Oil Geochemistry Research Articles

Molecular and carbon isotopic geochemistry of oils with different fluorescence color from the Upper Jurassic Qigu formation and oil accumulation process in Yongjin area, Junggar Basin in China

The Yongjin area, located in the middle of the Junggar Basin, is an important oil-producing region. Its major oil-producing formation is the Upper Jurassic Qigu Formation, which has experienced multiple oil-charging events that have resulted in oils with various fluorescent colors. However, the source of oils from the Qigu Formation is currently debated. As exploration and development progressed, the productivity of the Qigu Formation was observed to vary owing to oil viscosity differences. Conventional extraction methods can only be used to obtain a mixture of fluorescing oils of different colors, making it difficult to analyze the properties of oils that charge during different periods. Using microscopy to observe fluorescence the characteristics of oil in various samples were analyzed. Then, accelerated sequential extraction was used to separate the oils with different fluorescent colors (Groups I–IV). Through GC-MS (gas chromatography), GC-IRMS (gas chromatography-mass spectrometry), FT-IR (fourier transform infrared spectroscopy), and fluid inclusion observations and measurements, in conjunction with the geological context, the sources of oils from different charge periods and genesis of heavy oil were determined and the process of oil accumulation was reconstructed. Three stages of oil charging were identified: (1) During the Middle to Late Jurassic, low-mature and mature oil from the Lower Permian Fengcheng Formation and a low quantity of low-mature oil from the Middle Permian Lower Wuerhe Formation charged the Qigu Formation. These oils underwent notable biodegradation and oxidation, with some captured by inclusions (Group III) for preservation. (2) During the Late Cretaceous to Early Paleogene, mature oil from the Wuerhe Formation charged the Qigu Formation. This oil mixed with early oil that was not captured by the inclusions, resulting in the formation of black-brown fluorescing oil (Group IV) and yellow fluorescing inclusion oil (Group II). (3) From the Late Paleogene to the present, highly mature condensates from the Lower Wuerhe Formation charged the Qigu Formation. The oil mixed with early oil to generate yellow-brown (Group II) and blue-white (Group I) fluorescing oils. Low-mature and mature oil from the Fengcheng Formation charged the Jurassic reservoirs and underwent secondary alteration, whereas high-mature oil and gas did not. These oils likely predominantly accumulated in reservoirs between the Fengcheng and Lower Wuerhe formations. Although the Jurassic source rocks began to generate oil, this oil did not migrate upward to the Qigu Formation, indicating that the conventional and unconventional reservoirs under the Jurassic Qigu Formation have exploration potential.

Geochemistry of oils and condensates from the lower Eagle Ford formation, south Texas. Part 6: Carbon isotopes

Compound specific carbon isotope analyses were performed on a well-characterized suite of unconventional oils and condensates produced from the lower Eagle Ford Formation. Thermal maturity is the major influence on the δ13C values of C3–C19 hydrocarbons. From ∼0.8 to ∼1.1 %Ro, the main stage of oil generation, the δ13C values of most measured hydrocarbons remain relatively constant: n-alkanes are ∼ −30 ‰: light aromatic hydrocarbons, cycloalkanes and isoprenoids are ∼ −29 to −28 ‰. Only the C4 to C10 methylalkanes exhibit high variance with carbon number with δ13C values ranging from ∼ −32 to −28 ‰, respectively. Hydrocarbons from samples ∼1.1 to 1.3 %Ro, the late oil generation stage, are 13C-enriched by ∼1–∼2 ‰. This is the range typically assigned to the influence of thermal maturity on oil from many conventional petroleum systems. The onset of significant oil cracking occurs at ∼1.3 %Ro and all measured hydrocarbons systematically become progressively 13C-enriched although the degree varies by compound class and carbon number. The δ13C values of individual hydrocarbons shift by as much as ∼ +9 ‰ for propane and butane to only ∼ +3 ‰ for methylcyclopentane from <1.1 to 1.7 %Ro. The 13C-enrichments observed in the Eagle Ford oils/condensates with increasing maturity are attributed to the kinetic isotope effect (KIE), whereby 12C–12C bonds cleave faster than 12C–13C bonds. No evidence for isotopic equilibrium was found. The consistency of the sums of the weighted δ13C values for C4–C7n-alkane/methylalkane isomers provides support for Mango's (2000a) theory that these hydrocarbons are generated from precursors with a common chemical structure that pass through a similar transition state.Source facies exert only a minor influence on the carbon isotopic composition of Eagle Ford oils/condensates. Small variances in the 13C values of C6+n-alkanes, cyclohexane and methylcyclohexane are consistent with oils produced east of the San Marco Arch being generated from shales with a higher influx of terrestrial high plant matter compared to the shales west of the Arch. Phase fractionation was shown to have a measurable impact on the δ13C values of the most volatile hydrocarbons in evaporated samples and on the least volatile hydrocarbon that underwent phase separation in the subsurface during production.

