Petroleum Generation Research Articles

Formation mechanism of fault accommodation zones under combined stress in graben basin: Implications from geomechanical modeling

A fault accommodation zone is a type of structure that is defined as regulating displacement and strain between faults structure. Increasing numbers of fault accommodation zones are being identified in graben basins, indicating the potential exploration target and petroleum accumulation areas. This study aims to analyze the formation mechanism and development of fault accommodation zones under combined stress by a numerical simulation method considering geomechanical modeling. Using three-dimensional (3-D) seismic interpretation and fractal dimension method, exampled with the Dongxin fault zone, the fault activity and fault combination pattern were conducted to quantitatively characterize the activity difference in fault accommodation zones. Combined with mechanical experiment test, a geomehcanical model was established for fault accommodation zones in a graben basin. Integrating the paleostress numerical simulations and structural physical simulation experiment, the developmental characteristics and genetic mechanism of fault accommodation zones were summarized. Influenced by multi movements and combined stresses, three significant tectonic evolution stages of the Dongxing Fault Zone (DXFZ) were distinguished: During the Es3 sedimentary period, the large difference in the stress, strain, and rupture distribution in various faults were significant, and this stage was the key generation period for the prototype of the DXFZ, including the FAZ between large-scale faults. During the Es2 sedimentary period, the EW-trending symmetric with opposite dipping normal faults and the NE-SW trending faults with large scale were furtherly developed. The junction area of two secondary normal faults were prone to be ruptured, performing significant period for inheriting and developing characteristics of fault accommodation zones. During the Es1 sedimentary period, the high-order faults in the DXFZ exhibited the obvious fault depressions and strike-slip activity, and the fault accommodation zones were furtherly inherited and developed. This stage was the molded and formative period of the FAZ, the low-order faults, and the depression in the DXFZ.

Integrated Interpretation of Eocene-Palaeocene Rocks in Potwar Basin, Pakistan: Implications for Petroleum Generation

This study demonstrates how an integrated geochemical and petrophysical analysis can be used to evaluate the petroleum generation potential of source and reservoir rocks. The Eocene and Palaeocene sequences of the Potwar Basin, located in the upper Indus Basin of Pakistan, were analyzed. Well logs and Schlumberger log interpretation charts were used for the petrophysical analysis of the Chorgali Formation's reservoir potential. Geochemical methods were applied to 34 well-cutting Sakesar and Patala formations samples. Results from Vitrinite Reflectance (VR) (%Ro) and Tmax data suggest that both formations have reached the peak of their oil generation window. The Sakesar Formation has a mean TOC of 1.88 wt. % and HI values of 375 mg HC/g TOC. The Patala Formation has a mean TOC of 3.33 wt.% in well A and HI values ranging from 2.4 to 369 mg HC/g TOC in well B, with a mean TOC of 3.52 wt%. Both formations have mixed Type II/III kerogen. The findings indicate that both the Sakesar and Patala formations possess good oil/gas-generation potential and may act as source rocks in the Potwar Basin. Petrophysical analysis of the Chorgali Formation shows an average porosity of 10.32%, water saturation of 36.14%, and hydrocarbon saturation of 63.85%. This indicates that the Chorgali Formation has an average to good reservoir potential. The research findings will aid exploration and production companies in the Fimkassar Oilfield.

High resolution sequence stratigraphy of the Mishrif Formation (Cenomanian-Early Turonian) at zubair oilfield (al-rafdhiah dome), southern Iraq

The Mishrif Formation (Cenomanian -E Turonian) is one of the most important geological formations in the Middle East and Iraq because it contains enormous petroleum accumulations. It is considered to be the first reservoir in the region, and is still being studied because of its economic significance. The carbonate of the Mishrif Formation derives from a variety of depositional settings, including mid-ramp, shoal, lagoon, and intertidal. The five main microfacies discussed in this paper are wackestone, packstone, grainstone, floatstone, and bindstone. The most frequent fossilised components found in the Mishrif Formation are rudists, benthic foraminifera, echinoderms, burrows molluscs, and algae. According to the microfacies and analysed wireline log data, the sequence stratigraphy of the studied formation is composed of two regression cycles. Five parasequences of transgressive–regressive cycles make up the depositional sequence of the Mishrif Formation. The standard depositional environments seem to demonstrate a gradual regression, beginning with a short period of the outer ramp, then a steady period of the mid-ramp, and ending in the intertidal environment. Additionally, the study recorded two regional maximum flooding surfaces: K-135 and K-140. The former is present in the lowermost part of the formation, while the other lies in the middle. This study shows a close relationship between facies (environments) and hydrocarbon accumulation. The increased accumulation focuses on the lower part of the studied formation, and seems to be lower in the upper part of the formation as a result of changes in the environment of deposition.

