Expulsion Threshold Research Articles

Geochemical Modeling and Hydrocarbon Generation Potentiality of Source Rocks of the Oligocene to Miocene Succession in the Temsah Area, Eastern Nile Delta, Egypt

Geochemical investigation of the Temsah-4 well (T-4) in Temsah gas fields at the eastern offshore Nile Delta differentiate into two categories of OM (organic matter) which are kerogen types II and III within the boreholes penetrated Oligocene-Miocene source rocks. The geochemical and lithological characteristics of the OM-bearing formations in the investigated borehole recognized four thick organic matter-rich intervals (OMRI) in well T-4. The OMRI considers a part of formations that are believed to be considered a real source rock that comprises approximately 66.68% of the Wakar, 65.17% of Sidi-Salem, and 100% of Qantara Fms in the T-4 well. They comprised intervals depths of 3120m-3150m and 3300m-3559.4m belonging to Wakar Fm, from 3580m- 3870m belonging to Sidi-Salem Fm and from 3977m- 4170m belonging to Qantara Fm. The geochemical data reveals that Wakar Fm in the T-4 well considers immature source rock. While mature OMRI within Sidi-Salem and Qantara Fms in the T-4 well represented as effective mature source rocks. Construction of a TOC map in two dimensions throughout the studied areas shows a trend of increasing the quantity of OM eastward during the deposition of Sidi-Salem and Wakar Fms. The improvements of the richness (relatively high TOC) toward the eastward suggested a favorable condition for preservation and accumulation of OM toward the east than the west drilled boreholes. Based on the relative hydrocarbon potential (RHP) the suggested expulsion threshold depths appear to be shallower at 3700m in T-4. Burial history diagrams of studied T-4 wells based on geochemical results postulate that Tineh Fm enters the early mature stage at 2.8Ma. The maturity continues till the recent periods to enter the Qantara and most of Sidi-Salem Fms the same main-oil window at the T-4 area.

Quantitative effect of kerogen type on the hydrocarbon generation potential of Paleogene lacustrine source rocks, Liaohe Western Depression, China

Kerogen types exert a decisive effect on the onset and capacity of hydrocarbon generation of source rocks. Lacustrine source rocks in the Liaohe Western Depression are characterized by thick deposition, high total organic carbon (TOC) content, various kerogen types, and a wide range of thermal maturity. Consequently, their hydrocarbon generation potential and resource estimation can be misinterpreted. In this study, geochemical tests, numerical analysis, hydrocarbon generation kinetics, and basin modeling were integrated to investigate the differential effects of kerogen types on the hydrocarbon generation potential of lacustrine source rocks. Optimized hydrocarbon generation and expulsion (HGE) models of different kerogen types were established quantitatively upon abundant Rock-Eval/TOC/vitrinite reflectance (Ro) datasets. Three sets of good–excellent source rocks deposited in the fourth (Es4), third (Es3), and first (Es1) members of Paleogene Shahejie Formation, are predominantly types I–II1, II1–II2, and II–III, respectively. The activation energy of types I–II2 kerogen is concentrated (180–230 kcal/mol), whereas that of type III kerogen is widely distributed (150–280 kcal/mol). The original hydrocarbon generation potentials of types I, II1, II2, and III kerogens are 790, 510, 270, and 85 mg/g TOC, respectively. The Ro values of the hydrocarbon generation threshold for type I–III source rocks gradually increase from 0.42% to 0.74%, and Ro values of the hydrocarbon expulsion threshold increase from 0.49% to 0.87%. Types I and II1 source rocks are characterized by earlier hydrocarbon generation, more rapid hydrocarbon expulsion, and narrower hydrocarbon generation windows than types II2 and III source rocks. The kerogen types also affect the HGE history and resource potential. Three types (conventional, tight, and shale oil/gas) and three levels (realistic, expected, and prospective) of hydrocarbon resources of different members in the Liaohe Western Depression are evaluated. Findings suggest that the Es3 member has considerable conventional and unconventional hydrocarbon resources. This study can quantitatively characterize the hydrocarbon generation potential of source rocks with different kerogen types, and facilitate a quick and accurate assessment of hydrocarbon resources, providing strategies for future oil and gas exploration.

