Peak Oil Window Research Articles

Geochemical Characteristics of Oils from the Orenburg Field in the SE Volga‐Ural Basin, Russia: Implications for the Molecular Structure of a Marine Type II Kerogen

ABSTRACTSix oil samples from an Upper Devonian carbonate reservoir in the Orenburg field in the SE Volga‐Ural Basin (Russia) were analyzed geochemically, together with extracts of five core samples of the Domanik Formation source rock (Frasnian‐Tournaisian) from a well located in the south of the basin. Biomarker analyses of saturated and aromatic oil fractions were combined with new data on the molecular structure of asphaltene in order to investigate source rock organic matter input, depositional environment, and thermal maturity. The studied oil samples have high API values (31°–37°) and saturated hydrocarbon contents up to 66%, suggesting that they were generated by a thermally mature source rock and consistent with high contents of С6–С14 n‐alkanes relative to C15+ of the oil‐asphaltene fraction. The molecular structure of asphaltene derived from pyrolysis‐gas chromatograpy‐mass spectrometry (Py‐GC‐Ms) analyses also suggests that the oils were generated by a source rock containing marine Type II kerogen, consistent with the H/C atomic ratio up to 1.25. Bulk kinetic analyses of the asphaltene showed a relatively broad range of activation energies between 40 and 58 kcal/mol and a frequency factor (A) of 12E+14/1 s. The biomarker characteristics of aliphatic and aromatic fractions in the studied oils suggest that they were generated by carbonate‐rich source rocks containing organic matter of marine algal origin deposited under anoxic conditions. Furthermore, maturity‐sensitive biomarker parameters show that the oils were generated at peak oil window maturities. Oil‐source rock correlations of biomarker proxies indicated that the analyzed oils from the Orenburg field were mainly generated by carbonate‐rich shaley source rocks in the Domanik Formation.

Organic geochemical characterization and hydrocarbon generation modeling of Paleozoic-Paleogene shales, Wadi Sirhan basin, south-eastern Jordan

The Wadi Sirhan Basin in Jordan originated from the Arabian Platform and served as a stable shelf during the Paleozoic era. The Lower Paleozoic-Eocene sequence in the Wadi Sirhan Basin contains numerous shales, found, in ascending order the Upper Ordovician Dubeidib, Lower Silurian Mudawwara, Maastrichtian Ghareb, Paleocene Taqiyeh, and Eocene Sara fms. These strata warrant investigation of their source-rock potential and hydrocarbon generation modeling, to precisely elucidate the timing of petroleum generation. To achieve this, datasets were utilized from various analytical approaches, including Rock-Eval pyrolysis, visual kerogen analysis, pyrolysis-GC, and lipid biomarker geochemistry. The aim of this study is to assess these source rocks regarding organic matter quantity and quality, paleoenvironmental implications, thermal maturity, and petroleum generation depth/time. The Lower Paleozoic Dubeidib and Mudawwara shales are identified as effective source rocks, containing kerogen types II, II-III, and III. A high proportion of well-preserved, weakly fluorescent amorphous organic matter suggests an origin from marine plankton-derived alginite in an oxygen-deficient setting. These formations reached the peak oil window during the Devonian (∼405-380 Ma) and Carboniferous (∼320-300 Ma). The Dubeidib Fm experienced late-stage oil generation during the Early Triassic (∼255-250 Ma), with a transformation ratio (TR) of 68%. The Ghareb Fm predominantly contains type II kerogen, while the Taqiyeh and Sara fms mainly contain type I kerogen with minor type II kerogen. Thermal maturity assessments using integrated parameters indicate that the Dubeidib and Mudawwara shales have entered the main phase of hydrocarbon generation, while the Ghareb, Taqiyeh, and Sara shales remain immature. Furthermore, analysis of biomarker ratios reveals the dominance of marine over terrestrial organic matter in the studied strata. These clay-rich sediments were deposited under reducing conditions, which further facilitated the rearrangement of steranes into diasteranes. The modeled TRs indicate the generation and subsequent expulsion of hydrocarbons, but the absence of suitable reservoirs and/or improper trapping system, owing to the major Hercynian unconformity, led to an incomplete petroleum system in the basin. Additional investigation is required to evaluate the potential of the Early Paleozoic shales as subsurface unconventional resources, considering parameters such as brittleness index and hydraulic fracturing. This study holds important implications for future hydrocarbon exploration and development in the Wadi Sirhan Basin. The insights gained from such investigations could help mitigate the risk of petroleum exploration failures in the Wadi Sirhan Basin, guiding future exploration and development efforts towards promising approaches.

