Peak Oil Generation Research Articles

Geochemistry and possible origin of crude oils from Bashituo oil field, Tarim Basin

The entire range of hydrocarbons in Bashituo oils from Devonian and Carboniferous reservoirs were investigated to determine their origin, as well as their alteration, mixing, and maturity using gas chromatography, gas chromatography–mass spectrometry, and stable carbon isotope analysis. These geochemical studies indicate that the crude oils in the Devonian and Carboniferous reservoirs share similar C15+ molecular marker compositions of marine organic matter origin, whereas their light hydrocarbon compositions show distinct differences. The Carboniferous-reservoired oils are characterized by a relatively greater abundance of cycloalkanes and methylcyclohexane, which indicate a terrestrial organic matter (OM) contribution. Based on biomarker and carbon isotope analysis, Cambrian–Ordovician (J-O) marine rocks are assumed to be the main source for both the Devonian- and Carboniferous-reservoired oils, whereas Carboniferous rocks with terrestrial OM input also contributed to the Carboniferous-reservoired oils. The coexistence of 25-norhopanes, evident humps from unresolved complex mixture, and intact n-alkanes in Devonian-reservoired oils indicate a mixture of early-charged biodegraded oils with late fresh oils, corresponding to at least two oil-generation episodes by the J-O rocks. Light hydrocarbon indicators suggest a relatively high maturity beyond peak oil generation for the J-O–sourced late fresh oil, whereas C15+ molecular marker parameters indicate a maturity equivalent to early peak oil generation for the J-O–sourced, early-charged biodegraded oil. The maturity of the Carboniferous-sourced oil is equivalent to peak oil generation. The application of the entire range of hydrocarbons is essential when assessing a mixed or altered oil system because light hydrocarbons and biomarkers may yield different source-oil–correlations and maturities.

Black shale xenolith in a Jurassic−Cretaceous kimberlite and organic-rich Upper Ordovician shale on Baffin Island, Canada: A comparison of their organic matter

Abstract Rock-Eval pyrolysis and molecular organic geochemical analyses as well as organic petrographic observations were carried out on a rare black shale xenolith core drilled from a Late Jurassic-Early Cretaceous kimberlite on the Hall Peninsula in southern Baffin Island, Canada. The results are compared with those of outcrop shale samples from the Upper Ordovician Amadjuak Formation, the only organic-rich shale deposit discovered so far in the region. The shale xenolith is found to be organic-rich and thermally mature at the stage of peak oil generation, and contain type II organic matter similar to that of the immature Amadjuak shale. Discounting the differing thermal maturation effect, similar depositional environments and original organic inputs are suggested for both the shale xenolith and the Upper Ordovician shale based on their bulk, molecular and isotopic signatures as well as organic maceral assemblages. The present study cannot exclude the possibility of the shale xenolith being originated from an organic-rich Lower Silurian deposit, as suggested by previous Re Os isotope dating study. It is clear, however, that depending on their areal distribution and thickness, the lithostratigraphic unit from which the organic-rich black shale xenolith is derived would make an excellent petroleum source rock in the study area.

Late Jurassic Arwa Member in south-eastern Al-Jawf sub-basin, NW Sabatayn Basin of Yemen: Geochemistry and basin modeling reveal shale-gas potential

The current study evaluated the source rock characteristics, thickness, and lithology of the Late Jurassic Arwa Member to provide information about both conventional and unconventional resource systems in the Al-Jawf sub-basin. Three exploratory wells in the south-eastern portion of the Al-Jawf sub-basin were used for the source rock geochemistry and basin modeling study.Results from the geochemical and basin modeling indicate that the Arwa Member is a self contained source-reservoir whose shales are considered as gas-prone source rocks, and have generated large amounts of thermogenic gas through secondary cracking of oils at high thermal maturity levels. The geochemical results reveal that the Arwa shales currently contain Type III and IV kerogen in a gas-window maturity stage and are shale-gas resources.The basin models illustrate that the late Jurassic to early Miocene age was the peak-oil generation window of the Arwa shale source rock, with a transformation ratio (TR) of 10–85%. Most of the oil was expelled along micro-fractures caused by the pressure of oil generated within the Arwa shales, which was then trapped in the carbonate reservoir rocks within the Arwa Member itself. The oil retained in the Arwa carbonate rocks was partially and/or completely cracked into gas between the early Miocene and the present-day. This thermogenic gas was generated due to high thermal maturity caused by Tertiary volcanic rocks. Assuming a thickness of 360–1590 m and partial and/or complete cracking of retained oil to gas, the Arwa Shale Member could have a huge gas-generation potential.

