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The Woodford Shale is anecdotally assumed to be the major source of oil for plays in the Anadarko Basin, including the stacked oil and condensate play in the southcentral Oklahoma oil province (SCOOP). However, there is little published geochemical work to confirm this assumption. This study set out to identify a characteristic geochemical fingerprint for the Goddard Formation, another potential source rock in the SCOOP, to determine if the Goddard is contributing to oil accumulations within the SCOOP. The Upper Mississippian Goddard Formation has been a target for unconventional production in SCOOP since 2012. Published geochemical interpretations for the Goddard Formation are still limited, and this study represents the first detailed oil–source rock correlation for the Goddard in the SCOOP area. The most characteristic geochemical signature of the Goddard extracts is a predominance of tricyclic terpanes relative to the hopanes in the mass-to-charge ratio 191 chromatogram, possibly related to enrichment via thermal stress or a unique source signature. Additional distinctive signatures were also identified for the triaromatic steroid hydrocarbons, sesquiterpenoids, and steranes. The biomarker fingerprints of SCOOP oils are nearly identical with those of the Goddard extracts in this study. Oils in the SCOOP, therefore, appear to originate from a Mississippian source, such as the Goddard rather than the Woodford. This observation demonstrates the value of oil–source rock correlation studies and suggests that there may be effective source rocks in the Anadarko Basin that have been overlooked in the past and should be re-evaluated in detail.

Twenty-four oils produced from the Woodford Shale and overlying Mississippian strata in central Oklahoma were characterized geochemically to determine their possible source(s). The 168 core samples from the Woodford and Mississippian sections of 14 wells in central Oklahoma were initially characterized by total organic carbon (TOC), Rock-Eval, and vitrinite reflectance, and select samples (TOC > 1.0 wt. %) were subjected to biomarker analyses to characterize source input, depositional environment, maturity, and oil-to-source rock correlations. Thermal maturity parameters indicate the Woodford Shale is immature to marginally mature in Payne County, Oklahoma, and shows a progressive increase in maturity toward the southwest. Close to the Nemaha uplift, the Woodford is in the main stage of oil generation. It is proposed that the oils in this area have three possible origins: (1) Oils produced from the Woodford and overlying Mississippian strata have similar fingerprints, suggesting the Woodford Shale and overlying Mississippian strata are in communication; (2) oils produced near the Nemaha uplift (Logan and western Payne Counties) were sourced from the Woodford but had a significant Mississippian source contribution based on source-specific biomarkers; (3) oils east of the Cherokee platform (eastcentral Payne County) share strong Woodford source characteristics, and they were not generated in situ from the immature Woodford Shale but probably migrated from the Woodford Shale in the deeper part of the Anadarko Basin in southern Oklahoma. These results are consistent with the findings that indicate abundant marine coarse-grained biogenic silica (radiolarian-rich) chert facies found in eastcentral Payne County may contribute to good reservoir petrophysical properties, suggesting the Woodford Shale may not be a source in this area but simply a tight reservoir.

The Sirt Basin contains most of Libya’s producing oil fields and is in northern Libya, south of the Gulf of Sirt in the Mediterranean Sea. The main aims of this study were to characterize the type of organic matter and depositional conditions of the source rocks and thermal maturity of the crude oils in this region using a variety of geochemical techniques including gas chromatography (GC), gas chromatography/mass spectrometry (GCMS), stable carbon and hydrogen isotopes, total organic carbon (TOC), and Rock Eval analysis. Twelve crude oil samples from Cambrian–Ordovician Gargaf, Upper Paleocene Zaltan, and Middle Eocene Gialo reservoirs and seventy-nine source rock samples representing Sirt Shale samples from nine wells were collected from the Zaltan Platform and surrounding troughs in the central Sirt Basin. Organic geochemical parameters indicate that these oils were sourced from marine organic matter deposited under oxic to suboxic conditions. The oils were divided into three groups based on their whole oil carbon and hydrogen isotopic composition and thermal maturity as manifested by several saturate and aromatic hydrocarbon maturity parameters. Based on the geochemical data, it is proposed that there are at least two sources for the crude oils in the Zaltan Platform area of the central Sirt Basin. The study also indicates that the Sirt Shale source rocks from Maradah Trough are dominated by marine organic matter and have reached the main phase of oil generation.