Source Rock Assessment of the Permian to Jurassic Strata in the Northern Highlands, Northwestern Jordan: Insights from Organic Geochemistry and 1D Basin Modeling

The present study focused on the Permian to Jurassic sequence in the Northern Highlands area, NW Jordan. The Permian to Jurassic sequence in this area is thick and deeply buried, consisting mainly of carbonate intercalated with clastic shale. This study integrated various datasets, including total organic carbon (TOC, wt%), Rock-Eval pyrolysis, visual kerogen examination, gross composition, lipid biomarkers, vitrinite reflectance (VRo%), and bottom-hole temperature measurements. The main aim was to investigate the source rock characteristics of these strata regarding organic richness, kerogen type, depositional setting, thermal maturity, and hydrocarbon generation timing. The Permian strata are poor to fair source rocks, primarily containing kerogen type (KT) III. They are immature in the AJ-1 well and over-mature in the NH-2 well. The Upper Triassic strata are poor source rocks in the NH-1 well and fair to marginally good source rocks in the NH-2 well, containing highly mature terrestrial KT III. These strata are immature to early mature in the AJ-1 well and at the peak oil window stage in the NH-2 well. The Jurassic strata are poor source rocks, dominated by KT III and KT II-III. They are immature to early mature in the AJ-1 well and have reached the oil window in the NH-2 well. Biomarker-related ratios indicate that the Upper Triassic oils and Jurassic samples are source rocks that received mainly terrestrial organic input accumulated in shallow marine environments under highly reducing conditions. These strata are composed mostly of clay-rich lithologies with evidence of deposition in hypersaline and/or stratified water columns. 1D basin models revealed that the Upper Triassic strata reached the peak oil window from the Early Cretaceous (~80 Ma) to the present day in the NH-1 well and from ~130 Ma (Early Cretaceous) to ~90 Ma (Late Cretaceous) in the NH-2 well, with the late stage of hydrocarbon generation continuing from ~90 Ma to the present time. The present-day transformation ratio equals 77% in the Upper Triassic source rocks, suggesting that these rocks have expelled substantial volumes of hydrocarbons in the NH-2 well. To achieve future successful hydrocarbon discoveries in NW Jordan, accurate seismic studies and further geochemical analyses are recommended to precisely define the migration pathways.

Investigating the hydrocarbon potential of the Paleogene coal seams in Kapuni field, Taranaki basin, New Zealand: Implications for coal-oil correlation

Hydrocarbon generation in Taranaki Basin, New Zealand, has been proven in several source rocks within the syn- and post-rift basin-fill sedimentary successions. These source rocks are mainly hosted in the marginal and deep marine Upper Cretaceous shales, which generate marine and terrigenous oils. Some of the terrigenous oils could have been linked to the Paleogene coals; however, the capability of these coals to generate and expel liquid hydrocarbons is poorly-investigated. In this study, we present organic geochemistry, kerogen petrography, wireline logging, and basin modelling to evaluate the hydrocarbon generation potential of the Paleogene coals and coal-rich facies of the Kapuni Group sediments in Kapuni Field, Taranaki Basin. A compositional correlation between oil in the Kapuni Group reservoirs and coal extracts was performed to decipher the oil origin and define its parent source rock. Kapuni oils display high pristane/phytane (Pr/Ph) > 5, low dibenzothiophene (DBT)/phenanthrene <0.1 and high relative abundance of C29 regular steranes >60%, typifying their generation from a terrigenous source rock deposited in an oxic, fluvio-deltaic environment. Similar values were also observed in the muddy coal extracts of Farewell Formation, thereby reflecting a positive coal-oil correlation. The maturity-relevant biomarkers (Ts/Tm trisnorhopanes; C29 steranes isomers, and 22S-, 22R C32 homohopanes) are similar in both oils and Farewell coal extracts confirming oil expulsion from Farewell coals during the peak oil window maturity. These results demonstrate the generation and expulsion of coal-oil, thereby shedding light on the prospectively of the Paleogene plays in the Taranaki Basin.

Organic petrography and geochemistry of the Fu 2 member of the Paleocene Funing formation, Gaoyou Depression, Subei Basin, Eastern China: Implications for shale oil potential