Dynamic evaluation on sealing capacity of caprocks of the Meso-Neoproterozoic reservoirs in Ordos Basin, China

The Meso-Neoproterozoic is a new play in the Ordos Basin. A deeper understanding about the dynamic relationship between the caprocks and the source rocks is needed. Based on the comprehensive analysis of hydrocarbon source development characteristics of the Meso-Neoproterozoic and its overlying strata, as well as the formation contact relationships, lithology characteristics and exploratory drilling data, it is recognized that the Meso-Neoproterozoic contains two types of petroleum accumulation assemblage, that is, the “self-sourced indigenous” and “upper source rock-lower reservoir” assemblages. The former is mainly controlled by the development and distribution of source rocks of the Changcheng System, with the Lower Cambrian shale sequence as its caprock. The later is controlled by the superposition between the Meso-Neoproterozoic and its overlying source rocks and this assemblage is mainly distributed in Hangjinqi and Pingliang areas with the Carboniferous-Permian shale sequence as its caprock. The dynamic evaluation on the displacement pressure serves to reconstruct the displacement pressure history of the caprock. The results show that the shale sequence of the Cambrian Maozhuang Formation in well XY 1 in the southern Ordos Basin has possibly acquired the ability of sealing natural gas since the early of Late Triassic. Its displacement pressure increased rapidly up to 20 MPa during the Late Triassic-Jurassic and keeps at 9.2 MPa at present, indicating fair sealing ability. The Carboniferous-Permian caprocks in Hangjinqi area could have acquired the ability to seal natural gas in the Late Jurassic-Early Cretaceous, and the present-day displacement pressure is 9–12 MPa, indicating good sealing ability. The upper Paleozoic caprock in Pingliang area has been able to seal natural gas since the Early Jurassic, with a maximum displacement pressure of 23 MPa during the Cretaceous period and a current value of 17–20 MPa, indicative of strong ability to seal natural gas. The sealing ability of caprocks of both the “self-sourced indigenous” and “upper source rock - lower reservoir” assemblages has come into being earlier than or at least no later than the peak gas generation of the source rocks and therefore the caprocks are dynamically effective in geohistory. The Meso-Neoproterozoic reservoirs in the Ordos Basin are well preserved and probabally of better potential for exploration in terms of the caprock-source rock combination.

Properties and Model of a Lacustrine Shale Oil Reservoir: A Case Study of the Upper Fourth Member and Lower Third Member of the Shahejie Formation in Dongying Sag and Zhanhua Sag, Jiyang Depression

By combining thermal simulation experiments with core data, thin sections, scanning electron microscopy (SEM), source rock, and high-pressure mercury and gas adsorption analysis, this paper evaluates the properties and models of shale reservoirs in the upper fourth member and the lower third member of the Shahejie Formation in Dongying Sag and Zhanhua Sag. The results show that the oil shale is a high-quality source rock with petroleum generation potential. Inorganic mineral pores, organic pores, and fractures have developed with petroleum storage capacity. Clay and organic-rich soft shale lithofacies are interbedded with carbonate-rich hard shale lithofacies to form sandwich-type source–reservoir–caprock assemblages with internal sealing properties. Bitumen occurs mostly in the free state, and to a lesser extent is adsorbed, and shows flow characteristics. The migration resistance of the bitumen is displacement pressure, including capillary force and adsorption resistance, and the main force is pore fluid pressure. The migration modes of the bitumen include both subcritical flow and instantaneous flow, which are controlled by pore fluid pressure, displacement pressure, and the rock’s fracture strength. Owing to the multi-scale characteristics of the shale reservoir space, a vein-type model of a multi-scale progressive transport network is developed that obeys Murray’s law with a dominant migration pathway in the shale reservoir. The shale oil reservoir is a special lithologic reservoir controlled by the sedimentary environment and has self-generation, self-storage, and self-sealing characteristics with developed pore fluid overpressure and a multi-scale transport network.