Understanding the environmental features and processes responsible for the formation of organic-rich, laterally extensive source rocks of appreciable thickness, such as the Late Devonian–Early Mississippian Woodford Shale, is necessary to refine current depositional models. In this study, a detailed assessment of the paleowater column was undertaken via examination of molecular fossil (biomarker) data. Specifically, C40 aromatic carotenoids were used to delineate the nature and severity of photic-zone euxinia concomitant with the deposition of the lower, middle, and upper Woodford. The immature character of the Woodford in the study area ensured that biomarker interpretations were reflective of the depositional environment and not altered by secondary processes. Twenty-nine Woodford Shale samples from the Lawrence uplift of the western Arkoma Basin were subjected to bulk and molecular geochemical analyses, with the objective to enhance the understanding of the paleowater column. A suite of C40 aromatic carotenoids—paleorenieratane, isorenieratane, renieratane, and renierapurpurane—was identified for the first time in the Woodford Shale. Paleorenieratane, the predominant C40 aromatic carotenoid, was found to be isotopically enriched (δ13C e −12‰ ± 1.5‰). This was interpreted as a product of carbon fixation via the reverse tricarboxylic acid cycle, a diagnostic trait of Chlorobiaceae. Additional biomarker parameters sensitive to changes in redox assisted in substantiating interpretations of Chlorobiaceae derivatives, with the severity of photic-zone euxinia inferred by the effects that this environmental state imposed on the overlying microbial community and algal populations. Previously unrecognized inter- and intramember variations in water-column structure and redox state were documented. The lower Woodford was characterized by isolated pulses of photic-zone euxinia, with the middle Woodford deposited during persistent photic-zone euxinia, as evinced by elevated concentrations of the C40 aromatic carotenoids. A deep, persistent chemocline likely typified upper Woodford deposition, but lack of sampling intensity in this member may belie a more episodic nature. Effects of photic-zone euxinia appeared to be most severe in the middle Woodford, where progressively increasing C40 aromatic-carotenoid concentrations coincide with rising gammacerane indices and a systematic decrease in sterane/hopane values. Environmental conditions (e.g., oxygen minimum zone, restriction) that facilitate the development of euxinia in the photic zone were interpreted to reconstruct the paleoenvironment on a local to subregional scale.

The Central Sumatra Basin (CSB), formed during the Late Eocene (?) to Early Oligocene, is the most prolific hydrocarbon basin in Indonesia. The Brown Shale Formation of the Pematang Group is the sole known source rock for the tens of billions of barrels of oil located in the CSB. Samples analyzed in this study were from the Karbindo coal mine in the Kiliran graben of the Kiliran sub-basin, located on the western side of the CSB. This study incorporates advanced organic geochemical and petrographical data of samples from the Brown Shale Formation, as well as interpretations from previous studies at this location, to construct a detailed paleoenvironment model for this Tertiary lake. The lacustrine source rock was deposited under fresh water conditions, with subtle changes in the environment that resulted in significant changes in ecologies. Based on new data from organic petrography, biomarkers, microscale sealed vessel pyrolysis, and characterization of the polyaromatic hydrocarbons, the organic matter in the Brown Shale Formation was determined to be sourced primarily from lacustrine organisms with a small amount of terrestrial plant input. 4-Methylsterane concentrations and n -alkane distributions indicate that non-marine dinoflagellates and Botryococcus braunii (A race) were likely a significant portion of the local biosphere.