Ahdeb oil field, Mesopotamian Basin, Iraq: Reservoir architecture and oil charge history

The Ahdeb oil field is located in the Mesopotamian Basin of central Iraq within a northwest–southeast-trending anticline. Seven oil-bearing layers exist in the eastern area in the field, but there is only one oil-bearing layer in the western area. This study reveals that the reservoir filling process resulted from the difference in the elements in the petroleum system, the oil generation and migration process, and the formation of the structural trap. Most oils in the field, with pristane/phytane < 1 and a high relative abundance of hopanes exceeding C30, were generated from the Upper Jurassic–Lower Cretaceous Chia Gara Formation, whereas some oils were generated from the Lower Cretaceous Ratawi and Zubair Formations. The mid-Upper Cretaceous reservoirs in the field are composed of lime grainstones, packstones, and wackestones. The main oil accumulation occurred during the Maastrichtian, coinciding with peak oil generation from the Chia Gara Formation with a 50% transformation ratio from organic matter to oil. The reservoirs of the eastern structural trap in the field were filled with large amounts of medium to heavy oils. After the formation of two structural traps in the western area in the mid-Miocene, oils pre-existing in the second layer of the Khasib Formation in the east began migrating toward the structural traps in the west during the late Miocene, as verified by relatively higher 1-/4-methylcarbazole and 1,8-/2,7-dimethycarbazole ratios of oils in the west than that in the east and residual solid bitumen in the east. The strike-slip fault might also have restricted oil or gas migration during the Miocene, limiting oil accumulation in the west.

Hydrocarbon generation and evolution of the source rocks of the lower Es3 and upper Es4 members of the Shahejie Formation in the Niuzhuang Sub-sag, Jiyang Depression, Bohai Bay Basin, eastern China

Systematic organic petrology and geochemistry analyses have been conducted in the source rocks of the lower Es3 and upper Es4 members of the Shahejie Formation in the Niuzhuang Sub-sag, Jiyang Depression, Bohai Bay Basin, eastern China. The results indicate that the main organic types of shale and nongypsum mudstone in the lower Es3 and upper Es4 member are I-II1 kerogen, and the predominant ([Formula: see text]) activation energy frequencies range from 57 to [Formula: see text]. The similar distribution characteristics in the two source rocks indicate that they have a similar hydrocarbon maturation process. An extensive pyrolysis analysis indicates that the source rocks of the upper Es4 member do not have an obvious double peak hydrocarbon generation model. Previous studies indicate that the hydrocarbon index peak at a depth of 2500–2700 m is affected by migrating hydrocarbon. Major differences are not observed in the hydrocarbon generation and evolution process of the shale and nongypsum mudstone. The primary oil generation threshold of the lower Es3 and upper Es4 members is approximately 3200 m, and the oil generation peak is approximately 3500 m. The activation energy distribution of the gypsum mudstone of the upper Es4 member is wider than that of the shale and nongypsum mudstone, and lower activation energies account for a larger proportion of the activation energies. The above factors may lead to a shallower oil generation threshold for gypsum mudstone compared with that for shale and nongypsum mudstone.

Source rock potential of the Early Cretaceous intervals in the Darquain field, Abadan Plain, Zagros Basin, SW Iran