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.

Turbidite Fan Deposits in Gentle Slope Zones of Continental Faulted Basins: A Case Study from the Chezhen Depression, Bohai Bay Basin

Turbidite fans, serving as good reservoirs for petroleum accumulation, are typically formed during deep faulting periods in continental basins, particularly in steep slope zones. However, gentle slope zones are also significant and unique for the formation of turbidite fans. These turbidite fans hold immense importance in exploring concealed lithological reservoirs. Taking the Chezhen Depression of Bohai Bay Basin as an example, we conducted a comprehensive study of the turbidite fan deposits in the gentle slope zone. Our results indicate that (1) small-scale distal-source turbidite fans are a common sedimentary type in the Chezhen Depression of the Bohai Bay Basin; (2) the study area is mainly characterized by seven lithofacies; (3) there are incomplete Bouma sequences in the study interval. This study is an important turbidite investigation into continental faulted basins, and it can also provide an important reference value for exploration and development in unconventional reservoirs of the same type.

Comparison of Evaporite-Related Source Rocks and Implications for Petroleum Exploration: A Case Study of the Dongying Depression, Bohai Bay Basin, Eastern China

The Dongying Depression (Bohai Bay Basin, eastern China) was widely filled with evaporite (anhydrite and halite) layers during the Paleogene period, especially the middle of the fourth member of the Shahejie Formation (Es4). Most evaporite layers are interbedded with mudstone strata. The strata of Es4 are divided into three sections, referred to as the upper layers, evaporite layers, and lower layers, respectively. The analysis of elemental concentrations, elemental ratios, and Pr/Ph suggests that the lower layers were deposited in an intermittent saline lake environment within a relatively dry climate. The evaporite layers were formed in a highly saline lake environment, whereas the upper layers were formed in a brackish-saline to fresh-water environment. Organic matter (OM) abundance indices, including total organic carbon (TOC), chloroform extracts, total hydrocarbon content (HC), hydrocarbon generation potential (S1 + S2), and OM type, show that the source rock potential for petroleum generation in the upper layers is best, that in the evaporite layers is fair, and in the lower layers it is poor. Carbon isotopes (δ13C) of hydrocarbons in the evaporite and lower layers were heavier than those in the upper layers. Thermal maturity parameters show that the thermal evolution process of OM in the upper layers was faster where evaporite were present compared with evaporite-free areas, while the thermal evolution of OM in the lower layers was slower in these regions. The high thermal conductivity of evaporites may have accelerated the thermal evolution of source rocks in upper layers and allowed hydrocarbon generation at a shallower burial depth. This resulted in the earlier appearance of the petroleum generation window compared to in evaporite-free areas. Meanwhile, the thermal evolution of OM in the lower layers was restrained, and consequently the hydrocarbon generation window was widened, which implies the potential for petroleum exploration in deep strata under the evaporite sequence. This is a common phenomenon in evaporite-bearing basins, according to previous and present studies.

Characterization of free and bound bitumen fractions in a thermal maturation shale sequence. Part 2: Structural evolution of kerogen and bitumen during shale oil generation, expulsion and retention

Knowledge of the formation and enrichment mechanisms of shale oil is essential to understanding its mobility and hence a critical aspect for evaluating shale oil exploration and production. Semi-open hydrous pyrolysis experiments were performed on an organic-rich shale to simulate the petroleum generation and expulsion processes of Type II kerogen. The residual rocks matured to different levels (Easy%Ro = 0.50–1.37) were thereafter treated with stepwise extraction to obtain free and bound bitumen fractions. This study focuses on the structural characteristics of kerogen, bitumen fractions, and expelled oil during shale maturation using Fourier transform infrared (FTIR) spectroscopy and quantitative flash pyrolysis–gas chromatography (Py–GC). The results reveal that the composition of expelled oils changes with increasing maturity, whereas an opposite trend in structural composition was observed for kerogen after significant oil expulsion from the shale occurs, beginning at Easy%Ro = 0.79. A notable change is that aliphatic carbon chains of kerogen became shorter and/or more branched while those of expelled oil appeared to be more aliphatic with longer carbon chains at this stage. However, the overall compositional structures of shale bitumen fractions, both in free and bound phases, show only slight changes within the oil window stage. The bound bitumen is generally enriched in oxygenated functional groups as compared to free bitumen, indicating that the bound bitumen is related mainly to the interaction between the mineral surface and the bitumen–kerogen matrix. During maturation, the cracking (including defunctionalization) and condensation of kerogen and bitumen fractions, as well as a compositional fractionation due to oil expulsion, are likely to be the main factors influencing the opposite trend observed in structural compositions between kerogen and expelled oil. These processes may control the quality and content of expelled oil and bitumen in a petroleum system. Nevertheless, kerogen, expelled oil and bitumen show a gradual trend of decarboxylation during shale maturation in general.