Molecular organic geochemistry and origin of oil in the Potwar Basin, Pakistan

The Potwar Basin (PTB) is a prominent geological feature located in northern part of Pakistan, and is considered as one of the active and productive regions for petroleum and gas exploration in Pakistan. In this study, eight crude oil specimens originating from three distinct fields within the PTB were comprehensively examined to decipher the environmental conditions, source of organic matter (OM) and oil-oil correlations using gas chromatography coupled with flame ionization detection (GC-FID) and gas chromatography-mass spectrometry (GC–MS). The molecular marker and hierarchical cluster analysis of PTB oils reveal two different crude oil families. Family-I showed relatively low values of Pr/Ph, C19TT/C23TT and C25TT/C24TeT, C27-C29 regular steranes, dibenzothiophene (DBT), fluorene (FL) and dibenzofuran (DBF), as well as C26/C28 TAS (20S) and C27/C28 TAS (20R). These results suggest that Family-I crude oils derived from marine environment of suboxic water bodies with higher contribution from green algae or planktonic microbes. However, Family II contains comparatively high values of the aforementioned molecular parameters, indicating that crude oils mainly originated from a lacustrine environment with a higher contribution of plant organisms under oxidizing conditions. Saturated hydrocarbon maturity parameters such as CPI and OEP, and C3122S/(C3122S + C3122R) and C3222S/(C3222S + C3222R) indicate PTB crude oils are thermally mature, while aromatic indices reveal that Family-II crude oils are high mature. The present research defines that PTB crude oils contributed from mixed organic matter sources of marine and lacustrine majorly from marine sedimentary environment with the bloom of algae and/or higher plants.

The organic geochemistry of crude oil in the Saltpond Basin (Ghana): Organic source input, depositional environment, and thermal maturity

The Saltpond Basin, situated within the South Atlantic margin of Ghana, is a significant area for petroleum exploration but has received relatively limited research attention. Previous studies have examined source rock composition, but data on crude oil organic chemistry are lacking, hindering understanding of the basin’s petroleum system and evolution. To address this gap, we analyzed biomarkers and stable carbon-isotope ratios in Saltpond Basin crude oil using gas chromatography–mass spectrometry and gas chromatography–isotope ratio mass spectrometry to elucidate organic matter source, depositional environment, and thermal maturity. Findings were compared with oils from the West African segment of the South Atlantic margin, namely the Tano Basin and the Niger Delta Basin, to identify potential correlations and gain insights into regional variations. Molecular and isotopic results unveiled a significant prevalence of organic matter derived from lower marine organisms. Patterns of organic matter deposition and preservation in Saltpond oil samples suggested a suboxic marine transitional environment, contradicting conventional understanding of terrestrial dominance in such settings. Moreover, the potential for degradation processes to obscure differentiation between terrestrial and marine organic matter origins underscores the complex nature of organic matter dynamics in transitional marine environments. Analysis of molecular thermal maturity indices suggested Saltpond oils were expelled from source rocks exhibiting thermal maturity at the early maturity stage. Correlation analysis unveiled genetic disparities among crude oils sourced from the Saltpond Basin and those from the Tano and Niger Delta Basin, primarily due to variations in source input and depositional environment conditions. Saltpond oil exhibits lower terrestrial organic input than Tano Basin’s crude oils, which also have less terrestrial input than Niger Delta Basin crude oils. Additionally, its paleodepositional environment notably differs from oils in the Tano Basin (anoxic transitional marine-lacustrine settings) and the Niger Delta Basin (suboxic–oxic terrigenous deltaic or marine or lacustrine environments). Thermal maturity range of Saltpond oil is comparable to oils in the Tano Basin but lower than oils in the Niger Delta Basin. These findings provide valuable insights into petroleum generation history and unique organic geochemical characteristics within the Saltpond Basin, essential for exploration, production, and environmental management efforts in the region. Furthermore, correlation studies provide evidence that distinct biological, geological, and paleoenvironmental conditions shaped various oil types in the West African segment of the South Atlantic margin.