The Lawton oil field is located on the Wichita Mountain uplift in southwestern Oklahoma. This study focused on addressing three problems related to the Lawton oil field: (a) what is (are) the source(s) of the oils; (b) have the oils been subjected to alteration since emplacement; and (c) what is the filling history of the field? Eighteen oils and one seep sample were collected and characterized by a variety of geochemical techniques including bulk composition, biomarkers, and stable carbon isotopes in order to address these questions. Source rocks in this region are absent following the Pennsylvanian-age Wichita orogeny but biomarkers and stable isotopic data suggest the source of these oils is probably the Woodford Shale. Despite the fact that all of these oils were recovered from reservoirs at depths between 125 and 1,000 ft (38 and 305 m), none of them appeared to be extensively biodegraded as manifested by the abundance of the complete range of n-alkanes. However the presence of 25-norhopanes in all eighteen samples suggests that these oils are mixtures of various proportions of degraded and non-degraded (or slightly degraded) oils. The seep sample, and some oils, have a relatively high abundance of the C32 ββ 22R hopanoic acid, relative to the C31 ββ 22R hopanoic acid, with the presence of these ββ 22R hopanoic acids suggesting the oils have been degraded aerobically at some point in their history. It was also noted that the concentration of the C31 ββ 22R hopanoic acid is higher in the shallower reservoirs than in the deeper reservoirs possibly indicating slightly higher levels of degradation in the shallower reservoirs compared to the deeper reservoirs. A hydrocarbon accumulation model has been proposed for this field based on two main reservoir charging periods. The initial charge of crude oil was biodegraded, probably under anaerobic conditions. The second charging period took place after (or together with) the uplift of the Wichita Mountains and subsidence of the southern part of the Anadarko Basin leading to deeper burial of the source rock and production of higher maturity oil, which subsequently filled the reservoirs containing the degraded oil and may still be recharging these shallow reservoirs today.

The molecular and compound-specific isotopic composition of the n-alkanes in 30 oil samples from the Central Sumatra Basin were analyzed with the purpose of determining facies variations of the source rock in this basin. The oil samples were generated by the Eocene-Oligocene lacustrine Brown Shale Formation. Biomarkers in the oil samples indicate varying contributions from algal and terrigenous organic matter, primarily under oxic, or suboxic depositional conditions. Five source rock facies were identified based on the relative concentrations of n-alkanes, isoprenoids, tricyclic terpanes, and steranes. The individual facies were also distinguished by the compound-specific isotopic composition of the n-alkanes. Source rock depositional environments vary from deep lacustrine, shallow lacustrine, and lacustrine saline to coal and mixed coal and lacustrine shale. Deep lacustrine facies predominate in the Aman and Bengkalis troughs whereas saline and shallow lacustrine facies predominate in the South Aman and Kiri troughs, respectively. Oils derived from coal and mixed coal and lacustrine shale facies predominate in the northern part of the Central Sumatra Basin, in the Tanjung Medan and north of the Balam grabens.