Conversion of the Oil and Gas Generation Potential of the Deep Source Formations of the West Siberian Basin: An Example of Well Tyumen SG-6

A model of the thermal evolution of the lithosphere of the West Siberian Basin in the area of Superdeep Well SG-6, which was drilled through the Koltogor–Urengoi graben, is used to numerically estimate the generation of various hydrocarbon (HC) fractions by the Triassic and Jurassic source rocks. The thermal model assumes the emplacement of a sill into the subsurface layers of the basement in the Early Jurassic and hydrothermal activity in the Late Pliocene–Lower Pleistocene, which noticeably impacted the conversion history of the HC potential of the Triassic and Jurassic source rocks. For the Triassic Pur formation, the emplacement of the sill into the subsurface layers of the basement in the Lower Jurassic drastically intensified the conversion of the HC potential to 84% and the degradation of more than 97% of the generated light oil mass. Calculations show that the heavy oil generated by the rocks of the Pur, Togur, and lower horizons of the Tyumen formations has degraded almost completely as a result of secondary cracking, while heavy oil predominates among the generated HC fractions in the upper horizons of the Tyumen Formation and in the rocks of the Bazhenovo Formation. The light oil remaining nowadays in the matrix of the source rocks has completely degraded in the Triassic rocks but makes up much of the HC products in rocks at the bottom of the Togur Formation and the top of the Tyumen Formation. This oil is the dominant in the upper horizons of the Togur Formation and in the bottom part of the Tyumen Formation. According to calculations, gas hydrocarbons account for a significant proportion of HC products in the Togur and Tyumen formations, and they dominate in the Middle Triassic Pur Formation. At the relatively low initial potential of HC generation and a low content of organic matter in the rocks of the Pur, Togur, and Tyumen formations, no primary expulsion threshold of liquid HC has been reached, and the generated liquid HC probably did not leave the rock matrix, while the gaseous HC likely migrated. The threshold of primary expulsion of liquid HC for the Bazhenov rocks was calculated to be reached at about 65 My.

How grain size influences hydrocarbon generation and expulsion of shale based on Rock-Eval pyrolysis and kinetics?

The differences between the Rock-Eval pyrolysis results of powder and grain samples have attracted wide attentions. Grain samples show lower hydrocarbon yield and different composition of the products. However, the effect of grain size on hydrocarbon generation and expulsion has not yet been quantitatively evaluated. In this study, we prepared each grain into a regular column with precise geometric parameters such as diameter, height, surface area, and volume, which is defined as an independent unit of hydrocarbon generation and expulsion. For comparison, a powder sample corresponding to each grain sample is collected simultaneously during the preparation process. The grain samples are used to simulate the mass of hydrocarbons expelled, while the powder samples are used to simulate the total mass of hydrocarbon generated. Our results show significant differences between the grain samples and the powder samples. All powder samples have a higher expulsion of free hydrocarbons (S1) than grain samples, and almost all grain samples have a higher expulsion of pyrolysis hydrocarbons (S2) than powder samples when the diameter of the grains is smaller than 3 mm. Temperature controls hydrocarbon generation, but grain size retards hydrocarbon expulsion. The influences of the “carry-over” phenomenon, oil adsorption and nanopore confinement are enhanced by grain size, which retards and inhibits hydrocarbon expulsion. Some free hydrocarbons (S1) cannot be expelled from the grain samples at 300 °C. Parts of the retained free hydrocarbons (S1) further cracked into small molecules, which can be expelled and detected as pyrolysis hydrocarbons (S2) at 300–650 °C. Four new parameters were proposed to quantify these influences, namely the S1retained, the S2extra expulsion, the HI difference parameter, and the TOC difference parameter. Diameter is more closely related to hydrocarbon expulsion rather than height. For grain samples, HI increases and TOC decreases with increasing diameter. Activation energies for hydrocarbon generation ranges from 43 to 67 kcal/mol for powder samples, while activation energies for grain samples are almost concentrated in 54–55 kcal/mol, indicating a high expulsion threshold for grain samples. As the grain diameter increases from 1.74 to 5.24 mm, the transformation ratio decreases and the generation rate increases, indicating that the grain size delays the expulsion of hydrocarbon. This laboratory simulation provides some new results to better understand the hydrocarbon generation and expulsion of shale rock under natural conditions.