Geochemistry of High-Maturity Crude Oil and Gas from Deep–Ultradeep Reservoirs and Their Geological Importance in a Foreland Basin: A Case Study of the Southern Thrust Belt, Junggar Basin, Northwest China

Geochemistry of High-Maturity Crude Oil and Gas from Deep–Ultradeep Reservoirs and Their Geological Importance in a Foreland Basin: A Case Study of the Southern Thrust Belt, Junggar Basin, Northwest China

Geochemistry of Crude Oils from the Bazhenov Horizon (West Siberia)

Abstract —The Bazhenov horizon is the main source rock stratum of the West Siberian petroleum province, which possesses significant resources of hard-to-recover hydrocarbons, making it a unique exploration target. The study summarizes geochemical data on crude oils (39 samples) collected from pools within the Bazhenov and Tutleima formations. A comparative analysis of the carbon isotope composition and geochemical parameters calculated from the composition of the identified saturated and aromatic compounds (pristane/phytane, C29/C27 steranes, C35/C34 homohopanes, tricyclane index, relative concentrations of dibenzothiophenes) confirm a common aquatic genotype of the studied oils and their genetic affinity to the organic matter of the same age. At the same time, significant variations in the main physical and chemical characteristics of the studied Bazhenov oils may be caused their fractionation during migration processes.

Geochemical Biodegraded Oil Classification Using a Machine Learning Approach

Chromatographic oil analysis is an important step for the identification of biodegraded petroleum via peak visualization and interpretation of phenomena that explain the oil geochemistry. However, analyses of chromatogram components by geochemists are comparative, visual, and consequently slow. This article aims to improve the chromatogram analysis process performed during geochemical interpretation by proposing the use of Convolutional Neural Networks (CNN), which are deep learning techniques widely used by big tech companies. Two hundred and twenty-one chromatographic oil images from different worldwide basins (Brazil, the USA, Portugal, Angola, and Venezuela) were used. The open-source software Orange Data Mining was used to process images by CNN. The CNN algorithm extracts, pixel by pixel, recurring features from the images through convolutional operations. Subsequently, the recurring features are grouped into common feature groups. The training result obtained an accuracy (CA) of 96.7% and an area under the ROC (Receiver Operating Characteristic) curve (AUC) of 99.7%. In turn, the test result obtained a 97.6% CA and a 99.7% AUC. This work suggests that the processing of petroleum chromatographic images through CNN can become a new tool for the study of petroleum geochemistry since the chromatograms can be loaded, read, grouped, and classified more efficiently and quickly than the evaluations applied in classical methods.

Geochemistry of oils and condensates from the lower Eagle Ford Formation, south Texas. Part 5: Light hydrocarbons

There is a rich history of using light hydrocarbon distributions to characterize source and thermal maturity based on observations made on source rocks and petroleum fluids produced from conventional reservoirs. In this study, a suite of lower Eagle Ford oils and condensates was used to determine the accuracy and reliability of established light hydrocarbon parameters in an unconventional petroleum system. These samples have well defined organic source facies, generative temperatures, and extent of thermal cracking. They are largely free of the influence of long-distance migration, multiple charging events, reservoir alteration processes that commonly occur in conventional accumulations and free of contributions from other reservoirs along faults induced by fracturing.All established light hydrocarbon thermal maturity parameters are influenced to varying degrees by source facies. Ratios of i-C4/n-C4 and quaternary/tertiary dimethylpentanes linearly correlate with %Ro (R2 > 0.8) with negligible sensitivity to differences in source facies. The Isoheptane and C6–C7 branched/(branched + cyclic) hydrocarbon ratios correlate with %Ro (R2 > 0.8) but also are influenced by source facies. Some established C7 parameters are affected by thermal cracking: i-C5/n-C5 and toluene/n-C7 are the most sensitive ratios to the onset of intense hydrocarbon cracking (∼1.35 %Ro) and do not appear to be significantly influenced by source facies, C6–C7 branched/(branched + normal) hydrocarbons and methylcyclohexane/n-C7 both increase in response to cracking conditions but are significantly influenced by source facies, which is likely related to the presence of reactive clays. A revised formula for Ctemp is proposed: Ctemp = 161.9 + 29.4•(ln[2,4-DMP/2,3-DMP]). The revised Ctemp formula is applicable for oils/condensates with 2,4-DMP/2,3-DMP >0.25, expanding the practical limit from ∼120 to ∼160 °C, and yields Ctemp values consistent with the maximum exposure temperature with an accuracy of ∼ ±5 °C for most samples, excluding those that have been altered by evaporation. The Mango (1997) Ctemp formula should be used for lower maturity oils having DMP/2,3-DMP values < 0.25. Sample integrity is critical as many of the light hydrocarbon parameters are significantly altered by evaporative loss.