The Fu 2 Member of the Paleocene Funing Formation in the Gaoyou Depression, Subei Basin is an organic matter-rich formation, and has a high potential for shale oil exploration and exploitation. Total organic carbon (TOC), organic petrography, Rock-Eval pyrolysis, chloroform bitumen “A” extraction, and SARA (saturates/aromatics/resins/asphaltenes) composition analyses of shale samples from one drill core in the studied area spanning a thickness of 257 m were conducted to study the organic matter (OM) richness, kerogen type, maceral composition, hydrocarbon generation potential, and oil content of the Fu 2 Member. Results show that the Fu 2 Member shales in the study area have a Ro of 0.87%, in the peak oil window, suggesting a high potential for hydrocarbon generation. The studied OM in shales mainly belongs to kerogen Type II, with a minor portion of Type I and Type III. Under microscopic observation, macerals in the studied shales are mainly composed of vitrinite, inertinite, alginite, and solid bitumen. The studied shales have an average TOC content of 1.41 wt%, indicating good petroleum potential. The variations of maceral compositions could affect the reliability when the Tmax is used as an indicator of thermal maturity. The lower Shale 4 and upper Shale 5 interval (3650–3700 m), with high TOC and high oil saturation index, is identified as the sweet-spot interval of the Fu 2 Member for shale oil exploration.

Maceral evolution of lacustrine shale and its effects on the development of organic pores during low mature to high mature stage: A case study from the Qingshankou Formation in northern Songliao Basin, northeast China

Organic matter (OM) hosted pores are crucial for the storage and migration of petroleum in shale reservoirs. Thermal maturity and macerals type are important factors controlling the development of pores therein. In this study, six lacustrine shale samples with different thermal maturities from the first member of the Qingshankou Formation in the Songliao Basin, of which vitrinite reflectance (Ro) ranging from 0.58% to 1.43%, were selected for a comparative analysis. Scanning electron microscopy (SEM) and reflected light microscopy were combined to investigate the development of organic pores in different macerals during thermal maturation. The results show that alginite and liptodetrinite are the dominant primary macerals, followed by bituminite. Only a few primary organic pores developed in the alginite at the lowest maturity (Ro = 0.58%). As a result of petroleum generation, oil-prone macerals began to transform to initial-oil solid bitumen at the early oil window (Ro = 0.73%) and shrinkage cracks were observed. Initial-oil solid bitumen cracked to oil, gas and post-oil bitumen by primary cracking (Ro = 0.98%). Moreover, solid bitumen (SB) was found to be the dominant OM when Ro > 0.98%, which indicates that SB is the product of oil-prone macerals transformation. Many secondary bubble pores were observed on SB, which formed by gas release, while devolatilization cracks developed on migrated SB. Additionally, at the late oil window (Ro = 1.16%), migrated SB filled the interparticle pore spaces. With further increase in temperature, the liquid oil underwent secondary cracking into pyrobitumen and gas, and spongy pores developed on the pyrobitumen at higher levels of maturity (Ro = 1.43%), which formed when pyrobitumen cracked into gas. Vitrinite and inertinite are stable without any visible pores over the range of maturities, verifying their low petroleum generation potential. In addition, it was concluded that clay minerals could have a catalytic effect on the petroleum generation, which may explain why organic-clay mixtures had more abundant pores than single OM particles. However, after Ro > 0.98%, authigenic minerals occupied the organic pore spaces on the organic-clay mixtures, resulting in fewer pores compared to those observed in samples at the early to peak oil window.

ORIGIN OF OIL IN UPPER PERMIAN (ZECHSTEIN) CARBONATE RESERVOIR ROCKS AT THE JARVIS STRUCTURE UNDERLYING THE ETTRICK FIELD, OUTER MORAY FIRTH, UK NORTH SEA

Oil in the Jarvis structure underlying the main Upper Jurassic reservoir at the Ettrick oilfield (Outer Moray Firth, UK northern North Sea) is present in Upper Permian (Zechstein) carbonates. The origin of this “Jarvis oil” is investigated in this paper using a multidisciplinary approach based on data from well‐logs and cores from wells 20/02‐2 and 20/02‐3. Reservoirs at the Jarvis structure consist of carbonates in the upper part of the Halibut Carbonate Formation (Ca2) and in the Carbonate Member of the Turbot Anhydrite Formation (Ca3). These carbonates are typical Zechstein dolomites composed of a range of facies from mudpackstones with storm beds deposited at moderate water depths to shoreface bioclastic‐oolitic packstones to shallow‐subtidal and intertidal microbial laminites. Interbedded anhydrites replace sabkha and lagoonal selenitic gypsum. Several shallowing‐upward units are recognised. Molecular analysis of the Jarvis oil, and comparisons with biomarker and other geochemical data from extracts of Zechstein cores and published data from different source rocks from the North Sea area, suggest that the oil was generated by marine, OM‐rich shales in the Upper Jurassic Kimmeridge Clay Formation. The oil was generated at peak oil window maturity and is characterised by high Pr/Ph, BNH/H and DBT/P ratios, and abundant C28 steranes and C28+29 monoaromatic and C26R + C27S triaromatic steroids. The molecular composition of organic material in extracts of core samples of Zechstein carbonates from wells in the Jarvis structure differs significantly from that of the Jarvis oil. Biomarkers such as BNH are absent in the core extracts, and there are different distributions and abundances of saturated and aromatic hydrocarbons, likely controlled by thermal maturity.