Natural gas potential of Neogene source rocks in the Yiliping area, Qaidam Basin: Using an improved hydrocarbon generation and expulsion model based on least‐squares Monte Carlo

The Neogene petroleum system in the Yiliping area of the Qaidam Basin presents great prospects for natural gas exploration. However, its natural gas potential, including the source rock characteristics, is insufficient. Due to a lack of geological constraints, the hydrocarbon generation and expulsion (HGE) model, which is widely used in resource potential evaluation, may be unable to obtain optimal parameters. Here, we propose an improved HGE model based on least‐squares Monte Carlo to assess the HGE characteristics and natural gas resource potential of the Neogene source rocks in the Yiliping area by combining geological and geochemical investigations. The findings show that the Neogene source rock is effective and has significant potential for natural gas generation. Algae and bacteria, which were deposited in a saline and anoxic environment, are the primary sources of organic matter in Neogene source rock (primarily Type II and Type III). Modelling work suggests that Type II and III kerogen of Neogene source rock reach hydrocarbon generation threshold (HGT) at Ro = 0.38% and Ro = 0.49% and reach hydrocarbon expulsion threshold (HET) at Ro = 0.45% and Ro = 0.55%. The maximum HGE intensities are 3400 × 104 and 3378 × 104 t/km2. The extra‐source natural gas and shale gas resource potentials are predicted to be 2.05 × 1012 m3 to 4.11 × 1012 m3 and 7.03 × 1012 m3. The findings will guide future Neogene natural gas exploration in the Yiliping area of the Qaidam Basin.

Hydrocarbon expulsion model and resource potential evaluation of high-maturity marine source rocks in deep basins: Example from the Ediacaran microbial dolomite in the Sichuan Basin, China

Hydrocarbon expulsion features and resource potential evaluation of source rocks are crucial for the petroleum exploration. High-maturity marine source rocks have not exhibited a hydrocarbon expulsion mode owing to the lack of low-maturity source rocks in deep petroliferous basins. We considered the Ediacaran microbial dolomite in the Sichuan Basin, the largest high-maturity marine gas layer in China, to exhibit a method that quantitatively characterizes the hydrocarbon expulsion of high-maturity marine source rocks. The experiment of fluid inclusion, rock pyrolysis, and vitrinite reflectance (Ro) of 119 microbial dolomite core samples obtained from the Dengying Formation were performed. A hydrocarbon expulsion model of high-maturity source rock was established, and its resource potential was evaluated. The results showed that the Ediacaran microbial dolomite in the Sichuan Basin is a good source rock showing vast resource potential. The hydrocarbon expulsion threshold is determined to be vitrinite reflectance at 0.92%. The hydrocarbon expulsion intensities in the geologic history is high with maximum of 1.6 × 107 t/km2. The Ediacaran microbial dolomite expelled approximately 1.008 × 1012 t of hydrocarbons, and the recoverable resource was 1.5 × 1012 m3. The region can be categorized into areas I, II, III, and IV, in decreasing order of hydrocarbon expulsion intensity. Areas with a higher hydrocarbon expulsion intensity have a lower drilling risk and should be prioritized for exploration in the order I > II > III > IV. Two areas, northern and central parts of Ediacaran in the Sichuan Basin, were selected as prospects which had the drilling priority in the future gas exploration. The production data of 55 drilled wells verified the high reliability of this method. This model in this study does not require low-maturity samples and can be used for evaluating high-maturity marine source rocks, which has broad applicability in deep basins worldwide.

Mass Balance-Based Method for Quantifying the Oil Moveable Threshold and Oil Content Evaluation of Lacustrine Shale in the Paleogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin.

Substantial heterogeneity in lacustrine shale brings significant challenges to oil exploration. Therefore, a clear and effective resource evaluation standard can significantly reduce the exploration risk and cost, thus further guiding the prediction in productive areas. However, due to the lack of consideration of the thermal maturity and kerogen type, the present evaluation standards may result in the misjudgment of the resource quality of shale oil reservoirs. In this study, a method based on mass balance involving a hydrocarbon generation statistical model was proposed to calculate oil movable threshold (OMT) values. The OMT values for different types of kerogens are determined from simple and easily obtained pyrolysis parameters. Based on the OMT values, a three-dimensional resource quality evaluation model is constructed and applied to the source rocks in Member (Mbr) 1 of the Shahejie Formation (Fm) Nanpu Sag, Bohai Bay Basin, eastern China. The results show that the Mbr 1 of Shahejie Fm shale is a set of high-quality source rocks with high total organic matter (TOC) and S1c (calibrated free hydrocarbons) content. Meanwhile, the hydrocarbon generation potential of the studied lacustrine shales are in the order of type I > type II1 > type II2 > type III, whereas the OMT values show a similar order. From type I to type III, the hydrocarbon expulsion threshold (HET) values for the four types of shales correspond to pyrolysis peak temperatures (Tmax) at 438, 426, 428, and 432 °C with the maximum OMT values being 143, 128, 127, and 122 mg HC/g TOC, respectively. The movable and favorable shale oil accumulations are mainly associated with type II1 and II2 shales. Our work provides a novel method for distinguishing the resource quality and locating a favorable exploration target for lacustrine shale, improving efficiency and reducing exploration risks.