Composite confining systems: Rethinking geologic seals for permanent CO2 sequestration

Permanent containment is paramount for geologic carbon sequestration. Petroleum experience proves the possibility but also creates bias—to date, carbon storage projects have used seals similar to those of producing petroleum accumulations—thick, laterally extensive, effectively impermeable layers. These work for CO2, but may not be present where needed, nor optimal for sequestration. We introduce the concept of composite confining systems, defined here as multi-layer stratigraphic systems of discontinuous barriers with no a priori requirements for continuity or minimum capillary entry pressure. We explore the concept through physical analog modeling, geologic characterization and full-scale numerical modeling. We find that barriers need only offer enough capillary entry pressure contrast to divert the flow of CO2 and that barrier frequency and barrier area are the key variables in retarding vertical migration. Data from Southern Louisiana Miocene deltaic deposits shows ∼5–15 mudstone barriers/100 m of section, with average mudstone lengths of over 1 km and aspect ratios ∼2:1, giving effective ratios of vertical to horizontal permeability (kv/kh) of ∼0.0005. Full-scale reservoir models show that these systems can completely arrest vertical migration of industrial-scale volumes of CO2 (10's of megatons) within a few 10's of meters of stratigraphic section. Unlike more conventional petroleum seals and traps, which retain CO2 in a concentrated, mobile state, composite confining systems disperse and immobilize it via migration-assisted trapping. The greatest risks to performance of composite confining systems are the same as for conventional seals–the potential shortcuts across stratigraphic barriers, e.g., legacy wells, fluid escape pipes and permeable faults that focus flow.

Petroleum system modeling in complex tectonic setting; a study case of the Huallaga-Marañon retroforeland basin system, Peru

The present study explores the oil and gas potential of the Huallaga–Marañon Andean retroforeland basins in Perú, considering a regional transect which extends from the Eastern Cordillera in the west trough the Huallaga fold-and-thrust belt at the Andean deformation front to the Marañon Basin in the east. The sequential restoration of main tectonic events was derived from previous stratigraphic and structural interpretations revisited with reprocessed seismic lines, and new geochemical, petrographical, geochronological and thermochronological data. The resulting framework was tested in a 2-D Basin and Petroleum System Modeling (BPSM) to check the relationship between burial history, thermal maturity evolution and timing of hydrocarbon generation, expulsion and trapping at regional scale. BPSM suggests that during the Late Cretaceous (ca. 80 Ma) the petroleum generated in the Upper Triassic–Lower Jurassic source rock known as the Aramachay Formation migrated through the Middle–Upper Jurassic Sarayaquillo Formation basal sandstones up to 250 km and accumulated in the southeast of the Marañon Basin. From the Late Miocene, the reactivation of vertical faults favored the migration and accumulation of petroleum in Cretaceous siliciclastic reservoirs which is consistent with the hydrocarbon fields existence in this sector of the basin.In addition, results of modeling show that in the southwest of the Marañon Basin the development of structures during Late Miocene times postdated the generation and expulsion of hydrocarbons calculated for the Aramachay Formation which introduces a risk of synchronization between oil migration and charge. However, part of the generated hydrocarbons during the Late Cretaceous and Cenozoic are partially preserved in Jurassic reservoirs due to the high seal capacity of mudstones of the Sarayaquillo Formation. Such hydrocarbon fluids are redistributed and migrated into structural traps during Miocene times. In addition, the Miocene gas generation and expulsion also will reduce the risk of synchronization with the development of structures. In the Eastern Cordillera, organic-rich levels of the Aramachay Formation are in the late immature to early oil window show the occurrence of organic pores adding hydrocarbon storage capacity, suggesting this unit to be considered as a potential unconventional target in future exploration activities.