Thermal maturity of crude oils in the Baiyun sag, Pearl River Mouth basin, South China Sea: Insights from biomarkers，aromatic hydrocarbon and adamantane compounds

The Baiyun Sag in the Pearl River Mouth Basin is a hydrocarbon-rich depression in which oil and natural gas fields coexist. The complex characteristics of oil and condensate in the sag have been long-term issues, and one of the questions is the formation stage of black oil, volatile oil and gas condensate in the sag. In this study, to accurately estimate the thermal maturity of oil in the Baiyun Sag, maturity parameters derived from normal alkanes, terpanes, steranes and aromatic hydrocarbons were systematically investigated. In addition, adamantane parameters were used to verify both the oil and condensate maturity. The results show that the saturated hydrocarbon biomarker parameters are not suitable for providing a complete understanding of the oil maturity in the Baiyun Sag. A qualitative evaluation method for various maturity stages of oil was proposed based on the methylphenanthrene distribution fractions, phenyldibenzothiophene maturity parameters, and diamantane concentration. Subsequently, the maturity was quantitatively evaluated using empirical equations based on methyl diamantine. The equations were selected by comparing the calculated equivalent reflectance (Rc) with the qualitatively determined maturity stage of the crude oil. Finally, the calculated vitrinite reflectance values indicated an overestimation of the maturity of light oils and condensate oils, which were thought to be produced in the late oil window (Ro: 1.0%∼1.3%) to wet gas stage (Ro: >1.3%). The new results indicate that the black oils with Rc values ranging between 0.72% and 1.05% was generated during the peak oil window. The Rc values of gas condensates in the eastern and northeastern structural belts range from 1.20% to 1.24%, suggesting that they are products of the late oil window. The maturity levels of gas condensates in the Panyu Low Uplift are the highest (Rc: 1.14%–1.46%) in the sag. They were produced in the late oil to wet gas stages. The oil maturity characteristics confirm the oil exploration potentials of the eastern and northeastern structural belts of the Baiyun Sag.

Preliminary study of crude oils from Shabwah depression in the Central Sab'atayn Basin (Yemen): Revealing oil-oil correlation with organic matter input and maturity based on geochemical properties of maltene and asphaltene fractions

This study was investigated eleven crude oil samples from representing Jurassic reservoir sandstones from the Al–Uqlah Oilfield in the Shabwah depression, using physical and geochemical aspects for saturated, aromatic, and asphaltene fractions to gain information about their source rock characteristics, particularly the conditions of depositional environment, thermal maturity and organic matter (OM) character. The overall results show that the examined oils have API gravity values between 38° and 43°, indicating that most crude oils are light and not biodegradable; nevertheless, oil samples, sweet oils with a low sulfur content, with S of <1 wt%. The molecular structure of the asphaltene in these oils derived from Py–GC suggests mainly paraffinic oil exhibiting high to low wax content derived from Types I and II kerogens. This claim agrees with the high saturated HC of more than 38% and significant levels of aromatic HC and polar components. The studied oil were generated from clay-rich source rocks, containing a mixed OM origin of marine and terrestrial organic matter and deposited under sub-oxic depositional environmental conditions as indicated by their biomarker of the saturated and aromatic fractions. The Py–GC structure of the asphaltene together with the environment-related biomarker indicators reveals the existence of two oil families. The first oil family represented in the majority of the studied oils and characterised as waxy paraffinic oil and generated from a mixture of organic matter, with significant terrestrial land plant input and deposited in sub-oxic environmental conditions. Other oil samples belonged the second oil family; these samples are predominantly P–N-A oils with low wax content and were derived from marine-source rock, containing significant contributions from aquatic OM and little input from terrestrial OM and deposited under more reducing environmental conditions. The biomarker and non-biomarker maturity ratios indicate that thermally mature source rocks generated the investigated crude oils of both oil families, corresponding to the peak oil window.

Effect of Petroleum Generation and Retention on Nanopore Structure Change in Laminated and Massive Shales-Insights from Hydrous Pyrolysis of Lacustrine Source Rocks from the Permian Lucaogou Formation.