The Darquain field is located in the Abadan Plain SW Iran, which has a high potential for exploration and production of hydrocarbon resources with poorly defined petroleum systems. The goal of this paper is to characterize the Cretaceous source rock potential in the Darquain field. A gamma-sonic log was used as a proxy to identify probable source rock zones and to select sample depths. A total of 37 samples were analyzed by Rock-Eval, elemental, Gas Chromatography (GC) and gas chromatographymass spectrometry (GC-MS) techniques. The petroleum generation potential, as well as origin of the organic matter of samples, have been investigated. The results of this study indicate that, in the Early Cretaceous successions, there are favorable source zones in Garau, Gadvan, and Kazhdumi Formations. These source zones predominantly contain organic matter from marine origin, suggesting kerogen type II, while some samples contain terrestrial organic matters, suggesting kerogen type III. The Lower Garau zone, with 1.14 to 14.29% total organic carbon (TOC), is an excellent source rock with a fair genetic potential in the range of 2.74 and 9.5 mg/g. Elemental analysis results in the Lower Garau zone allow the classification of kerogens as high-sulfur. There are very good source zones in the Kazhdumi Formation, with fair to good genetic potential. The results of Rock-Eval and petrophysical analyses show that gamma ray data can be used as a useful tool to determine the potential source zones, although where TOC is less than 1% there is inconsistency. The results obtained from the biomarker characteristics are in agreement with the results of Rock-Eval pyrolysis and indicated carbonate source rocks, which contain a mixture of marine organic matter with a minor amount of terrigenous organic matter. Biomarker characteristics also suggest that the organic matter was deposited in a marine environment under reducing conditions, and that Early Cretaceous source zones are at the stage of early oil window to peak of oil generation.

Gravity-flow deposits and their exploration prospects in the Oligocene Dongying Formation, northwestern Bozhong Subbasin, Bohai Bay Basin, China

Abstract Gravity-flow deposits are important hydrocarbon exploration targets in most basins. In this study, an integration of geological, geophysical, and geochemical analysis is used to investigate the gravity-flow deposits and their petroleum prospects in the Oligocene Dongying Formation (E3d), Bozhong Subbasin, Bohai Bay Basin. Mass-transport deposits (MTDs) and channel-lobe complexes are the main gravity-flow depositional units. The mass-transport deposits (MTDs) show hummocky and chaotic reflections with poor continuity and variable amplitude. The channels display linear geomorphology with weak root-mean-square (RMS) amplitude, and the lobes are dominated by high-continuous and high-amplitude reflection at the terminal channels. The formation of gravity-flow deposits is primarily controlled by high sedimentation rate during a relative lowstand of lake level. The E3d3 source rock has TOC contents in the range of 0.6–3.1%, Rock-Eval S2 values in the range of 0.7–19.8 mg HC/g rock, and Hydrogen indices (HI) in the range of 100–600 mg/g TOC. The E3d2L source rock has TOC contents ranging from 0.5 to 1.9%, Rock-Eval S2 values from 0.4 to 7.8 mg HC/g rock, and HI from 40 to 480 mg/g TOC. Both E3d3 and E3d2L source rocks have good hydrocarbon-generation potential. The E3d3 and E3d2L source rocks have entered the oil-generation peak window with the vitrinite reflectance (Ro) higher than 1.0%. Oils generated from the underlying source rocks shortly migrated to the overlying gravity-flow lithologic traps. The gravity-flow reservoirs could serve as potential and effective hydrocarbon exploration targets.

Burial and thermal history reconstruction of the Mukalla-Sayhut Basin in the Gulf of Aden, Yemen: Implications for hydrocarbon generation from Paleocene potential source rock

In this study, four exploratory wells from the Mukalla-Sayhut Basin, Gulf of Aden are used for basin modeling study in order to simulate the petroleum generation and expulsion history of the Umm Er Radhuma Formation.The basin models illustrate that the Gulf of Aden is an extensional rift basin and initially developed during Oligocene as indicated by paleo-heat flow values. The heat flow reached peak heat-flow values of approximately 120–160 mW/m2 at Early to Middle Oligocene time. This high paleo-heat flow had a considerable effect on the Paleocene Umm Er Radhuma source rock and cooking of the organic matter. The basin models also indicate that the Umm Er Radhuma Formation source rock had passed the peak-oil generation window during the late Oligocene (Chattian) age. Onset of oil-generation began during late Rupelian age (∼29 Ma), whereas the main oil was generated during the Chattian age (27-24 Ma). The models also show that the petroleum was expelled from the Umm Er Radhuma source rock since latest Oligocene (late Chattian, < 24Ma) time, with transformation ratio of more than 50%. These basin models suggest that the Umm Er Radhuma Formation is an effective source rock where significant amount of petroleum is expected to be generated and expelled to any nearby potential reservoir rocks within the Mukalla-Sayhut Basin.

