE, thereby raising the ultimate size of Egret-Hibernia(!) to 6.19 billion BOE. Copyright ?? 2005. The American Association of Petroleum Geologists. All rights reserved.

American Association of Petroleum Geologists Bulle↗
USGS2004

Thermal alteration of Cretaceous black shale from the Eastern Atlantic. III: Laboratory simulations

Laboratory thermal alteration (pyrolysis) experiments were carried out on composited Cretaceous black shale samples from DSDP Hole 368. Dried rock samples (low water-rock ratio) were heated in an inert atmosphere in the range of 250–500°C and the resultant bitumen and kerogen concentrates were characterized. Pyrobitumen forms initially (250°C), then major hydrocarbon generation occurs from 300–360°C and oxygenated products ( e.g. alkanoic acids) have a maximum yield at 330–360°C with minor generation to 500°C. Dealkylation of the aromatic hydrocarbons to the parent polynuclear aromatic hydrocarbons occurs above 400°C. The kerogens become more aromatic with increasing pyrolysis temperature (atomic H/C decreases from 1.2 to 0.5 and vitrinite reflectance increases to 3%). The temperature ranges of pyrobitumen, bitumen, and PAH formation in dry pyrolysis experiments are of utility in correlating with field data on ore genesis.

Atlantic Ocean, Cape Verde Rise↗
USGS2003

Isolation and structural proof of the large diamond molecule, cyclohexamantane (C26H30)

Ace of diamonds: Cyclohexamantane (C26H30), a large diamond-like molecule containing six peri-fused adamantane cages was identified in petroleum and its structure proven by X-ray crystallography (see picture), Never synthesized because of severe mechanistic difficulties, the structure of cyclohexamantane has appeared in theoretical molecular-simulation studies related to diamond; its experimentally determined properties are now discussed.

Angewandte Chemie - International Edition↗
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↗