The lacustrine shale of the Middle Permian Lucaogou Formation in the Jimusar Sag is the principal prospective unconventional target in the Junggar Basin. The effect of petroleum generation and retention on nanopore structure change during thermal maturity in lacustrine shale is still unclear. In this study, two laminated and two massive shale samples from the Permian Lucaogou Formation were selected to study this change by closed hydrous pyrolysis. The pyrolysis temperatures were 295, 320, 345, 370, and 400 °C, which cover from the mature to the post-mature stage. Total organic carbon (TOC), Rock-Eval, and low-pressure N2 adsorption tests on pyrolyzed shale samples before and after extractable organic matter (EOM) extraction were conducted systematically. The results indicate that (1) the petroleum generation on nanopore structure change is in stages. The peak nanopore volume expanding stage is the late oil window (R o = 0.9-1.35%). At the post-mature stage (R o > 1.35%), the mesopore volume decreased and the majority of the nanopore space is from macropores. (2) The presence of EOM decreased both mesopores and macropores in the peak oil window. (3) The organic-rich laminated shale generated more macropores than massive shale with increasing thermal maturity. The results of this study shed light on the dynamic effect of laminae fabric, petroleum generation, and retention on shale nanopore structure change across the oil window.

Api gravities and geochemical evaluation of crude oils from sapele, niger – delta, nigeria

The investigation is to provide information on source organic matter input, depositional conditions and the correlation between crude oils recovered from Sapele oilfield in the Niger Delta. A suite of twenty-five crude oils from the Agbada reservoirs (synsedimentary) of the Tertiary Niger Delta (Southern Nigeria) were analysed based on API gravities and geochemically compared with extracts from source rock of the Akata and Agbada Formations. The Sapele shallow reservoirs occur between the depths of 4000ft and 6000ft, containing heavy crudes with API gravities 20 – 22 degrees. The deep reservoirs lie within 7000ft and 12000ft accumulating the light crudes with API gravities of 24.70-35.60 degrees, and viscocity of 1.64cP. The investigated biomarkers indicated that the Sapele oils were derived from mixed marine and terrigenous organic matter and deposited under suboxic conditions. This has been achieved from normal alkane and acyclic isoprenoids distributions, terpane and sterane biomarkers. These oils were also generated from source rock with a wide range of thermal maturity and ranging from early-mature to peak oil window. Based on molecular indicators of organic source input and depositional environment diagnostic biomarkers, one petroleum system operates in the Niger Delta Region; as observed on the source rocks from the Agbada organic – rich shale sediments. Therefore, the hydrocarbon exploration processes should be concentrating on the Akata and Agbada area of the Tertiary strata for determining the source kitchen.

Oil biomarker signature and hydrocarbon prospectivity of Paleozoic versus Mesozoic source rocks in the Faghur–Sallum basins, Egypt's Western Desert

Exploration campaigns focusing on Paleozoic plays in the Egyptian north Western Desert Sallum and Faghur basins have been limited to date, and little has been done to investigate their hydrocarbon generation potential. A total of 284 shale, calcareous shale, coaly shale and siltstone side-wall core and cuttings samples, covering the rock succession that ranges from the Silurian Kohla Formation to the Turonian Abu Roash Formation were analyzed for source rock potential. In addition, eight reservoired Paleozoic–Mesozoic oil samples were geochemically analyzed. This paper systematically investigates (1) organic enrichment, hydrocarbon generation potential, and thermal maturity of Mesozoic as well as possible Paleozoic source rocks, and (2) composition and biomarker characteristics of crude oil samples in the study area from the far north Western Desert basins of Egypt.The Silurian Kohla and Basur and the Carboniferous Desouqy and Dhiffah siltstone and shale rock samples show overall poor and fair to good source rock potential for the Lower and Upper Cretaceous rock units, respectively. In contrast, high TOC (up to 4.83 wt%) and Rock-Eval S2 (up to 6.57 mg HC/g rock) for the Devonian Zeitoun Formation samples indicates fair to very good source potential. The Middle Jurassic Khatatba Formation samples, compared with the Devonian Zeitoun Formation or other rock units in the stratigraphic column of the study area, have the highest TOC (30.1 wt%) and the highest S2 (26.9 mg HC/g rock), indicating fair to excellent source rock potential. These high values of the Khatatba Formation are locally related to organic-rich coaly shales and calcareous shale intervals. The Rock-Eval results indicate an overall dominance of Type-III kerogen with strongly varying OI values. This highly gas-prone character for most samples was confirmed petrographically by abundant vitrinite phytoclasts and recycled organic matter. Coals and coaly shale facies from the Alam El Bueib and Khatatba formations that contain liptinitic materials may represent Type-III kerogens that are capable of generating gas with minor oil. Based on Rock-Eval Tmax and HI results, the Zeitoun and Khatatba samples range from early to peak oil window. This is consistent with the Ro measurements of the Paleozoic Zeitoun samples (0.65–1.02%) and the Middle Jurassic Khatatba samples (0.59–1.01%).The Faghur oils are light (35°–46° API gravity), belong to a single genetic family and are non-biodegraded based on wide-ranging n-alkanes. Abundant tricyclic diterpanes, C24 tetracyclic terpane, C27 Ts trisnorneohopane, diahopane, cyclohexanes, C29 steranes and rearranged steranes and low to very low gammacerane and extended hopanes are common molecular signatures of the analyzed light oil and condensate samples. These findings indicate a relatively oxic fluvio-deltaic environment for the corresponding clay-rich coaly shale and calcareous shale source rocks that contain predominantly higher land-plants with negligible algal/bacterial organic materials. Based on saturated- and aromatic-maturity parameters, the analyzed oils were inherited from peak–late mature source rock.