Subsurface geology and geochemical evaluation of the Middle Jurassic-Lower Cretaceous organic-rich intervals, West Kalabsha area, Western Desert, Egypt

The West Kalabsha (WKAL) area is a western extreme exploratory area of the Faghur Basin in the Western Desert of Egypt. The study of four wells (WKAL; A-1 X, K-1 X, P-1X, and C-1 X), interpreted with twenty seismic lines, shows that the area is dissected by a series of normal faults with an irregular, E–W strike direction. The general trend of the throw is toward the south–southeast. The most prospective area for hydrocarbon (HC) migration is toward the north (upthrown side) of an E-W striking normal fault north of the WKAl-K-1 X and A-1 X wells. The WKAL-P-1 X and WKAL-K-1 X wells in the Faghur Basin were selected for both geochemical evaluation of possible source rock intervals and burial history modelling within the basin. Integration of the wire-line logs with geochemical analysis identified six organic matter-rich intervals (OMRIs) within the Middle Jurassic-Lower Cretaceous sequence. Four intervals are in the Alam El-Bueib-3C (AEB-3C) member with a cumulative vertical thickness of 530ft. The other OMRIs are 110ft in thickness recorded within the AEB-6 (10ft) and Upper Safa (100ft) members. The studied organic matter (OM) reveals type III, IIIC, and IV kerogens (mainly gas-prone) with a terrestrial origin. They have reached a maturity level consistent with the late oil window. The expulsion threshold depth detected in the WKAL-P-1 X well is 12000ft in the AEB-3C member, whereas the active source depth limit (ASDL) is 15000ft in the Safa Member. The present study suggests a paleo-geothermal gradient range between 1.13oF/100ft and 1.39oF/100ft with an estimated regional erosion of 5500 to 7000ft of strata mainly between the Paleozoic-Jurassic and Cretaceous-Tertiary boundaries. The present-day geothermal gradient based on bottom-hole temperatures shows a geothermal gradient of 1.4oF/100ft (WKAL-P-1 X), that increases to the north to 1.65oF/100ft (WKAL-K-1 X). Burial history modelling reveals that sedimentary strata entered the mature oil zone in the Early Cretaceous (110–115Ma) at depths of 7500–8000ft in the deepest part of WKAL-P-1 X and WKAL-K-1 X wells (Paleozoic strata). Maturation continued to present, resulting in Jurassic and Lower Cretaceous strata currently falling into the late oil window.

Potential resources of conventional, tight, and shale oil and gas from Paleogene Wenchang Formation source rocks in the Huizhou Depression

Conventional and tight unconventional oil and gas resources in the Huizhou Depression have shown broad exploration prospects, which mainly originate from Wenchang Formation source rocks. Thus far, studies on Wenchang Formation source rocks mainly focused on the geochemical characteristics and conventional petroleum resource evaluation; however, the correlation of conventional, tight, and shale oil and gas, and their resources are still unknown. In fact, the formation of conventional, tight, and shale oil and gas are intrinsically related, which allows for a more objective evaluation to consider the three types of oil and gas resources simultaneously in the whole dynamic process of both hydrocarbon generation and expulsion, as well as reservoir tightness history. In this work, based on geological and geochemical analyses, the improved hydrocarbon generation potential method was utilized to establish a hydrocarbon generation and expulsion model of the Wenchang Formation source rocks. Then, combined with the reservoir tightness history, the conventional, tight, and shale oil and gas resources were evaluated. The results show that the Wenchang Formation source rocks are distributed in the whole depressions, with a thickness of 50-1850 m and an average total organic carbon content of 2.2%. The organic matter is mainly type II and is mature-high maturity. The Wenchang Formation source rocks reached hydrocarbon generation threshold and expulsion threshold at a vitrinite reflectivity of 0.43% and 0.65%, respectively, and the reservoir evolved completely tight at 2.3 Ma. Overall, the Lower and Upper Wenchang Formation contain a large amount of conventional, tight, and shale oil and gas resources. Cited as: Hu, T., Wu, G., Xu, Z., Pang, X., Liu, Y., Yu, S. Potential resources of conventional, tight, and shale oil and gas from Paleogene Wenchang Formation source rocks in the Huizhou Depression. Advances in Geo-Energy Research, 2022, 6(5): 402-414. https://doi.org/10.46690/ager.2022.05.05