A method for determining oil-bearing pore size distribution in shales: A case study from the Damintun Sag, China

A good understanding of oil-bearing pore size distribution (PSD) in shales is crucial for determining reservoir sweet-spots. In this paper, we determined the oil-bearing PSD in lacustrine shales at peak oil generation by comparing PSDs between the extracted and un-extracted shale samples, and by relating the difference in PSDs between the extracted and un-extracted shale samples to the oil content in shales. It is found that while the specific pore volume (SPV) of meso pores are nearly 8 times as large as that of micro pores, macro pores contribute to the majority of the pore volume in lacustrine shales at peak oil generation. SPVs of the extracted samples are generally larger than that of the un-extracted ones. The oil-bearing PSD in pores with sizes up to 80 nm were obtained by subtracting SPVs of the un-extracted samples from that of the extracted ones within specific pore size intervals. The oil-bearing mechanism was further investigated by linking the oil-bearing PSD to the total oil content obtained from pyrolysis experiments. It is found that the content of oil residing in the micro and meso pores is significantly less than the total oil content, indicating that the oil is mainly contained in the macro pores. Therefore, the abundance and distribution of macro pores in lacustrine shales at peak oil generation are critical factors of a shale oil reservoir.

Geochemical characteristics of the Triassic Chang 7 lacustrine source rocks, Ordos Basin, China: Implications for paleoenvironment, petroleum potential and tight oil occurrence

The fact that high-quality lacustrine source rocks (generally shale and mudstone) control the formation and distribution of conventional and unconventional oil and gas reservoirs in lacustrine basins has been well-accepted in petroleum exploration and exploitation. Taking the Chang 7 lacustrine source rocks in the Ordos Basin as an example, several points having been reached are as follows. (1) The Chang 7 source rocks possess an excellent source rock potential, and the shales hold a better potential than the mudstones. (2) The paleoenvironments of the Chang 7 source rocks were sub-reducing to sub-oxidizing conditions and fresh- and brackish-water depositional environments with a maximum water depth of 150 m. The organic matter origins of the source rocks are mainly plankton, algae, bacteria and other aquatic microorganisms. (3) The beginning time of the oil generation of the Chang 7 source rocks is at 165 Ma, and the peak oil generation occurred during 115–95 Ma. The cumulative amounts of oil generation are up to 4711 × 103 t/km2 and the ratios of peak generation amounts to cumulative generation amounts are >50%. The beginning timing and peak generation timing of the shales are earlier than those of the mudstones, respectively, and the cumulative oil generation amount of the shales is higher than that of the mudstones, indicating a better oil generation potential of the shales. (4) Due to the more remained oil possessed in the shales, the hydrocarbon expulsion threshold of the Chang 7 shales (2560 m) is deeper than that of the Chang 7 mudstones (2080 m). (5) The occurrences of the Chang 8–6 tight oils are predominantly controlled by the outer boundary of the Chang 7 source rocks distribution, while the transition areas between thickness, TOC, and RO high value centers are the accumulation and enrichment zones. The Chang 7 shales controlled the occurrence of the Chang 8 tight oil reservoirs and the Chang 7 mudstones controlled the occurrence of the Chang 7 and Chang 6 tight oil reservoirs.

Origin of petroleum accumulation in the Chaheji-gaojiapu structural belt of the Baxian Sag, Bohai Bay Basin, China: Insights from biomarker and geological analyses