Petroleum geochemistry and origin of shallow-buried saline lacustrine oils in the slope zone of the Mahu sag, Junggar Basin, NW China

Recently, significant oil discoveries have been made in the shallower pay zones of the Jurassic Badaowan Formation (J1b) in the Mahu Sag, Junggar Basin, Northwest China. However, little work has been done on the geochemical characteristics and origins of the oil in the J1b reservoir. This study analyzes 44 oil and 14 source rock samples from the area in order to reveal their organic geochemical characteristics and the origins of the oils. The J1b oils are characterized by a low Pr/Ph ratio and high β-carotene and gammacerane indices, which indicate that they were mainly generated from source rocks deposited in a hypersaline environment. The oils are also extremely enhanced in C29 regular steranes, possibly derived from halophilic algae. Oil-source correlation shows that the oils were derived from the Lower Permian Fengcheng Formation (P1f) source rocks, which were deposited in a strongly stratified and highly saline water column with a predominance of algal/bacterial input in the organic matter. The source rocks of the Middle Permian lower-Wuerhe Formation (P2w), which were deposited in fresh to slightly saline water conditions with a greater input of terrigenous organic matter, make only a minor contribution to the J1b oils. The reconstruction of the oil accumulation process shows that the J1b oil reservoir may have been twice charged during Late Jurassic–Early Cretaceous and the Paleogene–Neogene, respectively. A large amount volume of hydrocarbons generated in the P1f source rock and leaked from T1b oil reservoirs migrated along faults connecting source beds and shallow-buried secondary faults into Jurassic traps, resulting in large-scale accumulations in J1b. These results are crucial for understanding the petroleum system of the Mahu Sag and will provide valuable guidance for petroleum exploration in the shallower formations in the slope area of the sag.

The role of water in the laboratory thermal advancement of immature type I kerogen from the Cretaceous Qingshankou Formation in China

To understand variations in geochemistry, organic petrology, and chemical composition of crude oil and byproducts, an immature sample from the Cretaceous Qingshankou Formation in the Songliao Basin, China, was analyzed by anhydrous and hydrous pyrolysis (AHP/HP) at a wide range of temperatures ranging from 300 °C to 450 °C. The geochemical parameters: TOC, S2, HI, and Tmax obtained from Rock–Eval pyrolysis showed both a decrease and an increase as thermal maturity progressed under HP and AHP conditions. Gas chromatography (GC) analysis showed the presence of n-alkanes in the C14 to C36 range in both expelled and residual byproducts, a Delta-shaped configuration although many samples had a gradually reducing (tapering) trend toward the high range. Gas chromatography-mass spectrometry (GC–MS) analysis revealed both an increase and a decrease in biomarker and very small changes in aromatic compound variations with increasing temperature during pyrolysis. To be more specific, C29Ts biomarker increased with temperature for the expelled byproduct, while the opposite trend was observed for the residual one. Next, The Ts/Tm ratio initially increased and then decreased with temperature while the C29H/C30H ratio fluctuated for the expelled byproduct but increased for the residual. Moreover, the GI and C30 rearranged hopane to C30 hopane ratio remained unchanged whereas the C23 tricyclic terpane/C24 tetracyclic terpane ratio and the C23/C24 tricyclic terpane ratio showed varying trends with maturity alike the C19/C23 and C20/C23 tricyclic terpane. Ultimately, based on organic petrography observations, increasing the temperature resulted in higher bitumen reflectance (%Bro, r) and optical and structural alterations in the macerals. The findings of this study provide valuable insights for future exploration endeavors in the studied region. Moreover, they contribute to our understanding of the significant role of water in the generation and expulsion of petroleum and associated byproducts, thereby facilitating the development of updated models in this field.

