Source Rock Kerogen Research Articles

Quantitative estimation of overpressure caused by gas generation and application to the Baiyun Depression in the Pearl River Mouth Basin, South China Sea

AbstractHydrocarbon generation can yield high fluid pressures in sedimentary basins as the conversion of solid kerogen to hydrocarbons can result in an increase in fluid volume. To quantify the relationship between gas generation and overpressure in source rocks, a set of equations for computing the pressure change due to gas generation has been derived. Those equations can be used to quantitatively estimate overpressure generated by type III kerogen in source rocks by considering gas generation and leakage, gas dissolution in formation water and residual oil, thermal cracking of oil to gas, and hydrocarbon episodic expulsion from source rocks. The equations also take consideration of other factors including source rock porosity, transformation ratio, total organic carbon (TOC), hydrogen index, and compressibility of kerogen, oil, and water. As both oil and gas are taken into account in the equations, they can also be used to estimate the evolution of overpressure caused by hydrocarbon generation of type I and type II kerogen source rocks. Sensitivity analyses on the type III kerogen source rock indicate that hydrogen index is the most influential parameter for overpressure generation, while TOC and residual gas coefficient (β: ratio of residual gas over the total gas generated) have a moderate effect. Overpressure can be generated even if the gas leakage/loss in the source rock is up to 80% of the total gas generated. This suggests that the internal pressure seal of the source rock is not a critical factor on the pressure change as long as the source rocks are capable of sealing liquid oil. The equations were applied to evaluate the overpressure in the Eocene–Oligocene Enping Formation source rocks due to hydrocarbon generation in the Baiyun Depression, the Pearl River Mouth Basin by considering the source rock properties, hydrocarbon generation history, and hydrocarbon expulsion timing. Two episodes of overpressure development due to gas generation and release were modeled to have occurred in the Enping Formation source rock since 16 Ma. The overpressure release at 10.2–5.3 Ma via hydrocarbon expulsion was apparently related to the Dongsha phase of tectonic deformation, whereas the pressure release at 2–0 Ma was due to pressure generation that was exceeded the fracture‐sealing pressure in the source rocks.

Hydrocarbon potential, thermal maturation of the Jurassic sequences, and the genetic implication for the oil seeps in North Thrust Zone, North Iraq

The organic geochemistry is studied for the rocks of three Jurassic formations: Sargelu, Naokelekan, and Chia Gara from the north of Iraq. These rocks comprise bituminous carbonate and shale rocks. The hydrocarbon source rock potential is evaluated by using total organic carbon (TOC) and Rock-Eval Pyrolysis. The prevalence of high values of TOC (2.21–45.12 wt.%) associated with moderate to high values of HI (225–550 mg HC/g TOC), low OI (1–33 CO2/g TOC), and high S2 values (4.53–181.0) indicate very good to excellent source rock potential for these rocks with mostly type II kerogen and few mixed-type II/III kerogen of oil prone source rocks. This is supported by high values of S2/S3 ratios (>5). Tmax values range from 440 to 447 °C in agreement with the calculated R o values (0.76–0.90) infer early to peak thermally mature stage. Based on the TOC and pyrolysis data, the rocks of the three formations have indigenous hydrocarbon mature oil prone. The geochemical investigation of biomarker parameters were performed for oil samples from two oil seepages (Banik and Tawke) which are located in the same area using gas chromatography-mass spectrometry and stable carbon isotope measurements. The measured values of Pr/n-C17 for oil samples are low coupled with high values of Ph/n-C18 indicating marine organic matters with type II kerogen accumulated under marine reducing condition. The values and plots of δ13C (saturate and aromatic) also approve the prevalence of marine reducing condition. The source rocks for the oils of both seepages are interpreted to be carbonate rocks of Mesozoic age by the measured CV values which are 0.25. All these data are in consistent with marine carbonate source rocks for these oils. The paleoredox depositional environment for the source rocks is interpreted by the low value of Pr/Ph (0.74 in Banik) and high values of homohopane ratio C35S/C34S (1.21 in Banik and 1.13 in Tawke); the values of C29/C30 (norhopane/hopane >1) as well as the high sulfur content all indicate reducing condition during the deposition of the marine source rocks. The concentrations of C27, C28, and C29 reflect the prevalence of marine algal plankton organic matters. The measured Oleanane index equal zero which indicates age older than Lower Cretaceous for the source rocks. This documented by the calculated values of C28/C29 sterane ratio, and plots on Geomark Research database gives an age of Middle–Upper Jurassic for the source rocks. According to the characteristics of depositional environment of the source rocks, the paleoredox condition, and age estimation, the oils of Banik and Tawke could be derived from the rocks of Sargelu, Naokelekan, and Chia Gara Formations.