Abstract The origin of petroleum accumulations in the Chaheji-gaojiapu structural belt of the Baxian Sag, Bohai Bay Basin was evaluated based on the results of Rock-Eval pyrolysis on 135 samples and a biomarker analysis on 26 source rock samples and 33 oil samples. The four possible source rock intervals have different biomarker assemblages and were deposited in different environments. For example, pristane/phytane, C27-diasterane/C27-sterane and C19/C23-tricyclic terpane ratios show an increasing trend, but (C28+C29)-tricyclic terpane/[(C28+C29)-tricyclic terpane + Ts] and steranes/hopanes parameters display a decreasing trend among the lower part of the first member (Es1L) and the middle (Es3M) and lower part (Es3L) of the third member of the Eocene Shahejie Formation. This finding indicates that a decreasing anoxic and alkaline environment with an increasing input of terrigenous organic matter developed during the deposition of the Es1L, Es3M and Es3L source rocks. However, the biomarker parameters of the forth member (Es4) of the Eocene Shahejie Formation display highly similar characteristics with the Es3L source rocks, except for the C29-sterane 20S/(20S + 20R) and C27-diasterane/C27-sterane ratios, which show obviously higher than the other source rock values. The Es3-derived oils are absolutely dominant in the Chaheji-gaojipu structural belt, based on the biomarker analysis of saturated hydrocarbon, with slight or no contributions from the Es1L and Es4 source rocks because of the low maturation for the Es1L source rock and the absence of vertical migrating channels for the Es4 source rock. Faults are vital to petroleum migration and accumulation in this area and demonstrate the following double effects: (1) the deep faults cutting off the Es3 source rocks are the key channels for oil vertical migration; (2) the shallow faults entrap oil and finally form the commercial oil pools. As a result, the fault block reservoir is the major oil-reservoir type in the Chaheji-gaojiapu structural zone, and the lithologic reservoir is another oil-reservoir type in this area. Based on 1D burial and thermal history modelling, the E3 and E4 source rocks reached the oil-generation peak at approximately 5 Ma and 20 Ma, respectively, but the Es1L source rock is still in the low-mature stage. Therefore, the process of the large oil migration and accumulation for the Es3 source rocks occurred during the late Neogene-Quaternary. Through this research, there are two considerable exploration potentials for this area, including condensate reservoirs in the deep strata and low-mature reservoirs in the Es1 stratum interval.

Experimental investigation of the role of rock fabric in gas generation and expulsion during thermal maturation: Anhydrous closed-system pyrolysis of a bitumen-rich Eagle Ford Shale

Gold-tube pyrolysis experiments were conducted on miniature core plugs and powdered rock from a bitumen-rich sample of Eagle Ford Shale to investigate the role of rock fabric in gas generation and expulsion during thermal maturation. The samples were isothermally heated at 130, 300, 310, 333, 367, 400, and 425 °C for 72 h under a confining pressure of 68.0 MPa, corresponding to six levels of induced thermal maturity: pre-oil generation (130 °C/72 h), incipient oil/bitumen generation (300 and 310 °C/72 h), early oil generation (333 °C/72 h), peak oil generation (367 °C/72 h), early oil cracking (400 °C/72 h), and late oil cracking (425 °C/72 h). Experimental results show that gas retention coupled with compositional fractionation occurs in the core plug experiments and varies as a function of thermal maturity. During the incipient oil/bitumen generation stage, yields of methane through pentane (C1–C5) from core plugs are significantly lower than those from rock powder, and gases from core plugs are enriched in methane. However, the differences in C1–C5 gas yield and composition decrease throughout the oil generation stage, and by the oil cracking stage no obvious compositional difference in C1–C5 gases exists. The decrease in the effect of rock fabric on gas yield and composition with increasing maturity is the result of an increase in gas expulsion efficiency. Pyrolysis of rock powder yields 4–16 times more CO2 compared to miniature core plugs, with δ13CCO2 values ranging from −2.9‰ to −0.6‰, likely due to carbonate decomposition accelerated by reactions with organic acids. Furthermore, lower yields of gaseous alkenes and H2 from core plug experiments suggest that the rock fabric plays a role in promoting hydrogenation reactions of alkenes.

Petroleum source rocks characterization and hydrocarbon generation of the Upper Jurassic succession in Jabal Ayban field, Sabatayn Basin, Yemen

The Upper Jurassic samples of Jabal Ayban field, Sabatayn Basin, western Yemen were used to determine the source rock characteristics and petroleum generative potentials. Based on organic geochemical analysis, the Upper Jurassic source rocks have variable TOC content in the range of 0.82–13 wt%, indicating a fair to very good source rock generative potential. The bulk geochemical results showed that Safer Member contains Type III kerogen grading to mixed Type II–III, while the Lam and Meem members displaying generally Type II, mixed Type II–III and Type III kerogens, which have the ability to generate mixed oil and gas accumulations under thermal maturation level. Vitrinite reflectance in the range (0.35–0.78% Ro) and Tmax in the range (411–445 °C), generally proving that the Meem source rocks have sufficient thermal maturity for hydrocarbon-generation, whereas the Lam and Safer are immature source rocks. 1D basin modelling was performed to analyse the hydrocarbon generation and expulsion history of the study area. Calibration of the model with measured VR (% Ro) and (BHT) data shows that the paleo-heat-flow was high at Late Jurassic. The burial/thermal history models indicate that the source rocks in the Lam and Safer members are immature source rocks and the peak oil generation has not been reached yet. The models also indicate that the early hydrocarbon generation (0.64% Ro) in the Meem source rock occurred during late Jurassic at 150 Ma and the main hydrocarbon generation (0.79% Ro) has been reached approximately at 146 Ma. Therefore, the Meem Member can be consider as generative potentials of prospective source rock horizons in Jabal Ayban field, Sabatayn Basin.