It has been estimated that technically recoverable reserves from shales in the continental U.S. are believed to be approximately 24 billion barrels of oil (BBO) and 750 trillion cubic feet (Tcf) of gas. In Oklahoma the most important hydrocarbon source rock is the Woodford Shale, proposed to be the source of some 70% of the state's liquid hydrocarbon reserves. Such a regionally widespread source rock provides potential for both academic study and industrial opportunities. In this study representative samples of the Woodford Shale from the McAlister Quarry outcrop have been characterized by a variety of geochemical techniques. TOC values range from 0.07 to 15.6 wt% and, based on Rock-Eval Pyrolysis, most of the samples plot within the Type I/II kerogen range, with several low TOC samples plotting in the Type III kerogen range. TOC and biomarker parameters, suggests that two sections of the Upper Woodford are immature paleosols, having been subaerially exposed due to abrupt episodes of sea level fall during the Late Devonian. Evidence for these zones of paleoweathering includes highly depleted TOC, increased oxygen index (OI) values, loss of n-alkanes, decreases in the aryl isoprenoid ratio (AIR), sesquiterpenoids, cheilanthanes, hopanoids, and decreases in many of the polycyclic aromatic hydrocarbons (PAHs). The values of several paleoenvironmental proxies for samples immediately following the Frasnian-Famennian (F–F) Stage extinction boundary within the Upper Woodford suggests that a large influx of weathered terrigenous material occurred at that time. The presence of pyrogenic compounds implies that paleowildfires were widespread throughout the Middle and Late Devonian in the North American midcontinent. It is possible that these influxes of weathered terrestrial organic material stimulated algal blooms that led to the anoxic water column conditions often attributed to the F–F Stage extinction event. Investigation of the stratigraphic framework of these source rocks assists in evaluating their potential as hydrocarbon producers and/or unconventional reservoirs. Integration of geochemical data adds another powerful dimension to this approach. It has been proposed that the Woodford Shale was deposited during a 2nd order depositional sequence. The lower member represented the transgressive systems tract (TST), the Upper member the highstand systems tract (HST), and the Middle member bridging the transition between the two. Numerous 3rd order parasequences were also identified as being part of the overall 2nd order sequence and could be correlated to the Devonian sea level curve. The major objectives of the study were: While this study focuses locally on the McAlister Quarry samples, it is also of regional importance. The Woodford is a prolific source rock throughout the Anadarko Basin and has been the subject of extensive exploration and production efforts, particularly in the past decade with the development of horizontal drilling and hydrofracturing techniques. Continued investigation of the heterogeneity of the shale will greatly enhance the ability to predict more productive facies within the formation throughout the basin.

The Central Sumatra Basin (CSB) is a prolific oil producing basin in Indonesia where a single source rock has been identified, the Brown Shale Formation of the Paleogene Pematang Group. Despite the presence of a single source rock, the oils in the Central Sumatra Basin and particularly in the Aman Trough, exhibit variable molecular and isotopic compositions, previously described as reflective of lateral facies variations within the source rock. Analyses by gas chromatography (GC), gas chromatography–mass spectrometry (GC–MS) and gas chromatography–isotope ratio mass spectrometry (GC–IRMS) of 15 oil samples from the Aman Trough allowed identification of vertical and lateral facies changes within the Brown Shale Formation as well as paleoproductivity and paleoclimatic changes that took place during deposition of this prolific source rock. The molecular and isotopic data indicate the source rock for these oils was deposited in a fresh to brackish water stratified lake in which CO 2 limiting conditions prevailed. Compound specific isotopic data also indicate that changes in paleoclimatic conditions, possibly associated with the Eocene–Oligocene paleoclimatic transition, had an effect on the geochemical composition of the source rock in the Aman Trough.

Molecular and isotopic compositions of 51 gas and 7 condensate samples produced from the Barnett Shale were determined by gas chromatography–isotope ratio mass spectrometry to investigate their origin and maturity at the time of generation. Additionally, two hydrous pyrolysis experiments were performed to calibrate maturity values predicted for gas generation. Molecular and carbon and hydrogen isotopic compositions of the gases indicate that gas produced from the Barnett is thermogenic. To estimate generation maturity, additional analyses were performed on the condensates and available core samples. Diamondoid indices combined with vitrinite reflectance (Ro) measurements, isotopic and molecular composition, and hydrous pyrolysis experiments suggest that gas produced from the Barnett Shale was generated within the condensate–wet gas window (1.3–2.0% Ro) at a later stage than hydrocarbons accumulated in shallower reservoirs. The origin of the gas is thermogenic, probably derived from both kerogen cracking and secondary cracking of previously generated nonmigrated hydrocarbons. Additionally, the occurrence of a methane isotope reversal in group 1 gases corroborates that in-situ oil or gas cracking is occurring in the easternmost part of the study area.