The source of highly overmature solid bitumens in the Permian coral reef paleo-reservoirs of the Nanpanjiang Depression

Solid bitumens occur extensively in Permian coral reefs of the Nanpanjiang Depression. Both potential source rocks and solid bitumens in the study area are highly overmature and have similar bulk carbon isotope values. It is difficult to perform an oil–source rock correlation study in this area based on only regular molecular geochemical methods and bulk carbon isotope values. Thus the covalently bound biomarkers released from solid bitumens and source rock kerogens by catalytic hydropyrolysis (HyPy), together with the geological settings, were taken into account in this oil–source rock correlation study. The distribution characteristics of covalently bound biomarkers suggest that the major source rock of the Longlin paleo-reservoir (in the midwest of the depression) solid bitumen should be the Middle Devonian mudstone, whereas the source rock of the Ziyun paleo-reservoir (in the north of the depression) solid bitumen should be the Lower Permian source rock. However, solid bitumens in the Ceheng and Wangmo paleo-reservoirs (in the middle of the depression) may be mainly sourced from the Middle Devonian source rock, but partly from the Permian source rock. Our bitumen–source rock correlation results are also supported by the petroleum geological settings of the study area, which indicate that the filling of those paleo-reservoirs was controlled by the matching of hydrocarbon generation and trap formation. Basically, the timing of hydrocarbon generation of the Middle Devonian source rocks matches well with the formation of Permian coral reef traps in the middle and midwest portions of the depression, but it is earlier than the formation of the Permian coral reef trap in the north of the depression. We show that our oil–source rock correlation study based on covalently bound biomarkers can provide reliable information for petroleum system analysis when highly overmature strata in South China are involved.

A comparison of results from two different flash pyrolysis methods on a solid bitumen sample

A Cambrian solid bitumen from northwestern Sichuan Basin, southern China was analyzed using two different flash pyrolysis methods coupled with gas chromatography–mass spectrometry analysis, including Pyroprobe® and analytical laser micropyrolysis. Results show that pyrolysis products from a Pyroprobe® (model 5000) analysis are dominated by mono-, di- and tricyclic aromatic hydrocarbons, whilst those from laser micropyrolysis are dominated by aliphatic hydrocarbons (n-alk-1-ene/n-alkane doublets), which is consistent with the results from an FT-IR spectrum of the solid bitumen. According to the molecular compositions of the pyrolysates from two types of pyrolysis, results from a 532nm continuous wave laser may be more suitable for pyrolysis research of bitumen/asphaltene. Thus, differences in pyrolysis techniques must be considered when used to characterize oil asphaltenes or source rock kerogens.