Hydrocarbon generation and potential in continental organic-rich shales at the highly-mature stage, as determined by hydrous pyrolysis under supercritical conditions

Hydrous pyrolysis experiments were conducted to assess hydrocarbon generation and potential in three continental organic-rich shales at the highly-mature stage. The results of this study have important implications for deep petroleum exploration in China. The calcareous shale dominated by type-I kerogen reached its peak oil generation at a vitrinite reflectance (VR) of 1.5 %Ro, and entered the major stage of gas generation at a VR ranging from 1.50 to 2.44 %Ro. The high HI, low S2 and low atomic H/C ratio revealed that the calcareous shale has some potential for hydrocarbon generation at a VR greater than 2.44 %Ro. The mudstone with type-II kerogen reached its peak oil generation at a VR of 2.5 %Ro. The high atomic H/C ratio, but low HI and S2 indicated that mudstone may retain some hydrocarbon potential. The carbonaceous mudstone dominated by type-III kerogen had still not reached its peak of hydrocarbon generation at a VR of 3.12 %Ro. The low dryness of the gaseous hydrocarbon yields shows that the carbonaceous mudstone was still in the primary gas generation stage. The high values of S2 and atomic H/C fraction, but low HI, revealed that the carbonaceous mudstone may retain a large hydrocarbon generation potential at higher maturity stages. Our results suggested that the continental type-I and -II kerogen may have potential for shale gas and deep petroleum generation, while the continental type-III kerogen retained good potential for yielding deep natural gas.

Multi-proxy approach to screen the hydrocarbon potential of the Jurassic succession in the Matruh Basin, North Western Desert, Egypt

This paper discusses the hydrocarbon potential of the Jurassic succession in a mature basin in Egypt as an important element of a larger petroleum system study. Prior to any organic petrographic and organic geochemical analyses, a palynological age dating of the originally undifferentiated Jurassic sequence was carried out to identify different formations under investigation. This was based on key bioevents of some recovered dinoflagellate cysts and the identified lithology. Palynological, TOC/Rock Eval pyrolysis (including modified Rock-Eval methods), and vitrinite reflectance (VRo%) data from a total of 14 samples taken from the uppermost lower-upper Jurassic sequence represented by the Wadi Natrun (Toarcian-Aalenian), Khatatba (late Bathonian-Callovian), and Masajid (Oxfordian) formations in the Abu Tunis-1× well, are presented. In addition, two samples from the Abu Tunis-1× well and the proximal (~32km to the east) Siqueifa-1× well, having the highest remaining hydrocarbon potential (S2 yields), were analyzed and their results were compared using modified pyrolysis programs. Although the data showed a good correlation between the TAI of the palynomorph assemblage, vitrinite reflectance, and Tmax from Rock-Eval pyrolysis in the shallower intervals, the correlation between VRo and Tmax was poor in the lower half of the studied succession (middle Khatatba and Wadi Natrun formations). The very low Tmax values indicate immature OM while VRo and TAI indicated middle stage of oil window to past peak oil generation. The reason for this discrepancy is that the deeper samples are reservoir rocks, not source rocks, and the majority of the organic matter is not composed of reactive kerogen but consists of migrated hydrocarbons and NSO compounds. Contamination due to oil-based mud (OBM) was eliminated because the Abu Tunis-1× well was drilled in 1969, prior to the extensive use of OBM in drilling. This study showed that a multi-proxy approach is the best way to screen the hydrocarbon potential in a thick succession that contains interbedded source and reservoir rocks.