Geochemistry of carbonate-derived oils in the Seram Basin, eastern Indonesia: A new hydrocarbon generation, migration, and preservation model for exploration in fold-thrust belts

Geochemistry of carbonate-derived oils in the Seram Basin, eastern Indonesia: A new hydrocarbon generation, migration, and preservation model for exploration in fold-thrust belts

Organic Geochemistry of Crude Oils from the Kohat Basin, Pakistan

The crude oils from the reservoirs of Mela-01 and Mela-04 wells located in the Kohat Basin, Pakistan, were geochemically analyzed to evaluate the origin, depositional conditions, and thermal maturity of the rock units and possible facies from which these oils were sourced. Gas chromatography-mass spectrometry (GC-MS) was performed on the samples to obtain biomarker and non-biomarker parameters. Analyzed non-biomarker parameters, including carbon preference index (CPI), terrigenous to aquatic ratio (TAR), isoprenoids pristane to phytane (Pr/Ph), and biomarker parameters, including steranes and dibenzothiophene/phenanthrene (DBT/P) of aromatic compounds, were utilized in the present study to achieve the objectives. Most of these parameters suggest a mixed source of organic matter (marine/terrestrial) with sub-oxic conditions in the source rocks for the analyzed oil samples in the studied wells from Mela oilfield, Kohat Basin. Furthermore, the CPI and different biomarker parameters such as steranes C29 S/S+R, ββ/αα+ββ), moretane to hopane (M29/C30H), pentacyclic terpanes C27 (Ts/Ts+Tm), H32 (S/S+R) hopanes, and aromatic methylphenanthrene index (MPI) indicate that the analyzed oils have originated from thermally mature rocks falling in the oil window. As the studied Kohat Basin has multiple source rocks and contributes to the major petroleum production of the country, the present investigations reveal that its okthe Mela oils were generated by the strata of mixed organic matter that were deposited in marine sub-oxic conditions. Furthermore, this study suggests that this stratum would also have been produced in unexplored surrounding areas such as Tirah, Orakzai, and the Bannu Depression.

Petroleum Geochemistry of the Central and Eastern Onshore Niger Delta Basin: Oil-Oil Correlation Using Biomarkers and Multi-Variate Statistics

Petroleum geochemistry of oils in several depobelts of the world has been well documented based on biomarkers. However, there is paucity of data regarding the use of multi-variate statistics in oil-oil correlation study, particularly in the Sub-Saharan African region. The purpose of the study was to gain an insight into the geochemical differences and identify their cause(s) through the application of bulk properties, biomarker indices and multi-variate statistics. Correlation of oils from eight wellheads of three stratigraphic units within the Central and Eastern onshore Niger Delta Basin fields (AG and AS) were undertaken by gas chromatography-flame ionization detector. Utilization of bulk properties, biomarker indices and cross plot parameters somewhat separated the mature AG1-4, AS3 and AS4 oils deposited in oxic/suboxicshaly environment from AS2 oil deposited in anoxic fluvio deltaic environment. In-reservoir alteration and migration differences were the major factors responsible for the observed slight geochemical variability in the studied oils. Nevertheless, multi-variate principal component analysis indicated that the Central and Eastern onshore Niger Delta Basin oils were principally generated from similar organic matter sources. The implication here was that the geochemical variations in the studied oils were not significant, a conclusion corroborated by Pearson correlation model data.

Geochemistry of oils and condensates from the lower Eagle Ford formation, south Texas. Part 4: Diamondoids

A rich variety of diamondoid indices exists that are assumed to be diagnostic of source facies, thermal maturity, the extent of oil cracking, mixed oils, and reservoir alteration processes. These parameters were developed either from empirical relationships observed in source rocks and oils produced from conventional reservoirs or laboratory experiments. Diamondoid parameters are now being routinely applied to unconventional oils; however, their accuracy and reliability have not been rigorously tested in these petroleum systems.Here, we examine diamondoid compositions in a suite of lower Eagle Ford oils and condensates with well-constrained source facies and thermal maturity established by other geochemical measurements and basin modeling. Diamondoid concentrations are low in samples from ∼0.8 to 1.35 %Ro, and then increase significantly at higher maturity due to the cracking of less stable hydrocarbons. Most published maturity-dependent diamondoid indices are not diagnostic when maturity is ≲ 1.1 %Ro and are influenced by source facies. Based on our data, their predictive accuracy is no better than ±0.2 %Ro at higher maturity. Published source indices are not diagnostic of a specific kerogen type or lithofacies but may be used to differentiate sources in complex petroleum systems. Quantitative diamondoid analysis can be used to calculate the degree of oil-to-gas conversion; however, the natural variance in the baseline concentration of 3-+4-methydiamantanes limits its accuracy at maturities ≲1.35 %Ro. Three lower Eagle Ford oils associated with Karnes Trough faults exhibit anomalous diamondoid distributions behavior that these reservoirs received secondary charges from a source other than lower Eagle Ford (likely Austin Chalk). Evidence for a secondary charge was not apparent from the study of the saturated and aromatic biomarkers. In summary, established diamondoid maturity and source indices based on compound ratios should be used with caution to characterize unconventional oils/condensates while quantitative diamondoid analysis can be used with greater confidence and can provide insights that are not apparent from other geochemical parameters provided that highly accurate determination of diamondoid concentrations can be obtained. In the case of the Eagle Ford oils and extracts, analyses must be accurate to less than 1 ppm.