Generation Time and Accumulation of Lower Paleozoic Petroleum in Sichuan and Tarim Basins Determined by Re–Os Isotopic Dating

With the targets of petroleum exploration transferred to the deep and ancient strata, abundant oil and gas resources have been found in Lower Paleozoic and older strata in central and western China. Due to complex evolutionary processes including multiple episodes of hydrocarbon accumulation and ubiquitously accompanied by secondary alterations, significant uncertainties remain concerning the generation time and accumulation processes of these revealed petroleum sources. In this paper, relative pure Re and Os elements existing in the asphaltene fractions of Lower Cambrian solid bitumen collected from the Guangyuan area, western Sichuan Basin, SW China and Middle–Lower Ordovician heavy oils in the Aiding area of the Tahe oilfield in the Tarim Basin, NW China were successfully obtained by sample pretreatments, and Re–Os isotopic analysis was subsequently carried out for the dating of these. The Re–Os isotopic composition indicates a generation time of Guangyuan bitumen to between 572 Ma and 559 Ma, corresponding to the late Sinian period of the Neoproterozoic era. By the means of Re–Os isochron aging, initial 187Os/188Os ratios, and carbon isotopic compositions, the Lower Cambrian bitumen is supposed to originate from source rocks of the Doushantuo Formation in the Sinian strata and subsequently migrated into the reservoirs of the Dengying Formation. This previously reserved petroleum was transformed into its present bitumen state by the destruction of reservoirs caused by tectonic uplift. The Re–Os dating results of Middle–Lower Ordovician heavy oil of Tarim Basin suggest that it was formed between 450 Ma to 436 Ma, corresponding to the Late Ordovician–Early Silurian system, and the generated petroleum likely migrate into the Middle–Lower Ordovician karst reservoirs to form early oil reservoirs. With tectonic uplift, these oil reservoirs were degraded and reformed to the heavy-oil reservoirs of today.

Geophysical Modeling and Its Contribution on the Reservoir Characterization of Al Baraka in El Gallaba Plain, South Egypt

Summary The early Cretaceous formations in recent years are considered significant potential hydrocarbon-bearing rocks in many rift basins such as Komombo, south Egypt. Therefore, this study is focused on the critical analysis and interpretation of well logging together with seismic reflection data on the Al Baraka petroliferous reservoir in the Komombo subbasin. The interpretation of these data was used to construct the first 3D geophysical models in this area which were subsequently interpreted in terms of their potential to be hydrocarbon-bearing or not. The 3D petrophysical models were deduced to illustrate the spatial distribution and propagation of the petrophysical properties (laterally and vertically) within the reservoir. Additionally, 3D seismic models were prepared to get a comprehensive, in-depth picture of how the productive hydrocarbon reservoir zones are structurally controlled in different depths. So, these models are crucial for explaining reservoir characteristics and providing supported geological reservoir models for precise reservoir performance prediction. This study aims to differentiate and determine hydrocarbon potential zones in terms of the petroleum system. The results of these progressive analyses showed that only two zones (C and D) in the Six Hills Formation are considered the most productive zones because they have a large thickness of sand bodies, low-water saturation values, high porosity, and high permeability. These zones are located in the northeastern and central parts of the studied area, which represent the depocenter of the subbasin. This evidence supported and confirmed the presence of petroleum accumulations in certain zones within the Six Hills Formation. Therefore, this work can give and encourage experts with adequate knowledge to understand the development of the rift basins in Komombo and other basins in middle and south Egypt.

Differential hydrocarbon generation and evolution of typical terrestrial gas-prone source rocks: An example from the Kuqa foreland basin, NW China