Solid bitumen was identified within the Mississippian Chester sandstone reservoir in the Hitch field, southwest Kansas. The adjacent Etzold field has similar reservoir properties but lacks solid bitumen, although the Hitch and Etzold fields were thought to be in pressure communication and have common source rocks. Hitch and Etzold crude oils and core extracts were characterized geochemically to gain a better understanding of the reservoir-filling history and geological and geochemical controls on solid bitumen formation in the Hitch reservoir. Based on a variety of geochemical characteristics, we propose that the Hitch and Etzold oils are mixtures derived from Ordovician and Late Devonian–early Mississippian (Woodford Shale) source rocks. The solid bitumen in the Hitch reservoir probably results from mixing of oils having different geochemical compositions, which filled the reservoir over an extended period. No evidence of severe biodegradation or thermal alteration is observed. A reservoir-filling scenario is proposed in an effort to explain why the Hitch oils are geochemically more heterogeneous than Etzold oils. Furthermore, gas de-asphalting and regional pressure drops as a result of post-Laramide orogeny may have contributed to a phase change in the reservoir fluid and deposition of solid materials by disturbance of thermodynamic equilibrium. The major significance of this study is related to improving our knowledge on the occurrence of the presence of solid bitumen in reservoirs that can introduce barriers into the reservoir, complicating waterflood operations and leading to erroneous oil-in-place calculations and subsequently lower than expected oil recovery.

The presence of three families of hopanoic acids, 17,21-secohopanoic acids, 25-norhopanoic acids, and 28-norhopanoic acids, is discussed. Oils from West Siberia and tar balls from the Seychelles Islands were found to contain relatively high proportions of 17,21-secohopanoic acids. These acids have not been previously reported in any oils or source rocks. A heavily biodegraded West Siberian oil, was found to contain an homologous series of 25-norhopanoic acids co-occurring with the 25-norhopanes as previously reported in only a small number of oils from Campos Basin, Brazil. 28-Norhopanoic acids have been reported in various sediments and extracts of the Monterey Shale, but in this study their occurrence has been extended to oils, degraded oils, and tar balls sourced from the Monterey Shale. The primary purpose herein is to report the occurrence of these acids and possible relationships between the acids and corresponding hydrocarbons.

Extracts of 18 potential source rocks from the Qaidam, Liaohe, and Tarim Basins, China have been characterized by high temperature gas chromatography (HTGC) and found to contain high molecular weight hydrocarbons (HMWHCs) above C40. These rocks were originally formed in freshwater lacustrine, saline lacustrine, and terrigenous bog environments with mudstone, calcareous mudstone, coaly shale and coal lithologies. Their ages range from Triassic to Miocene and maturities from immature to mature covering a vitrinite reflectance range (Ro) for the Liaohe and Tarim samples of 0.54–0.84%. The combined distributions of the n-alkane and alkylcyclopentane homologues in the extracts can be used to characterize the nature of the original depositional environment. In certain samples the carbon number predominance of the n-alkanes changes from an odd/even predominance to even/odd predominance above C40 possibly suggesting different precursors for the n-alkanes above and below C40. Concentrations of the HMWHCs were also observed to increase with maturity of the source rocks. This is the first comprehensive report on the occurrence of HMWHCs in source rocks and their discovery introduces the possibility of using these compounds for oil/source rock correlation purposes in future studies along with the more conventional biomarkers.

Results of extraction experiments performed on immature Green River Formation source rock samples from the Black Shale Facies (Uinta Basin, Utah) demonstrate the potential of extracting high molecular weight hydrocarbons (HMWHC) with sequential dichloromethane:methanol/soxhlet and p -xylene/sonication techniques. The first soxhlet extraction step with DCM:MeOH removes lower molecular weight alkanes from the source rock while the HMWHC remain in the rock residue. Sonication of the rock residue with p -xylene recovers these HMWHC, showing distinct hydrocarbon distributions and preferences in high temperature gas chromatograms. Extracts obtained by using p -xylene/soxhlet with original source rocks and sequential soxhlet extraction instead of sonication have relatively lower concentrations of HMWHC. Sequential extraction of two other source rock types (Mahogany Shale and Black Shale Facies coal) did not result in detection of similar HMWHC in the extract. This indicates that the presence of these compounds in the Black Shale Facies of the Green River Formation is a primary source signal and a specific characteristic of this source rock.