Petroleum resource potential evaluation using insights based on hydrocarbon generation, expulsion, and retention capabilities—A case study targeting the Paleogene Es1 formation, Qikou Sag

The Shahejie Formation of the Bohai Bay Basin has been set as a favorable shale oil area for exploration in currently practice. However, the process was impeded by the obscurity of favorable exploration area in the shale play and resource evaluation targeted at the main research area, the Qikou Sag. In particular, there is a need for a systematic assessment of the various types of resources present. The study presented herein emphasizes on quantifying source rock generation, expulsion, and retention hydrocarbon characteristics using the advanced hydrocarbon-generation potential model (HGPM) in the first member of the Paleogene Shahejie Formation (Es 1 ) of the Qikou Sag. Geological and geochemical features reveal that the Es 1 source rocks are of relatively high quality with a 1200-m maximum thickness and abundant organic matter (total organic carbon (TOC) content of 2.27% on average; type I kerogen dominated; mature stage). The type of organic matter was reassessed using the progressive and reasonable dimensionless TOC and S 2 variables. The HGPM demonstrated that the expulsion threshold was R o = 0.50% and the maximum generation hydrocarbon potential ( Q g ), expulsion hydrocarbon potential ( Q e ), and retention potential ( Q r ) were 746.99, 231.57, and 515.42 mg HC/g TOC, respectively. The hydrocarbon generation (I g ), expulsion (I e ), retention (I r ), and effective retention intensity (I re ) all centered in the Qikou main depression at 450 × 10 4 , 200 × 10 4 , 300 × 10 4 , and 230 × 10 4 t/km 2 , respectively. The predicted resource potential can be finally queued as follows: retention shale resources with 22.90 × 10 8 t oil equivalent, including movable shale oil and gas of 12.21 × 10 8 t, and conventional and tight oil or gas resources with 9.62 × 10 8 t oil equivalent. The most favorable exploration areas are mainly distributed in the Qikou main depression and Qibei Subsag. Quantitative and detailed evaluation provides a reasonable prediction of exploration targets and prospects and further mitigates risks and losses incurred during shale-exploration successions. • Advanced hydrocarbon generation potential model is used in the Qikou Sag, NE China. • Potential resources and favorable targes of study area are presented. • Redetermination on organic matter type and redescription on HC generation process. • Unconventional oil and gas occupy a desirable resource scale. • The resources comparisons between Qikou Sag and the adjacent Nanpu Sag.

Pore evolution model and diagenetic evolution sequence of the Mesoproterozoic Xiamaling shale in Zhangjiakou, Hebei

Current research on diagenesis and its evolution focuses mainly on sandstone reservoirs. Conventional oil and gas reservoir observation techniques for characterizing shale reservoirs are limited, and comprehensive research on nanoscale pore variations, diagenesis and evolution of shale reservoirs, especially immature and low-maturity marine shale reservoirs, is relatively scarce. To reveal the diagenesis and evolution of low-maturity marine shale, geochemical and mineral analyses, quantitative characterization of the pore structure and qualitative characterization of the pore morphology were performed on the Xiamaling shale. With the burial and geothermal history, the Xiamaling diagenetic evolution sequence and the nanoscale pore system evolution were studied. The results show that smectite continually transforms to an illite-smectite (I/S) mixed layer and then quickly transforms to illite and chlorite; the kaolinite content gradually decreases as maturity increases. The hydrocarbon expulsion threshold of the Xiamaling shale is EqRo = 1.0%, and the porosity decreases to a minimum value of EqRo = 1.0% and then increases. The pore structure evolution model shows that the pore volumes (PVs) of micropores and macropores decrease to minima at approximately EqRo = 0.92% and 0.85%, respectively, and then increase; the mesopore PVs continuously decrease. Micropore and mesopore surface areas (SAs) decrease to their minima at approximately EqRo = 0.85% and 1.0%, respectively, and then increase; simultaneously, the macropore SAs continuously decrease. The main diagenetic types of the Xiamaling shale are compaction, dissolution, cementation, thermal maturation of organic matter (OM), and clay mineral transformation; it reaches period B of the middle diagenetic stage, and the diagenetic evolution sequence is determined. The pore system composition and variation characteristics of the Xiamaling shale are analysed, and a corresponding evolution model is established.