Conventional and unconventional petroleum potentials of the Late Jurassic Madbi organic-rich shales from the Sunah oilfield in the Say’un–Masilah Basin, Eastern Yemen

This study aims to carry out the detailed geochemical characterization of the Madbi organic-rich shale intervals from structural heights in the Sunah oilfield, Say’un–Masilah Basin. The geochemical and basin model results of the source rock reveal that the Madbi Formation in the Sunah oilfield have both conventional and unconventional oil resource potential, and can laterally and vertically change from one well site to another due to varying burial temperature distributions with increasing depth. The Madbi source rock from structural heights of the oilfield is characterized by high organic content, with total organic matter (TOC) values of up to 12 wt%, and reached the low mature stage of the oil generation window. These characteristics make them a potential yet unconventional oil resource candidate, resulting in the retention of more oil that could be released upon application of similarly unconventional techniques. The conventional petroleum system of the Madbi Formation in the deeper portions in the Sunah oilfield was identified based on the match between source, reservoir and seal rocks, and timing of generation, migration, trap formation, and preservation. This Madbi source rock set reached relatively high maturity in the peak-oil window, with ratios of approximately 10–50% of the kerogen converted to large amounts of oil since the late Eocene-early Oligocene. To date, the conversion ratios of kerogen have reached their highest values of more than 50%, generating significant amounts of oil and leading to high pressures and subsequent oil expulsion, which reached the trapping site via vertical migration paths through the faults.

Phase fractionation and oil mixing as contributors to complex petroleum phase in deep strata: A case study from LG7 block in the Tarim Basin, China

Integrated geochemical analysis was conducted on oil and gas samples from the LG7 block, Tarim Basin, China, to investigate the causal mechanisms for the complex petroleum phase. Consistency in biomarker derived parameters suggest that heavy oil, black oil, and condensate, though vary in physical properties and phase state, share a genetic affinity and are all mature oil generated at peak oil window. However, mass loss and double-peaks pattern in n-paraffins of black oil and heavy oil, and much higher maturity of gas and some oil fractions (diamondoids) jointly suggest the oil samples in the study site have suffered secondary alteration process including phase fractionation and mixing. In combination with tectonic evolution analysis, the study site experienced severe uplift after primary oil accumulation and thus formed biodegraded heavy oil in local highs. Since Neogene, the introduction of oil-cracking gas from deeper strata charged early oil accumulations and caused phase fractionation, during which primary oil was fractionated into vaporized light oil and heavy oil residue. Vaporized light oil continued to migrate towards higher positions and were readily to either mix with other oil residue and heavy oil, or to be trapped to form secondary condensate in favorable reservoirs. Thus, the complex disordered distribution of heavy oil, black oil, and condensate is observed within a relatively small area. Our reconstruction of the petroleum accumulation and alteration process speculates future exploration endeavors to potential oil-cracking gas/condensate accumulations in the study area.

Genesis and preservation of the giant ultradeep Hadexun petroleum accumulation in the Tarim Basin, China

Reservoired liquid petroleum has limited potential to be preserved under high temperature conditions due to thermal cracking and potentially thermochemical sulfate reduction, and thus exploration targets in ultradeep strata are mainly gas and condensate gas. However, a giant ultradeep liquid petroleum accumulation, with an average depth of >6500 m, was discovered recently in the Hadexun area, Tarim Basin. In this study, integrated geochemical analyses were conducted on the black oil samples from the Hadexun area. Intact terpanes and steranes and low concentration of diamondoids were detected, indicating that these oils were generated at peak oil window and were barely altered by secondary geochemical process (thermal cracking or others) despite their depth. The associated wet gas with light isotopic profiles was classified as mature oil-derived gas co-generated with the oil. Petroleum accumulation analyses suggested that the favorable carbonate reservoir bodies in the Middle Ordovician Yijianfang Formation were attributed to karstification and weathering, and mainly distributed along the major strike-slip fault belts. Together with the thick mudstones in the overlying Upper Ordovician Sangtamu Formation, they formed a favorable reservoir-seal assemblage in the Hadexun area. Massive volumes of liquid petroleum were generated and expelled from the Lower Cambrian black shales in the Late Hercynian and migrated into the Ordovician carbonate reservoirs through the strike-slip fault system, and subsequently were exposed to stable tectonic conditions. Due to the rapid subsidence since the Neogene, insufficient temperature-time exposure eliminated the impact of thermal cracking; therefore, the petroleum accumulation was preserved in the liquid phase, and further indicates that huge petroleum resource potential remains in ultradeep strata in the Tarim Basin. • Oil/gas sourced from the Cambrian shales were barely altered by geochemical process. • Insufficient compensation of temperature and time led to the preservation of the ultradeep oil. • Oil/gas was preferentially enriched in favorable carbonate reservoir bodies along faults. • Liquid petroleum and condensate/gas are the main targets in Ordovician and Cambrian assemblages, respectively.