Summary Pores, spores, pollen and pellets are all important constituents of resource shales. Pores provide the storage place and, when connected, the transport route for hydrocarbon molecules. Conventional Scanning Electron Microscopy (SEM and FESEM) of pores from untreated surfaces from several resource shales reveal a common variety of pore types. An inexpensive method of analysis has been developed to measure porosity, and dimensions of pores. The shales exhibit a variety of porosities, but usually 1 µm in length) and nanopores (defined here as

An outcrop-behind outcrop study was conducted in and adjacent to a 300 100 16 m (980 330 50 ft) quarry of the gas-producing Woodford Shale to structurally/stratigraphically characterize it from the pore to subregional scales using a variety of techniques. Strata around quarry walls were described and correlated to a 64 m (210 ft) long continuous core drilled 150 m (500 ft) back from the quarry wall and almost to the Woodford-Hunton unconformity. Borehole logs obtained include neutron and density porosity (NPHI and DPHI) logs, and logs from Elemental Capture Spectroscopy (ECS™), Combinable Magnetic Resonance (CMR-Plus™), Fullbore Formation MicroImager (FMI™), and sonic scanner (Modular Sonic Imaging Platform, or MSIP™)—all manufactured by Schlumberger. The strata around the quarry are horizontally bedded. Borehole logs were used to identify a basic threefold subdivision into an upper relatively porous quartzose interval; a middle, more clay-rich, and less porous interval; and a lower interval of intermediate quartz-clay content. These intervals correspond to the informally named upper, middle, and lower Woodford. Detailed core and quarry wall description revealed several types of finely laminated lithofacies, with varying amounts of total organic carbon (TOC). The FMI log revealed a much greater degree of variability in laminations than can be readily seen with the naked eye. Organic geochemistry and biomarkers are closely tied to these lithofacies and record cyclic variations in oxic-anoxic depositional environments, which correspond to relative sea level fall-rise cycles. At the scanning electron microscopy scale, microfractures and microchannels are common and provide tortuous pathways for gas (and oil) migration through the shales. Based on FMI and core analysis, fracture density is much greater in the upper quartzose lithofacies than in the lower, more clay-rich lithofacies. A laser imaging detection and ranging (LIDAR) survey around the quarry walls documented two near-vertical fracture trends in the quartzose lithofacies: one striking N85E with spacings of 1.2 m (4 ft) and the other striking N45E related to the present stress field. The FMI analysis only imaged the latter fracture set. Both log-derived and laboratory-tested geomechanical property measurements documented a significant relationship between shale fabric (laminations and preferred clay-particle orientation) and rock strength, and a secondary relationship to mineral composition. Porosity and microfractures or microchannels also appear to influence rock strength. This integrated study has provided insight into the causal relations among Woodford properties at a variety of scales. In particular, a stratigraphic (vertical) segregation of lithofacies can be related to cyclic variations in depositional environments. The resulting stratified zones exhibit variations in their hydrocarbon source and reservoir (fracturable) potential. Such information and predictive capability can be valuable for improved targeted horizontal drilling into enriched source rock and/or readily fracturable reservoir rock in the Woodford and perhaps other gas shales.