Thermal modeling and hydrocarbon generation of the Late Jurassic-Early Cretaceous Chia Gara Formation in Iraqi Kurdistan region, northern Zagros Fold Belt

The Late Jurassic-Early Cretaceous Chia Gara Formation is an important oil-source rock in Iraqi Kurdistan region. Chia Gara source rock is characterised by high organic matter and sulphur content with Type II_S kerogen. 1D basin models were integrated with geological information and geochemical data from Chia Gara Fm at four well locations in Kurdistan region, northern Iraq. The models of the burial/thermal history indicate that Chia Gara Fm is presently in the peak-oil generation window and some oil cracked to gas during Late Eocene to Late Miocene time. Onset of oil-generation began during the Middle Paleocene- Early Oligocene (60–30 Ma). Oil was generated during the Late Eocene to Late Miocene (48–9 Ma). The models also suggest that the oil was expelled from Chia Gara source rock during the Late Eocene to Late Miocene (37–9 Ma), with a transformation ratio more than 50%. The high transformation ratio of more than 80% in two wells suggests that the generated oil was cracked to gas during the end of Middle Miocene time and continued to present day. The basin modeling results further suggest that Chia Gara Formation acts as a prolific petroleum-source rock and significant of oil and limited of gas have been generated and expelled to any nearby prospect reservoir rocks in the Kurdistan region.

Generation and expulsion history of oil-source rock (Middle Jurassic Sargelu Formation) in the Kurdistan of north Iraq, Zagros folded belt: Implications from 1D basin modeling study

Middle Jurassic Sargelu Formation is an important oil-source rock in the Iraqi Kurdistan oilfields, northern Zagros Fold Belt. The Sargelu source rock is characterised by high organic matter and sulphur content with Type II-S kerogen, which can be expected to generate oil at low maturity stages.A 1D basin modelling was performed by integrating geological and geochemical data of the Sargelu source rock from six wells in the Kurdistan region, north Iraq. The basin modelling results was used to reconstruct the burial and thermal history and to simulate and predict the timing of petroleum generation and expulsion for the Middle Jurassic Sargelu source rock. Burial/thermal history models indicate that the Sargelu source rock had passed the peak-oil generation window during the Late Eocene to Late Miocene. Onset of oil-generation began during the Middle Eocene - Late Miocene (51-11 Ma), whereas the maximum rates of oil with limited gas were generated during the Late Eocene to Late Miocene (52-10 Ma). The models also show that the oil was expelled from the Sargelu source rock since Late Eocene to present-day (44-0 Ma), with transformation ratio higher than 50%. The subsequent high transformation ratio higher than 80% suggests that the generated oil was cracked to gas during the Early Oligocene and continued to present day. These basin modeling results also suggest that the Sargelu Formation acts as an effective oil-source where significant amount of petroleum is expected to be generated and expelled to any nearby prospect reservoir rocks in the Kurdistan region.

Basin modeling in the initial stage of exploration: a case study from the North Subbasin of the South Yellow Sea Basin

Basin modeling has become an important tool for analyzing sedimentary basins. The North Subbasin of the South Yellow Sea Basin is filled with thick Meso-Cenozoic terrigenous deposits during the rift evolution stage. The accumulation of data and achievements of geological investigations in recent years have provided the preconditions for basin modeling. The necessary parameters and geological elements for simulations are collated and summarized. Modeling of tectono-thermal evolution is performed and the related trend in heat flow is reconstructed and calibrated. The heat flow value commences from an average level of 61 mW/m2 during Middle-Late Jurassic, rises to about 80 mW/m2 from circa 145 Ma to circa 74 Ma, and then undergoes a gradual decline to 65 mW/m2 until the end of Oligocene.Three evolutionary phases, namely, the initial rifting phase, syn-rifting phase, and post-rifting phase, have been identified. The modeling results show that the North Subbasin generally enters into a stage of strong rifting during Cretaceous and undergoes rapid subsidence until the Late Cretaceous, then follows by a stage of moderate rifting during the Paleogene. The input and general workflow involved in 3-D modeling are introduced. Reconstruction of the petroleum system in the North Subbasin reveals that the threshold depth of hydrocarbon generation is located near the top of the Paleogene Funing formation, and the underlying Jurassic and Cretaceous source rocks have reached or exceeded peak oil generation and have almost completed the generation and expulsion of hydrocarbons. The main generation and expulsion in the Jurassic source rocks take place during the syn-rifting and post-rifting phases, whereas the peak generation and expulsion in the Cretaceous and Paleogene source rocks take place during the post-rifting phase. Although the study area is still a relatively less explored sedimentary basin, the results of modeling can provide valuable information for exploration. A preliminary discussion of the main uncertainty factors is also presented.