Terrestrial gas-prone source rocks are significant for hydrocarbon gas accumulations especially in central and western basins in China. The Kuqa foreland basin in the northern margin of the Tarim Basin, NW China is rich in natural gas with recent discoveries of several large to giant gas-producing fields (e.g., the Kela-2, Dibei, Dabei-1, and Zhongqiu-1 gas fields, etc.) and a proven 3 P gas reserve of over one trillion cubic meters (TCM). This proliferous petroleum province is powered by an effective and diverse gas-prone source rock series in the basin comprising mudstone, carbonaceous mudstone, and coal seams. To date, little systematic research work has been done on the petroleum generation potential of the source rocks. This has seriously restricted the assessment of petroleum resources and further exploration in the frontier areas of the basin. A sealed gold tube pyrolysis approach was employed to simulate the oil and gas generation and cracking yields for the aforementioned three types of source rock. Compared with typical Type I and II1 kerogens, the three types of source rocks in the Kuqa foreland basin are characterized by (1) far less hydrocarbon yield (150 mg/g TOC) with comparatively larger amounts of CO2 (310 mg/g TOC), (2) a limited capacity and narrower window (0.5%–1.08% Ro) for oil generation, and (3) a much earlier secondary cracking for bulk oil to light oil and gases (>0.86% Ro for mudstone and >1.08% Ro for both carbonaceous mudstone and coal). All the source rocks are gas-prone, and significant amount of gas can still be generated during an over-mature stage. The kinetic parameters obtained allow us to model hydrocarbon generation in the Kuqa foreland basin more realistically. It is concluded that (1) two episodes of hydrocarbon generation occurred with hydrocarbon gases being mainly generated during the later stage (12–3 Ma); and (2) the depocenter of the basin is capable of supplying massive high-mature gases as late as in the Quaternary, which is crucial for the formation of giant gas fields. The findings provide new insight on the reconstruction of oil and gas accumulation processes and further hydrocarbon exploration in the basin.

Oil generation and expulsion modeling of the syn-rift Salif oil-source rock in the Tihamah Basin, Yemeni Red Sea: Implications for shale oil exploration

The Miocene Salif Formation is an oil-source rock within the Tihamah Basin, southern Red Sea of Yemen. The Salif shale beds are characterized by high organic carbon content (TOC) up to 5.59% and high oil saturation index (OSI) (30 < OSI <260 mg HC/g TOC). However, most of the Salif shale samples exhibit OSI values of >100 mg HC/g TOC, indicating a thermally mature and oil-saturated source rock system with high oil-bearing potential. This finding is supported by the vitrinite reflectance values, representing mature oil generation window. Therefore, the shale oil potential of the Salif source rock system is studied for the first time by integrating geochemical data and geological information into a 1-D modelling scheme. The models reconstructed for the thermal and burial history infers that the Salif source rock system is located within the late oil-window from the Late Pliocene to present-day. Kerogen to oil conversion and the timing of petroleum generation and expulsion are also simulated by the 1-D models, showing that 10–50% of the total kerogen is converted into oil during the early Pliocene to the Pleistocene, which is consistent with the peak-late mature oil-window (0.70–1.26 %Ro). The models also exhibited that limited oil was expelled from the Salif source rock system since the Pleistocene-present-day as demonstrated by the TR ratio of up to 55%. The integration of source rock evaluation and modeling approach concludes that the Salif source rock provides a good potential for possible oil production, where suitable reservoir characteristics do occur.

The effects of Jurassic igneous intrusions on the generation and retention of gas shale in the Lower Permian source-reservoir shales of Karoo Basin, South Africa

Shale gas potential of the Whitehill Formation (Permian), Karoo Basin, South Africa is strongly influenced by widespread Jurassic igneous intrusions. A high-resolution organic petrographic and geochemical study is reported here on two stratigraphic sections, the objective being to gain insights into the chemical structure and alteration of oil-prone sedimentary organic matter during contact metamorphism. One section unaffected by intrusion served as background, while the other section was intruded by two laterally continuous dolerite sills with an average thickness of 10.7 and 9.3 m, preferentially emplaced at the upper and lower contacts of the formation, respectively. Heat flow from the sills caused TOC and S2 values from programmed pyrolysis to decline over a distance of 8.7 m from 3.2 to 0.15% and 4.65 to 0.11 mg HC/g TOC, respectively, and cause the reflectance of vitrinite and solid bitumen to increase from 2.03 to 5.82% and 1.58 to 7.87%.Organic matter in the background samples is dominated by solid bitumen, a secondary thermal conversion product of oil-generative Type II kerogen. In the sill-hosting section, the thermal aureoles can be recognized by systematic changes to the optical texture and chemical structure and composition of solid bitumen. Solid bitumen particles develop anisotropy approaching the sills and become transformed into coke and pyrolytic carbon. δ13Corg values become less negative by up to 3.13‰ VPDB. These data suggest significant devolatilization of organic matter to methane and destruction of petroleum generation and retention potential in the contact aureole of the sills. The trend of these datasets, coupled with the presence of several sills and their laterally extensive nature throughout much of the study area suggests that the intrusions have been significant in increasing methane generation on a basinal scale. Together, this study indicates that the complementary application of combined light and electron microscopy (CLEM), programmed pyrolysis, and isotope ratio mass spectrometry (IRMS) is suitable for a comprehensive characterization of organic matter alteration through the maturation continuum. Results also show that contact metamorphic alteration of organic matter by intrusions produced structural and compositional changes that are distinctive from those expected from geological burial maturation where graphite is the end-product.