Thirty oils from the Pauls Valley area of the Anadarko Basin, Oklahoma, have been analyzed for n-alkane, terpane and sterane distributions in an effort to classify genetically related oils. Ten rock samples from the area were also analyzed in an attempt to relate oil types to their possible source rocks. The Pauls Valley area, located near the southeast corner of the Anadarko Basin, has producing formations ranging in age from Middle Ordovician to Late Pennsylvanian. Trapping mechanisms responsible for the accumulation of hydrocarbons vary from purely structural traps, to fractured reservoirs, to up-dip truncations of reservoirs and up-dip pinchouts of sandstones. Results show that 85% of oils in the area probably have a common source, the Woodford Shale. A group of oils reservoired in the Viola Group exhibit distinct geochemical characteristics and are thought to have a different source. The differences between the oils from these two sources include: enhanced C24 tetracyclic terpane concentrations relative to C26 tricyclic terpanes; diminished C28–30 tricyclic terpanes relative to Ts and Tm; diminished C30-steranes relative to their C29 counterparts; predominance of C35 over C34 extended hopanes and an even/odd predominance of the normal alkane distribution. Extracts from the Viola Group generally exhibit the same qualities as the associated oils and the limestone is proposed as their probable source rock. The predominance of C29-steranes for oil samples which appear to have a marine source (inferred by their n-alkane distribution, the presence of C30-steranes and high levels of tricyclic terpanes) suggests that caution be used in the interpretation of terrigenous sources based on the high abundance of C29-steranes. The Deese Group, the Springer Formation, the Sylvan Shale, and the Arbuckle Group are not likely sources for the oils analyzed from the Pauls Valley area. Differences in API gravity and color, previously used to classify oils in this region, are not source-related but are related to maturation and migration effects.

The Tertiary Thrace Basin located in NW Turkey comprises 9 km of clastic-sedimentary column ranging in age from Early Eocene to Recent in age. Fifteen natural gas and 10 associated condensate samples collected from the 11 different gas fields along the NW-SE extending zone of the northern portion of the basin were evaluated on the basis of their chemical and individual C isotopic compositions. For the purpose of the study, the genesis of CH 4, thermogenic C2+ gases, and associated condensates were evaluated separately. Methane appears to have 3 origins: Group-1 CH4 is bacteriogenic (Calculated ?13CC1-C = -61.48‰; Silivri Field) and found in Oligocene reservoirs and mixed with the thermogenic Group-2 CH4. They probably formed in the Upper Oligocene coal and shales deposited in a marshy-swamp environment of fluvio-deltaic settings. Group-2 (?13CC1-C = -35.80‰; Hamitabat Field) and Group-3 (?13C 1-C = -49.10‰; Degirmenköy Field) methanes are thermogenic and share the same origin with the Group-2 and Group-3 C 2+ gases. The Group-2 C2+ gases include 63% of the gas fields. They are produced from both Eocene (overwhelmingly) and Oligocene reservoirs. These gases were almost certainly generated from isotopically heavy terrestrial kerogen (?13C = -21‰) present in the Eocene deltaic Hamitabat shales. The Group-3 C2+ gases, produced from one field, were generated from isotopically light marine kerogen (?13C = -29‰). Lower Oligoce ne Mezardere shales deposited in pro-deltaic settings are believed to be the source of these gases. The bulk and individual n-alkane isotopic relationships between the rock extracts, gases, condensates and oils from the basin differentiated two Groups of condensates, which can be genetically linked to the Group-2 and -3 thermogenic C2+ gases. However, it is crucial to note that condensates do not necessarily correlate to their associated gases. Maturity assessments on the Group-1 and -2 thermogenic gases based on their estimated initial kerogen isotope values (?13C = -21‰; -29‰) and on the biomarkers present in the associated condensates reveal that all the hydrocarbons including gases, condensates and oils are the products of primary cracking at the early mature st age (Req = 0.55-0.81%). It is demonstrated that the open-system source conditions required for such an early-mature hydrocarbon expulsion exist and are supported by fault systems of the basin. © 2005 Elsevier Ltd. All rights reserved.