The origin of solid bitumen in the Honghuayuan Formation (O1h) of the Majiang paleo-reservoir—Evidence from catalytic hydropyrolysates

Large amounts of solid bitumen occur in the Honghuayuan Formation of the Lower Ordovician (O1h) within the Majiang paleo-reservoir. Most of the potential source rocks and solid bitumens in the Southern Guizhou Depression are of high maturity (%Ro>2). Consequently, the yields of extractable organic matter (EOM) from the potential source rocks and solid bitumens are too low to satisfy the requirement of instrumental analysis. Moreover, the reliability of oil–source correlations based on biomarkers in EOM may be questionable because the routine biomarkers obtained by Soxhlet extraction may have been severely altered by secondary alterations. In this research, catalytic hydropyrolysis (HyPy) is used to release covalently bound biomarkers from highly overmature kerogens and solid bitumens. We analyzed the covalently bound biomarkers and n-alkanes released from the O1h solid bitumens and potential source rock kerogens via catalytic hydropyrolysis by using gas chromatography–mass spectrometry and gas chromatography–isotope ratio mass spectrometry to clarify the oil–source correlation of the Majiang paleo-reservoir. Compared with free biomarkers in EOM, the covalently bound biomarkers released by HyPy exhibit low-maturity characteristics and they retain inherited geochemical information. The oil–source correlation indicates that the Lower Cambrian marine mudstones are the main source for the O1h solid bitumens of the Majiang paleo-reservoir. Furthermore, this research also suggests that some of the O1h solid bitumens had suffered severe biodegradation ahead of thermal alteration.

Evaluation of the rhenium–osmium geochronometer in the Phosphoria petroleum system, Bighorn Basin of Wyoming and Montana, USA

Rhenium–osmium (Re–Os) geochronometry is applied to crude oils derived from the Permian Phosphoria Formation of the Bighorn Basin in Wyoming and Montana to determine whether the radiogenic age reflects the timing of petroleum generation, timing of migration, age of the source rock, or the timing of thermochemical sulfate reduction (TSR). The oils selected for this study are interpreted to be derived from the Meade Peak Phosphatic Shale and Retort Phosphatic Shale Members of the Phosphoria Formation based on oil–oil and oil–source rock correlations utilizing bulk properties, elemental composition, δ13C and δ34S values, and biomarker distributions. The δ34S values of the oils range from −6.2‰ to +5.7‰, with oils heavier than −2‰ interpreted to be indicative of TSR. The Re and Os isotope data of the Phosphoria oils plot in two general trends: (1) the main trend (n=15 oils) yielding a Triassic age (239±43Ma) with an initial 187Os/188Os value of 0.85±0.42 and a mean square weighted deviation (MSWD) of 1596, and (2) the Torchlight trend (n=4 oils) yielding a Miocene age (9.24±0.39Ma) with an initial 187Os/188Os value of 1.88±0.01 and a MSWD of 0.05. The scatter (high MSWD) in the main-trend regression is due, in part, to TSR in reservoirs along the eastern margin of the basin. Excluding oils that have experienced TSR, the regression is significantly improved, yielding an age of 211±21Ma with a MSWD of 148. This revised age is consistent with some studies that have proposed Late Triassic as the beginning of Phosphoria oil generation and migration, and does not seem to reflect the source rock age (Permian) or the timing of re-migration (Late Cretaceous to Eocene) associated with the Laramide orogeny. The low precision of the revised regression (±21Ma) is not unexpected for this oil family given the long duration of generation from a large geographic area of mature Phosphoria source rock, and the possible range in the initial 187Os/188Os values of the Meade Peak and Retort source units. Effects of re-migration may have contributed to the scatter, but thermal cracking and biodegradation likely have had minimal or no effect on the main-trend regression. The four Phosphoria-sourced oils from Torchlight and Lamb fields yield a precise Miocene age Re–Os isochron that may reflect the end of TSR in the reservoir due to cooling below a threshold temperature in the last 10m.y. from uplift and erosion of overlying rocks.The mechanism for the formation of a Re–Os isotopic relationship in a family of crude oils may involve multiple steps in the petroleum generation process. Bitumen generation from the source rock kerogen may provide a reset of the isotopic chronometer, and incremental expulsion of oil over the duration of the oil window may provide some of the variation seen in 187Re/188Os values from an oil family.