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.

A new hydrocarbon prospect determination using the seismic interpretation and petrophysical evaluation of Bahariya reservoir in Nader field, north Western Desert, Egypt

The goal of this research is to assess the hydrocarbon potential of Bahariya reservoirs in Nader Field of Khalda Ridge concession in the northern part of Western Desert, which had never been addressed before. This study is based on using a complete set of well-logs of four wells and twenty 2D seismic lines, where both the Upper and Lower Bahariya members were evaluated as hydrocarbon-bearing sandstone reservoirs in the Nader Field. Seismic interpretations were used to clarify the structural settings of the tops of these members. These members' time-and-depth-structure maps reveal a variety of structural features which aid in hydrocarbon prospect identification in the area. The interpretation of the depth structure contour maps clearly defines NW-SE fault trend. The petrophysical evaluation includes lithology identification and determinations of petrophysical parameters such as effective porosity (PHIE), net-pay thickness, water saturation (Sw), shale content (Vsh), and hydrocarbon saturation (Sh). The computed petrophysical parameters of the Upper Bahariya reservoir reveal that it has a PHIE range of 13–24%, Sw of 53.7–92%, and Vsh of 12.5–23%. On the other hand, the computed petrophysical parameters of the Lower Bahariya reservoir reveal that it has a PHIE range of 14–23%, Sw of 35–89%, and Vsh of 12.1–18%. The Sh averages 46.3% for the Upper Bahariya and 65% for the Lower Bahariya. The maximum net-pay thickness is 33 foot in the Lower Bahariya reservoir and is 11 foot in the Upper Bahariya reservoir. The results of this study revealed three new proposed locations to the southeast and north of the investigated Nader Field. These locations lie on four- or three-way dip structural closures that are suitable for petroleum accumulations. These potential locations also exhibit decreasing in Vsh and Sw, and increasing in net pay, PHIE, and Sh in both Upper and Lower Bahariya reservoirs. As a result, it is advised to pay more attention to exploration efforts on new promising locations for more economical petroleum discoveries.

Fluid evolution and petroleum accumulation in the precambrian gas reservoirs of the Sichuan Basin, SW China

Deep marine carbonates comprise one of the most significant reservoir types globally. Reconstruction of Precambrian oil reservoirs and the complex tectonism that affected Precambrian carbonate reservoirs demonstrate the complexity of the natural gas enrichment mechanism. A comparison between the fluid evolution of the well-preserved reservoirs in the central Sichuan Basin and the poorly preserved reservoirs in the southeastern Sichuan Basin offers insights into the factors that control the preservation of ancient reservoirs. We conducted geochemical analysis of the multistage cementation sequence, Raman quantitative analysis on fluid (gas) inclusions, and rare earth element (REE) analysis of diagenetic fluid environments. Hydrocarbon migration can cause variations in the diagenetic environment. Quantitative Raman measurements of the trapping pressure, trapping temperature, and composition of fluid (gas) inclusions are also useful in defining periods of gas accumulation. In situ U–Pb dating results of dolomite veins indicate that extensive dolomitization in the Sichuan Basin began during the early Cambrian. In the central Sichuan Basin, reservoir pressure evolved from normal during the Middle Jurassic to strongly overpressured during the mid-Cretaceous. Overpressure generated before Himalayan tectonism appears to be positively correlated with gas preservation. Overpressure within inclusions bearing hydrogen sulfide indicates that thermochemical sulfate reduction (TSR) does not produce intense dissolution that increases the porosity of carbonate reservoirs and reduces pore pressure. Poorly preserved reservoirs were intruded by exogenous and hydrothermal fluids but remained normally pressured. Secondary methane-rich gas inclusions record normal pressure conditions during the early Paleogene.

Editorial: The relationship between petroleum accumulation and mineralization in sedimentary basins

Editorial: The relationship between petroleum accumulation and mineralization in sedimentary basins