The Tertiary Green River petroleum system in the Uinta basin generated about 500 million bbl of recoverable, high pour-point, paraffinic crude oil from lacustrine source rocks. A prolific complex of marginal and open-lacustrine source rocks, dominated by carbonate oil shales containing up to 60 wt. % type I kerogen, occur within distinct stratigraphic units in the basin. Petroleum generation is interpreted to originate from source pods in the basal Green River Formation buried to depths greater than 3000 m along the steeply dipping northern margin of the basin. Producing fields in the Altamont-Bluebell trend have elevated pore-fluid pressures approaching 80% of lithostatic pressure and are completed in strata where open fractures provide permeability. Active hydrocarbon generation is one explanation for the origin of the overpressured reservoirs. In this study, experiments were undertaken to examine the mechanisms of hydrocarbon generation and accumulation in the Uinta basin. We combined analyses of representative source rocks from the entire Green River stratigraphic section with detailed laboratory simulation experiments using both open- and closed-system pyrolysis. This information provides new insights on lacustrine source rock lithofacies, gas-oil-source rock correlations, hydrocarbon generation kinetics, and basin modeling. The results show that the basal Green River Formation contains a unique type I source facies responsible for generation of paraffinic crude oils. The classic type I oil shales in the upper Green River Formation correlate well with low-maturity aromatic-asphaltic samples. We determined kinetic parameters for the source rocks and used them to develop basin models for hydrocarbon generation. The models show that hydrous pyrolysis kinetic parameters are more consistent with the natural data in terms of predicted timing and extent of oil generation as compared to models using Rock-Eval kinetics. (Begin page 1334)

Paleozoic source rocks and crude oils from the Anadarko basin, Oklahoma, have been characterized by means of a variety of organic geochemical techniques. The potential source rocks investigated include the Viola Group, Sylvan Shale, Lower Mississippian limestone, Chester group, Springer Formation, and Morrow group. The Woodford Shale, which is an important source rock in the basin and has been discussed extensively in the literature, was used as a laboratory standard in this study. The crude oils examined in this study were obtained from reservoir formations of various ages from throughout the basin. The source rock screening analysis indicates that the lower and middle subfacies of the Viola, especially from the southeastern part of the basin, have substantial oil-generation potential. The Sylvan is not a source rock, although the black shales in the Springer and Morrow have substantial oil- and especially gas-generation potential. The results of this study support the proposal for multiple sources of oil and gas generation in the Anadarko basin. Selected source rock and oil samples were characterized in more detail, and the distributions and concentrations (both relative and absolute concentrations) of biomarkers in different source rocks and oils were determined. The biomarker characteristics were combined with other geochemical and geological data to interpret the sources, depositional environments, diagenesis and catagenesis processes, migration, and weathering. Oil­source rock correlations were made between source rocks and a number of crude oils based on quantitative and qualitative biomarker distributions. Petrographic descriptions and graptolite reflectance measurements were used to evaluate ©Copyright 1997. The American Association of Petroleum Geologists. All rights reserved.1Manuscript received November 1, 1995; revised manuscript received April 8, 1996; final acceptance September 13, 1996. 2ARCO International Oil and Gas Company, 2300 W. Plano Parkway, Plano, Texas 75057. 3School of Geology and Geophysics, University of Oklahoma, Norman, Oklahoma 73019.

Biomarkers are compounds, generally hydrocarbons, present in crude oils and source rocks whose carbon skeletons can be readily related to a precursor molecule occurring in the original source material. The use of biomarkers in source rock extracts and crude oils for the purpose of determining source materials, thermal maturity, extent of biodegradation and migration and for making oil/oil and oil/source rock correlation studies has been well documented. One of the major problems with this approach is the possibility of contamination either naturally, through crude oil migration, or artificially during sample collection or work-up procedures. A solution to this potential problem can be found in the use of biomarkers produced by kerogen pyrolysis. The actual isolation of the kerogen eliminates any potential contaminants and pyrolysis of the kerogen produces indigenous biomarkers. In this paper it is intended to review progress that has been made in the study of biomarkers produced by kerogen pyrolysis. The various techniques that have been used in this approach will be discussed and examples given to show, in particular, the distributions of triterpanes and steranes produced by kerogen pyrolysis. In addition, results obtained from a combination of hydrous pyrolysis to artificially mature kerogens, and anhydrous pyrolysis to characterize the artificially matured kerogens, will be discussed. Certain biomarkers such as the C 28 -bisnorhopane and gammacerane are not produced during anhydrous pyrolysis and possible reasons for these observations will be discussed. Finally, the production of sulphur-containing compounds during pyrolysis reactions will be briefly discussed with reference to their role as possible indicators of maturity and depositional environments.