Improved understanding of mixed oil in Nigeria based on pyrolysis of asphaltenes

Crude oil from reservoirs in the onshore Niger Delta is a mixture of low and high maturity charge. Aromatic biomarkers in these oils, such as alkylphenanthrenes and alkylnaphthalenes, show relatively high thermal maturity, whereas the saturated sterane and hopane biomarkers indicate lower maturity close to the peak of the oil window. The high predicted maturity of the crude oils based on alkylphenanthrene and alkylnaphthalene indices is probably caused by mixing of high maturity condensate with less mature black oil. This correlates with the gas washing phenomenon of studied Nigerian oils caused by migrating condensate stream. The results of our study indicate that asphaltenes can be used to infer the organofacies of the low maturity petroleum charge in mixed crude oils. Compositional characteristics of the asphaltene pyrolysates indicate an origin of the related oils from Type II/III or Type III source rock kerogen. The n-alkyl-chain length distributions of the asphaltene pyrolysates predict source rocks that generated high wax paraffinic–naphthenic–aromatic oils or paraffinic oils. The n-alkyl-chain length of asphaltene pyrolysates changes in proportion to oxicity and the relative input of terrigenous organic matter to the source rock.

TSR origin of sulfur in Permian and Triassic reservoir bitumen, East Sichuan Basin, China

Solid bitumen, H 2S, pyrite and anhydrite samples from the Lower Triassic Feixianguan Formation and Upper Permian Changxing Formation, and source rock kerogen samples from the Cambrian, Ordovician, Silurian and Permian in the East Sichuan Basin were analyzed for their sulfur content and δ 34S values, to determine if the measurements were consistent with a thermochemical sulfate reduction (TSR) origin of the produced H 2S and solid bitumen. The results show that the solid bitumen samples have sulfur contents from 2.6 to 12.5 wt.% and δ 34S values from +13.4‰ to +22.1‰. The δ 34S values are significantly heavier than those of potential Upper Permian source rock kerogens that average +1.3‰ ( n = 3), suggesting that most of the sulfur in the solid bitumen is derived from isotopically heavy H 2S of TSR origin (from +12.0‰ to +13.7‰). Interestingly, two gases produced from gas to water transition zones during drill stem testing (DST) show significantly lighter δ 34S values (+3.3‰ and +4.1‰) than the H 2S from gas-producing intervals. The isotopically light H 2S may be genetically linked to fracture-filling isotopically heavy anhydrite with δ 34S values from +38.5‰ to +39.6‰, which are significantly heavier than those of coeval seawater sulfate (+11.8‰ to +21.7‰) as measured for bedded anhydrite. The link may have resulted from reduction of part of the dissolved sulfate by hydrocarbons under sulfate-limited conditions. Source rock kerogens show a secular change in δ 34S values relative to source rock age. A dramatic decrease and then increase in δ 34S kerogen was found toward the Permian/Triassic boundary for the first time in the East Sichuan Basin.

Changes in gas composition during simulated maturation of sulfur rich type II-S source rock and related petroleum asphaltenes

Asphaltenes extracted from crude oils are proposed to possess structural features of the related source rock kerogen. For the present study micro-scale sealed vessel pyrolysis (MSSV) and combustion isotope ratio mass spectrometry (GC–C–IRMS) were used to compare gas generation from a whole rock (type II-S kerogen) from southern Italy with that from related sulfur rich asphaltenes isolated from a low maturity heavy crude oil. The purpose of was to determine whether experimental pyrolysis of oil asphaltenes can be used to predict the timing and the chemical and isotopic composition of hydrocarbon gases generated from genetically related kerogen in the source rock during burial maturation. The results show that parameters such as (gas to oil ratio) GOR and oil and gas formation timing are very similar for these two sample types, whereas gas composition, product aromaticity and sulfur content are remarkably different. Slight differences in GOR are mainly due to differences in gas formation characteristics at very high levels of thermal alteration. Secondary gas formation from the whole rock covers a much broader temperature range under geological conditions than that from the asphaltene products. However, it is remarkable that both the onset and the maximum temperature are nearly identical under geological conditions. The observed differences in gas generation characteristics are supported by discrepancies in the carbon isotopic characteristics of the gas range compounds and indicate different precursors and/or mechanisms for gas generated from whole rock and asphaltenes.