Evaluation of source rocks in the 5th member of the Upper Triassic Xujiahe Formation in the Xinchang Gas Field, the Western Sichuan Depression, China

The 5th member of the Upper Triassic Xujiahe Formation (T3x5) is one of the important targets for terrigenous natural gas exploration in the Xinchang Gas Field in the Western Sichuan Depression, however, the quality of the T3x5 source rocks is poorly studied and the understanding of it is controversial. Studies have been conducted on the development and organic geochemical characteristics of the T3x5 mudstone in the Xinchang Gas Field, and the results indicate that, the T3x5 mudstone in the Xinchang Gas Field display an average thickness of 285.3 m, and the thickness of each submember increases from north to south. The average TOC content, hydrocarbon potential (S1+S2) and chloroform bitumen “A” content of T3x5 mudstone are 2.17%, 2.26 mg/g and 0.264‰, respectively, with the organic abundance mainly reaching the standard of medium source rocks. The kerogen type index (TI) is lower than 0 with the mean δ13C value of −25.0‰, indicating mainly humic and sapropelic-humic types of organic matters. The average vitrinite reflectance (RO) value is 1.17%, indicating the stage after the peak of oil generation. The gas generation intensity of T3x5 mudstone is generally in the range of (3–16) × 108 m3/km2, which suggests the resource basis for the generation of medium-small gas fields. The total amount of natural gas generated by T3x5 mudstone in the Xinchang Gas Field is relatively low, and the generated gas cannot completely displace the water in the formation, therefore, the fullness of gas in the reservoirs is generally low, which causes the simultaneous production of gas and water and the low gas production in the process of production test.

Empirical relationship between gas composition and thermal maturity in Eagle Ford Shale, south Texas

Organic-rich and carbonate-rich Eagle Ford Shale is a self-sourced oil and gas reservoir with little alteration of gas chemistry as might be affected by petroleum expulsion and migration. As such it provides an ideal natural laboratory to quantify the compositional variation of gases generated from oil-prone type II kerogen during thermal maturation. The chemical composition of the gas released from rock crushing was conducted and integrated with Rock-Eval pyrolysis to define the empirical relationship between gas compositional parameters and thermal maturity in this study. From 10 wells in the Eagle Ford Shale in south Texas, we collected 74 core samples having a range of thermal maturity (the measured maximum temperature [Tmax] values of hydrocarbons generated in Rock-Eval pyrolysis range from 427°C to 494°C [800°F to 921°F], and the calculated equivalent vitrinite reflectance (Roe) values range from 0.51% to 1.73% based on Tmax values). Total organic carbon content ranges from 0.3% to 8.53%, with an average of 3.12% (standard deviation of 1.77%). Burial depth is from 2989.6 to 13,827.3 ft (911.2 to 4214.6 m). Our results showed that gas composition in the Eagle Ford Shale is mainly controlled by thermal maturity, and three stages of gas generation are identified based on the C1 and C2 concentrations of the gases released by rock crushing from Eagle Ford Shale core samples. The three stages of gas generation correspond to the following processes of organic matter conversion: (1) kerogen and bitumen thermal cracking to crude oil, (2) bitumen and heavy crude oil thermal cracking to light oil, and (3) light oil cracking to gas. Methane-rich gas and an abundance of branched butane and pentane are generated in light oil cracking to gas, resulting in high C1/C2, C1/(C2 + C3), i-C4/n-C4, and i-C5/n-C5 ratios. Increased cracking of normal alkanes such as n-butane and n-pentane occurs in the light oil cracking to gas. Empirical equations between gas compositional parameters and thermal maturity (Tmax or Roe) are obtained for oil-prone type II. The C1, C2, C1/C2, C1/C2 + C3, and i-C4/n-C4 ratios are the five best parameters for determining thermal maturity with an exponentially derived R2 value of 0.74. The composition of gas produced from the Eagle Ford Shale following hydraulic fracturing is used to validate the empirical equations. Calculated thermal regime for the oil production based on the produced gas is located at the peak of oil generation and the beginning of light oil cracking to gas, corresponding to Tmax from 454°C to 464°C (849°F to 867°F) or at an Roe ranging from 1.01% to 1.19%. Empirical equations provide a basis for interpretation of mud gas logging data and produced gas composition.