SEVERE BIODEGRADATION OF CRUDE OILS FROM THE QUIRIQUIRE FIELD, EASTERN VENEZUELAN BASIN

Five crude oil samples from the Quiriquire field (Maturin sub‐basin, Eastern Venezuelan Basin) were analysed to evaluate their levels of biodegradation. The oils were obtained from coarse sandstones and conglomerates of the Pliocene Quiriquire Formation at depths &lt;1000 m. Analyses of the samples’ bulk physicochemical parameters indicate variations in API gravity and in the content of saturated hydrocarbons and NSO+asphaltenes, and also in the saturate/aromatic ratio which increases in more biodegraded oils. n‐Alkane distributions are characterized by a dominant unresolved complex mixture (UCM) or hump under an envelope of peaks which lack the acyclic isoprenoids pristane and phytane. The alteration of steranes and terpanes together with the presence of 25‐norhopanes and 17‐nor‐tricyclic terpanes, and the alteration of low molecular‐weight (C20‐C21) triaromatic steroids, phenanthrene, methyl‐phenanthrene, dibenzothiophene and methyl‐dibenzothiophene, indicate that the oils have undergone severe biodegradation.The oils contain compounds with different susceptibilities to biodegradation which is probably a consequence of the mixing of different oil charges in the Quiriquire Formation reservoir. The oils were derived from underlying source rocks in the Upper Cretaceous Guayuta Group (Querecual and San Antonio Formations), and migration into the shallow reservoir at Quiriquire field likely occurred continuously through time. Although the oils have undergone severe biodegradation, it was possible to make some inferences about their origin. Thus, the analyzed oils are interpreted to have originated from marine shale or marl source rocks containing mixed organic matter deposited under anoxic‐suboxic conditions and were generated at near peak oil window maturities.

Molecular fossils within bitumens and kerogens from the\u2009~\u20091\xa0Ga Lakhanda Lagerst\xe4tte (Siberia, Russia) and their significance for understanding early eukaryote evolution

The emergence and diversification of eukaryotes during the Proterozoic is one of the most fundamental evolutionary developments in Earth’s history. The ca. 1-billion-year-old Lakhanda Lagerstätte (Siberia, Russia) contains a wealth of eukaryotic body fossils and offers an important glimpse into their ecosystem. Seeking to complement the paleontological record of this remarkable lagerstätte, we here explored information encoded within sedimentary organic matter (total organic carbon = 0.01–1.27 wt.%). Major emphasis was placed on sedimentary hydrocarbons preserved within bitumens and kerogens, including molecular fossils (or organic biomarkers) that are specific to bacteria and eukaryotes (i.e. hopanes and regular steranes, respectively). Programmed pyrolysis and molecular organic geochemistry suggest that the organic matter in the analyzed samples is about peak oil window maturity and thus sufficiently well preserved for detailed molecular fossil studies that include hopanes and steranes. Together with petrographic evidence as well as compositional similarities of the bitumens and corresponding kerogens, the consistency of different independent maturity parameters establishes that sedimentary hydrocarbons are indigenous and syngenetic to the host rock. The possible presence of trace amounts of hopanes and absence of steranes in samples that are sufficiently well preserved to retain both types of compounds evidences an environment dominated by anaerobic bacteria with no or very little inputs by eukaryotes. In concert with the paleontological record of the Lakhanda Lagerstätte, our study adds to the view that eukaryotes were present but not significant in Mesoproterozoic ecosystems.