Timing and petroleum sources for the Lower Cretaceous Mannville Group oil sands of northern Alberta based on 4-D modeling

The Lower Cretaceous Mannville Group oil sands of northern Alberta have an estimated 270.3 billion m3 (BCM) (1700 billion bbl) of in-place heavy oil and tar. Our study area includes oil sand accumulations and downdip areas that partially extend into the deformation zone in western Alberta. The oil sands are composed of highly biodegraded oil and tar, collectively referred to as bitumen, whose source remains controversial. This is addressed in our study with a four-dimensional (4-D) petroleum system model. The modeled primary trap for generated and migrated oil is subtle structures. A probable seal for the oil sands was a gradual updip removal of the lighter hydrocarbon fractions as migrated oil was progressively biodegraded. This is hypothetical because the modeling software did not include seals resulting from the biodegradation of oil. Although the 4-D model shows that source rocks ranging from the Devonian–Mississippian Exshaw Formation to the Lower Cretaceous Mannville Group coals and Ostracode-zone-contributed oil to Mannville Group reservoirs, source rocks in the Jurassic Fernie Group (Gordondale Member and Poker Chip A shale) were the initial and major contributors. Kinetics associated with the type IIS kerogen in Fernie Group source rocks resulted in the early generation and expulsion of oil, as early as 85 Ma and prior to the generation from the type II kerogen of deeper and older source rocks. The modeled 50% peak transformation to oil was reached about 75 Ma for the Gordondale Member and Poker Chip A shale near the west margin of the study area, and prior to onset about 65 Ma from other source rocks. This early petroleum generation from the Fernie Group source rocks resulted in large volumes of generated oil, and prior to the Laramide uplift and onset of erosion (58 Ma), which curtailed oil generation from all source rocks. Oil generation from all source rocks ended by 40 Ma. Although the modeled study area did not include possible western contributions of generated oil to the oil sands, the amount generated by the Jurassic source rocks within the study area was 475 BCM (2990 billion bbl).

Compositions and significance of crude oil stains in Bowser and Sustut basins (Intermontane Belt) British Columbia

Abstract Crude oil stains occur geographically and stratigraphically widely in Bowser and Sustut basins in the Intermontane Belt, British Columbia. Bitumens extracted from Jurassic and Cretaceous Bowser Lake and Sustut groups have compositions indicating at least three petroleum systems. Many of the samples are from outcrops or shallow depths and some are lightly to moderately biodegraded. In some samples the biodegradation affects the normal alkanes generally and isoprenoid compounds partly, such that the polycyclic biomarker compounds are inferred to be unaltered. This is confirmed by systematic variations within and among compositional fractions and compounds. Compositional differences among the samples are best illustrated by variations of steranes and terpanes, but are also observed in gross compositional traits and other saturate and aromatic fraction compounds. One oil family is inferred to be derived from source rock kerogens in Lower Jurassic and older Stikine Assemblage. This petroleum has characteristics of pre-Jurassic, marine, carbonate source rocks deposited in hypersaline to mesohaline environments. A second oil family is derived from Mesozoic open marine source rock kerogens that are inferred to lie within the organic-rich lithologies found in distal fine clastic deposits of the upper Hazelton and lower Bowser Lake groups deposited during progradation of the Bowser clastic wedge. A third oil family that occurs only in the northern Bowser and Sustut basins originates from non-marine Mesozoic source rock kerogens, probably within thick, often coaly, non-marine upper Bowser Lake assemblages. Many of the extracted crude oils occur in rocks where the host rock vitrinite reflectance is significantly higher than the thermal maturity inferred from the crude oil geochemistry. The occurrence and composition of these crude oils expand the petroleum prospectivity of Bowser and Sustut basins by reducing petroleum system risks generally, and by indicating a possible petroleum system for Hazelton Group reservoirs, which now should be attributed a petroleum potential, where before Hazelton Group was considered commonly to be economic basement.