Terpane Characterization of Crude Oils from Niger Delta, Nigeria: A Geochemical Appraisal

The geochemistry of crude oils from the Niger Delta, Nigeria, were evaluated using the characterization of C₁₉ to C₃₅ terpanes. Analyses of two representative crude oils from Western and Central Niger Delta showed abundances of C₁₉ to C₂₉ tricyclic terpanes constituted 12.09% and 29.74%, C₂₄ tetracyclic terpane 0.31% and 0.15% and C₂₇ to C₃₅ pentacyclic terpanes 87.61% and 70.12%, respectively. Diagnostic ratios of terpanes indicated relatively low abundances of C₂₃, C₂₈ and C₂₉ tricyclic terpanes, low abundances of homohopanes, a significantly high abundance of oleanane and that the Niger Delta crude oils were derived from terrestrial organic matter source rocks deposited in an oxic environment during the Tertiary period. Multivariate oil-oil correlation plot showed the Western and Central Niger Delta crude oils are not distinct, but moderately related (genetically). However, diagnostic ratios of C₂₄ tetracyclic terpane, which was high and moderate and gammacerane, which was low and high, revealed crude oils from Western Niger Delta were derived from predominantly terrestrial source and crude oils from Central Niger Delta were derived from terrestrial source with input from marine organic matter, respectively. Tricyclic terpanes/hopanes and isomerization ratios of C₃₂ homohopanes indicated the Niger Delta crude oils were generated at high maturity, at top of the oil generation window.

Contrasting shale oil accumulation in the upper and lower sweet spots of the lacustrine Permian Lucaogou Formation, Junggar Basin, China

Shale oil enrichment and accumulation in lacustrine strata is rather heterogeneous (unlike that in marine strata), which is a challenging issue to study. Here we carried out a case study in the Permian Lucaogou Formation in the Jimusar Sag, Junggar Basin, northwestern China. Based on data from drill cores, thin sections, rock extracts, and crude oils (including well logging, petrophysics, nuclear magnetic resonance, organic geochemistry, and oil test), the differences of lithology, reservoir physical property, oil generation potential, shale oil content, and physical property and geochemistry of oil between the lower and upper sweet spots were comprehensively compared. Results show that a mixed sedimentary system comprising interbedded carbonate, siltstone, and mudstone was developed owing to terrigenous clastic sedimentation, volcanism, and carbonate deposition. The lower sweet spot has a relatively higher content of silt compared with the upper sweet spot. Due to spatial changes in the depositional environment, only the lower sweet spot occurs at the northeastern margin of the study area and only the upper sweet spot occurs at its southeastern margin, but both occur in the central part of the study area. The porosity and permeability of the sweet spots are highly heterogeneous, due to the complex sedimentary–diagenetic processes, and dissolution pores are common in the lower sweet spot. The hydrocarbon generation potential and shale oil content of the sweet spots are both excellent. Comparatively, the shale oil in the lower sweet spot has higher densities and lower wax contents than those in the upper sweet spot. Thus, the shale oil is more mobile in the upper sweet spot. This implies a high-salinity depositional environment for the lower sweet spot and the oils are generated from salt-tolerant planktonic algae. The oil saturation index (OSI) values are not entirely consistent with the test production results. This indicates that the shale oil productivity is comprehensively controlled by multiple factors, e.g., the hydrocarbon generation potential, reservoir physical properties, and shale oil mobility. These are key features that distinguish lacustrine from marine shale oil systems. The exploration and exploitation strategies of shale oil in lacustrine systems need to be carefully developed.