Geochemical characteristics and hydrocarbon potential of Cretaceous Upper Shale Unit, Lower Indus Basin, Pakistan

This study focuses on the geochemical investigation of source rock samples from three different wells of upper shale unit (Lower Goru Formation; Lower Indus Basin). Samples were powdered to very fine particle size and extracted soluble organic matter (SOM) was fractionated using column chromatography. The saturated hydrocarbon fraction was further analyzed to evaluate source rock potential and organic matter type. Total organic carbon reflected fair source rock potential. The values of Pr/Ph, Pr/n-C17 vs. Ph/n-C18, C31/C19 show that organic matter is mainly terrestrial and depositional conditions varies from anoxic to the dysoxic. Different maturity parameters including Bit/TOC ratio, carbon preference indices revealed mature organic matter input and peak oil-window for the samples. Furthermore, bitumen transformation ratio indicates increase in thermal maturity with increasing depth. Based on these data, it may be said that the shale unit is probably fair candidate for hydrocarbon generation perspective.

Organic geochemistry of crude oils from Oligocene reservoirs in the Salin sub-basin, Myanmar: Insights into source, maturity, and depositional environment

Fourteen crude oil samples were collected from the South (Yenangyaung: YNG), Central (Chauk: CHK), and North (Letpando: LPDO) oilfields in the Salin sub-basin, Myanmar. This study investigated the organic geochemical characterization of crude oils from early to late Oligocene reservoir rocks. The saturated and aromatic hydrocarbons of selected oil samples were analyzed by integration of gas chromatography and gas chromatography-mass spectrometry methods to evaluate their origin, depositional environment, and thermal maturity. All the oils have moderate to high API gravity, showing medium to light oils. Crude oils were classified into three groups based on their biomarker compositions. The group I oils (Okhmintaung Formation, upper Oligocene, YNG Oil Field) mainly originated from planktons/algal materials with less contribution of terrestrial input, deposited under sub-oxic environments (lacustrine-marine setting). The group II oils (Padaung Formation, middle Oligocene, CHK Oil Field) were significantly generated from planktons/algal sources with minor input from terrestrial materials, deposited in an oxic/sub-oxic environment (fluvial/deltaic-marine setting). Group III oils (Shwezettaw Formation, lower Oligocene, LPDO Oil Field) were derived from a mixed contribution of planktons/algal materials and terrestrial input accumulated under an oxic environment (fluvial/deltaic-marine setting). Group I and Group II oils have reached peak oil window, while Group III oils indicate the early oil window. The results of stable carbon isotopic compositions for all analyzed oil samples indicate that the source rocks were derived from marine algae, and terrestrial and/or freshwater algal materials. Oil-oil correlation suggested that Oil Groups exhibit mixed source characterization during hydrocarbon accumulation processes.

Molecular structure evolution of Type I kerogen during pyrolysis: Case study from the Songliao Basin, NE China

To characterize molecular structure evolution of Type I kerogen, we performed gold tube pyrolysis experiments on a Cretaceous Qingshankou lacustrine mudstone in the Songliao Basin during artificial maturation. The hydrocarbons generated at 320–600 °C at two heating rates, 2 and 20 °C/h were quantified, and the maximum yields of C14+, C6-14 and C2-5 gaseous products corresponded to vitrinite reflectance (Ro) nodes of 1.18%, 1.76% and 2.5%, respectively. Chemical compositions of solid residues (pyrolysis products remaining after extraction by dichloromethane and methanol) with Easy%Ro values ranging from 0.49 to 2.5% were studied by elemental analysis and nuclear magnetic resonance. With increasing temperature, the solid residues presented sharp decreases in aliphatic fractions and significant increases in aromatic fractions, while a condensation reaction occurring in the residue was related to secondary coking and cracking reactions occurring after the peak oil window. Four structural models of the residues were investigated, demonstrating that three positive nonlinear stages occurred between fused aromatic carbon (XE BP) structures and hydrocarbon generation. At Easy%Ro < 0.89, the XE BP numbers were relatively stable, and the generated hydrocarbons mainly attributed to cleavage of heteroatomic functional groups (NSOs) of kerogen. During the peak hydrocarbon-generating stage (Easy%Ro values of 0.89–1.76), the XE BP numbers exhibited an obvious increase due to breaking of carbon chains and cyclization reactions, which was accompanied by formation of large quantities of C14+ oils and C6-14 hydrocarbons derived from direct cracking of kerogen. The XE BP numbers were growth slowing and highly cross-linked features at Easy%Ro values of 1.76–2.5% due to polycondensation, and a large amount of C2-5 gas generation was mainly attributed to oil cracking. A good coupling relationship between H/C atomic ratio and polycondensation of aromatic structures in evolution further strengthens research of molecular structure evolution in Type I kerogen. Moreover, comparison of the number of aromatic structures caused by alkyl bond breakage and condensation showed that the number of the former was higher than that of the latter before the peak of oil generation, whereas the number of the latter was obviously dominant after the peak of oil generation.