The significance of kinetic parameters and structural markers in source rock asphaltenes, reservoir asphaltenes and related source rock kerogens, the Duvernay Formation (WCSB)

Asphaltenes from reservoir oils, source rock bitumen and the kerogen of related source rocks of the Duvernay Formation (WCSB) have been studied in order to compare their petroleum generation characteristics. Open system bulk petroleum pyrolysis for bulk kinetic evaluation and geological extrapolation and pyrolysis GC experiments for petroleum compositional characterisation were applied in order to evaluate the reliability of petroleum asphaltenes in source rock evaluation studies in which a potential source rock sample is not available. Kinetic parameters and resulting geological extrapolations of petroleum formation calculated on immature source rock kerogens and asphaltenes fit exactly to corresponding parameters measured on asphaltenes precipitated on low mature oils. In contrast molecular characteristics such as aromaticity and the amount of alkylated thiophenes reveal highest values in source rock asphaltenes, while oil asphaltenes demonstrate lowest aromaticity. Source rock kerogens seem to represent an intermediate between both types of asphaltenes at low levels of maturity. Interestingly the molecular ratios observed in products formed from oil asphaltenes fit exactly to those observed in natural oils and support the application of petroleum asphaltenes to predict petroleum formation and especially petroleum compositional characteristics.

From petroleum-type organofacies to hydrocarbon phase prediction

The organic facies concept states that kerogen abundance and composition are relatable to depositional settings. This link has been extended, using open-system pyrolysis methods, to include major petroleum types whose gross compositions are inherently defined by source rock kerogens and, hence, to petroleum composition, which directly controls the physical response of fluids to changing pressure and temperature conditions during secondary migration. The possibility to model petroleum composition during hydrocarbon generation as well as the phase behavior of the fluids during migration is now available in modern basin modeling software. However, whereas pyrolysis methods can accurately reconstruct hydrocarbon gas:oil ratios and liquid compositions, they are inherently incapable of correctly reproducing the gas composition of natural fluids, and because the gas composition dominantly controls the phase behavior of petroleums, multicompound compositional kinetic predictions based on pyrolysis results alone are inappropriate for the prediction of phase behavior. The new PhaseKinetics approach described here combines open- and closed-system pyrolysis techniques to characterize the compositional evolution of the fluids generated as a function of increasing thermal stress, as well as correcting experimentally determined gas compositions and, therefore, overcomes these deficiencies. It has been used to develop compositional kinetic schemes capable of predicting natural petroleum phase behavior for different organofacies types. The methodology uses a compositional description of the generated fluids similar to that used in pressure-volume-temperature (PVT) simulation. Selected studies in the Norwegian North Sea, Brazil, and Mexico demonstrate the quality of the tuned compositional predictions for different organic facies types.

The origin of thermogenic gas hydrates on the northern Cascadia Margin as inferred from isotopic ( 13C/ 12C and D/H) and molecular composition of hydrate and vent gas