Geochemistry of oils and condensates from the lower Eagle Ford formation, South Texas. Part 3: Basin modeling

Maturity-dependent bulk properties and molecular compositions of oils and condensates produced from the lower Eagle Ford shales exhibit two distinct regional trends with production depth. Samples west of 98.6 West longitude form a trend that is offset upwardly by ∼2000 ft compared to samples near the Karnes Trough area. This offset is unlikely due to variations in source facies or regional heat flow. To test whether the offset is the result of different amounts of uplift and overburden removal, a psuedo 3D basin model was constructed for the Eagle Ford Formation using standard geologic methods and rock-calibrated 1D burial histories. Present-day thermal maturity was found to correlate with reconstructed maximum burial depth (MBD). When maturity-dependent geochemical parameters are plotted versus MBD, the trends show significantly greater fidelity than when plotted versus true vertical depth; however, the regional offsets are still evident, suggesting that the basin model could be refined. Petroleum samples can be used to calibrate basin models provided they reflect the current maturity of their source. This criterium may be met by unconventional fluids provided the producing strata is charged with the latest generated hydrocarbons from very limited, localized fetch area – conditions believed to be present in the lower Eagle Ford. API gravity from initial production, the only oil property reported for all wells, generally correlates with molecular maturity parameters but can be influenced by other processes. To compensate for these extraneous influences, trends of API gravity versus TVD were plotted for 0.2° longitudinal segments across the Eagle Ford play and used to model the relative amount of uplift and erosion needed to yield oil with the same API gravity and by inference the same maturity. Calculated MDB's from the API gravity oil-based model were found to agree well with those determined by the rock-based basin model and yielded more coherent depth trends with the measured maturity parameters. Both the rock-based and oil-based models find that the amount of Neogene uplift and overburden removal to be no more than ∼500 ft in the area near the San Marcos Arch and increases to the west, reaching ∼6500 ft in Maverick County. This finding strongly supports, if not proves, Cander's (2013) model for petroleum retention/production in the Eagle Ford shales and that the produced petroleum is a near-instantaneous, rather than a cumulative charge, of the latest generated hydrocarbons. This implies that unconventional continuous source petroleum systems are suitable for oil-based calibration of basin models. In many ways, the Eagle Ford petroleum system is ideal in its simplicity for the application of type of calibration.

Geochemistry of Oils and Condensates from the Bovanenkovo and East-Bovanenkovo Fields

Geochemistry of Oils and Condensates from the Bovanenkovo and East-Bovanenkovo Fields

Geochemistry of Oils and Condensates from the Bovanenkovo and East-Bovanenkovo Fields

Geochemistry of Oils and Condensates from the Bovanenkovo and East-Bovanenkovo Fields

Reservoir oil geochemistry in the northern Western Desert of Egypt – High-resolution mass spectrometry and stable carbon isotope characterization

Fourier transform-ion cyclotron resonance-mass spectrometry (FT-ICR-MS) with negative ion electrospray ionization (ESI-N) and positive ion atmospheric pressure photoionization (APPI-P), and compound-specific carbon isotope measurements together with conventional biomarker analyses were applied on 13 crude oil samples from Cretaceous reservoirs in the Shushan, Dahab/Mireir, and Abu Gharadig basins of the northern Western Desert of Egypt to identify their origin, maturity, alteration level, and petroleum relationships. Five oil families were identified, and the FT-ICR-MS data enabled a differentiation between crude oils with terrigenous, marine, and mixed organic matter input based on polar compounds. The dominance of acidic (ESI-N) and low-polarity (APPI-P) oxygen-containing compounds in the Shushan oils reflects land plant material input and oxic depositional conditions for their source rocks. The abundance of oxygen-containing compounds gradually decreases in the NE-Abu Gharadig and Dahab/Mireir oils (source rocks: mixed Type III/II organic matter (OM)) to reach minimum values in the marine-dominated Abu Gharadig oils. Based on compound-specific carbon isotopes and hydrocarbon biomarkers, the Shushan Basin hosts two different oil families from source rocks with Type III OM that likely reveal different thermal maturities and ages. The detected APPI-P aromatic hydrocarbons together with other molecular maturity ratios suggest a higher thermal maturity for the Shushan family A and Abu Gharadig oils than for oils of Shushan family B and from the Dahab/Mireir Basins, respectively.