The isotopic ( δ 13C and δD) and hydrocarbon compositions of hydrate-bound and vent gas collected from the seafloor of Barkley Canyon (northern Cascadia Margin, offshore Vancouver Island, Canada) were evaluated to characterize the gas and infer the type and maturity of the source rock kerogen. The hydrate gas contained methane having δ 13C values from −43.4‰ to −42.6‰, δD values from −143‰ to −138‰ and a large percentage (14.9% to 31.9%) of C 2 to C 5+ hydrocarbons. These data are consistent with a thermogenic gas source. The data from Barkley Canyon are interpreted within the context of similar data from the Gulf of Mexico and Caspian Sea thermogenic hydrates, which occur in regions where the petroleum systems supporting gas and oil generation are better understood. A stable carbon isotope-based natural gas plot model and D/H data from the hydrate gas indicate that the source rock for the Barkley Canyon hydrate and vent gas had primarily Type III kerogen mixed with a small fraction of Type II kerogen. Oil from a seep having a pristane/phytane ratio of 3.2 was identified as a gas condensate, which supports the conclusions drawn from the gas data. A mechanism for explaining how fluids are conducted from the deep petroleum reservoir to the seafloor of Barkley Canyon is proposed.

Potential of thermogravimetric analysis coupled with mass spectrometry for the evaluation of kerogen in source rocks

The molecular composition of oil and yield from a source rock depends on the temperature to which the source rock is subjected. However, the yield of oil and gas represents hydrocarbons generated over a range of temperatures. A technique that measures both volatile yields and bulk and molecular compositions during volatile evolution would determine the differential effects of temperature change, thereby giving information on the effect of thermal gradients. Attaching a mass spectrometer to a thermogravimetric analyser assists in this goal since it allows gases to be analysed during petroleum source rock evaluation by pyrolysis. Single ion monitoring allows unambiguous identification of thermal events. It reveals temperature at which water, methane and carbon dioxide evolve. This allows organic and inorganic transitions to be distinguished. Parameters that describe the yields of oil and gas can also be derived from thermogravimetric analysis (TGA) in much the same way as they can for Rock–Eval pyrolysis data and are useful when combined with solid state 13C nuclear magnetic resonance (NMR) spectroscopy and Rock–Eval data for elucidating mineral matter effects.

Potential of emission Fourier transform infrared spectroscopy for in situ evaluation of kerogen in source rocks during pyrolysis

Eleven petroleum source rock samples have been examined by Emission Fourier transform infrared spectroscopy (FTIRES) and by Rock-Eval thermal analyses. FTIRES has been used to estimate the amount of C–H aliphatic and C–H aromatic signal lost during thermal treatment at Rock-Eval temperatures. In particular, the loss of signal from 150°C to 300°C has been monitored and compared to the yield of oil obtained over this range by Rock-Eval analysis. Likewise, signal loss between 300–500°C and 500–700°C was monitored. Correlations of FTIRES changes with Rock-Eval pyrolysis derived parameters were not found because FTIRES reflects changes in composition of undistilled material during pyrolysis. However, by relating Rock-Eval and FTIRES derived parameters a source rock quality index can be derived. This index can be useful as a quick routine method for scanning samples to determine if the free oil in the source rock was generated by thermal maturation of the same source rock.

Carbon isotopic composition of organic acids in oil field waters, San Joaquin Basin, California, USA

The carbon isotopic compositions of short-chain organic acids (C 2-C 5) in oilfield waters of the San Joaquin Basin exhibit a wide range of values, from +0.57 to −27.33‰ (PDB). Most, however, are in the range of −15 to −25‰. The bulk isotopic compositions of individual acids generally become isotopically depleted (more negative) with increasing carbon number (chain length) but are consistently more enriched than the isotopic composition of coproduced oils. Relationships between carbon number and isotopic composition of the acids suggest intramolecular isotopic fractionation. Calculated carboxyl carbons (COOH) are isotopically more enriched, typically by 10 to 38‰, than aliphatic carbons (CH). Calculated aliphatic carbon isotopic compositions cluster around two values, −23 and −28‰, consistent with the isotopic composition of coproduced oils derived from two different sources, Miocene Monterey–sourced oils (−22 to −25‰) and Eocene Kreyenhagen–sourced oils (−28 to −30‰). We suggest that the isotopic composition of the aliphatic carbons in the organic acids reflects the carbon isotopic composition of the coproduced oils (or their source kerogen). Isotopic compositions of carboxyl carbons fall within a range of −12.8 to +8.0, consistently heavier than aliphatic carbons. We interpret the enrichment of carboxyl carbons to be inherited from either biological precursors in the source rock kerogen or due to exchange with carbon in dissolved HCO 3. The carbon isotopic enrichment of carboxyl carbons is at odds with theories that attribute organic acids to the inorganic oxidation of hydrocarbons in the subsurface.

The occurrence of fatty acids in immature source rocks and their distribution characteristics

The fatty acids in extractable bitumen and kerogen of immature source rocks of the Liaohe Basin and Jiyang sag were investigated in this study. The result showed that the bitumen fatty acids were mainly associated with non-hydrocarbon fraction and that the kerogen fatty acids with some tightly bound fatty acids were mainly bounded in a net structure of kerogen by ester bonds. For the investigated source rocks, the fatty acids in bitumen, bound fatty acids and tightly bound acids in kerogen ranged in 0.01%–0.073 9%, 0.005%–0.045 5% and 0.005%–0.010% respectively. Among the fatty acids analyzed in this study, mono-carboxylic acids, α, ω)-di-carboxylic acids and hydroxy acids accounted for 70%–100%, 0%–30% and <10% respectively. It was also found that the monocarboxylic acids with longer chains mainly existed in bitumen, and that the α, ω)-di-carboxylic acids and hydroxy acids mainly existed in kerogen. From above, it was assumed that the monocar-boxylic acids in bitumen might have played an important role in the hydrocarbon generation from fatty acids in immature source rocks.

Determining the temperature of petroleum formation from the kinetic properties of petroleum asphaltenes

Knowledge of the timing and location of petroleum formation is important in assessing the extent of available reserves in hydrocarbon-forming basins. This can be predicted from the thermal history of a basin and the kinetic parameters that characterize the thermal breakdown of kerogen in source rocks. At present, the kinetic parameters of kerogen breakdown are experimentally determined using immature rock samples from basin margins, but questions remain about the accuracy of this approach, especially when significant variability is observed within individual source units. Here we show that the kinetics of hydrocarbon generation from petroleum asphaltenes can be used to determine the temperature conditions of the actual source rock at the time of expulsion of the sampled petroleum. This relationship reflects the structural similarity of asphaltenes to the parent kerogen. We expect that our approach may be used as a comparatively simple alternative method for assessing the petroleum generation characteristics of a given basin, which will allow for better estimates of the available oil resources and the risks associated with their exploration.

Chemical Structure and Biomarker Content of Jinghan Asphaltenes and Kerogens

The compound classes and biomarker compositions of immature Jinghan crude oil asphaltenes and their potential respective source rock kerogens have been investigated by chemolysis. The C-S-, C-O-, and C arom -C-bound appendages have been liberated by Ni 2 B reduction, BBr 3 hydrolysis, and ruthenium-ions-catalyzed oxidation. Measured were the saturate, aromatic, and polar (+ asphaltene) compound classes and the homologous series of hydrocarbon biomarkers: n-alkanes, regular isoprenoids, steranes, 4-methylsteranes, hopanes, gammacerane, their monocarboxylic acid derivatives, and α,ω-di-n-alkanoic acids. The nature and distribution of the biomarkers in shallower depths reveals a good correlation between the crude oil asphaltene and the kerogen, manifesting a crude oil-source rock relationship. In deeper strata, the correlation is less convincing but there is no indication of incompatibility. The biomarker composition confirms the immaturity of this deposit, and the huge (53%) yields of C-S plus C-O bond cleavage products from the high-sulfur asphaltene set this type of asphaltene aside from mature crude oil asphaltenes. Also, the biomarker composition points to a strongly reducing, lacustrine depositional environment for this deposit.