Hydrocarbon generation and expulsion characteristics of the Lower Cambrian Qiongzhusi shale in the Sichuan Basin, Central China: Implications for conventional and unconventional natural gas resource potential

In recent years, significant progress and breakthroughs have been made in the exploration of conventional and unconventional natural gas in the Lower Cambrian petroleum system in the Sichuan Basin in Central China, showing excellent exploration prospects. However, detailed evaluation of the Qiongzhusi shale, the main source rocks in the Lower Cambrian petroleum system, including their hydrocarbon generation and expulsion characteristics, is lacking, even though such evaluation is critical for understanding conventional and unconventional natural gas resource potential. To investigate the geological and geochemical characteristics of the Qiongzhusi shale, experiments including pyrolysis, total organic carbon (TOC), vitrinite reflectance (Ro), gas chromatography (GC) and gas chromatography–mass spectrometry (GC–MS) were conducted. Based on modeling work and fluid inclusion analysis, the hydrocarbon generation and expulsion characteristics of the Qiongzhusi shale and their control on hydrocarbon accumulation was analyzed, and the conventional and unconventional natural gas resource potential of the Lower Cambrian petroleum system was systematically evaluated. The results indicate that the organic matter of the Qiongzhusi shale is mainly derived from bacteria and algae deposited in a saline, reducing marine environment. The shale is predominantly composed of type I kerogen with an average TOC value of 1.85 wt%, and is widely distributed in the basin with an average thickness of 212.7 m. The Qiongzhusi shale is primarily post-mature with an average vitrinite reflectance (Ro) of 2.53%. Modeling work suggests the Qiongzhusi shale reached the hydrocarbon expulsion threshold (HET) at Ro = 0.9%, and the main hydrocarbon expulsion stages are Triassic, Jurassic, and Cretaceous. The maximum hydrocarbon generation and expulsion intensities at present day are 32 × 10 6 t/km 2 and 18 × 10 6 t/km 2 , respectively. The conventional natural gas resource potential of the Longwangmiao Formation derived from the Qiongzhusi shale is estimated to be between 9.51 × 10 12 m 3 and 19.03 × 10 12 m 3 . The unconventional shale gas resource potential of the Qiongzhusi shale is predicted to be 1.4 × 10 12 m 3 , showing significant prospects for natural gas exploration. • Geochemistry characteristics of the Qiongzhusi Formation were systemically evaluated. • Hydrocarbon generation and expulsion characteristics of the Qiongzhusi Formation were first analyzed. • Conventional and unconventional natural gas resource potentials of ancient Lower-Cambrian petroleum system were calculated.

Geochemical constraints on the origin and distribution of Cretaceous source rocks in the Ceará basin, Brazilian Equatorial margin

The Mundaú sub-basin composes the western segment of the Ceará Basin, which is one of a series of basins of the Brazilian Equatorial Margin that resulted from the breakup of Western Gondwana. This study investigates the origin and maturation of the organic matter preserved in the rocks of the middle and outer shelf of the Mundaú sub-basin, in order to assess the source-rock potential for oil and gas generation. The samples selected for this study are representative of the Mundaú, Paracuru, and Ubarana formations, which correlate with the rift, transition, and drift phases of the Western Gondwana breakup. The results indicate moderate to good potential for oil generation and good potential for gas generation for the Mundaú Formation. Fault activity during the rift phase favored sediment supply. Kerogen type III predominates in shallower portions and probably reflects the contribution from the continent. Good to excellent potential for oil and gas generation is indicated for the Paracuru Formation. Kerogen types I and II predominate, having the marine organic matter been deposited in reducing conditions. The most promising interval for hydrocarbon generation is limited by the top of the Trairí Member and the top of the Paracuru Formation. Moderate to good potential for oil and gas generation is suggested for the Uruburetama Member of the Ubarana Formation. The source rocks located in the middle shelf were deposited under reducing conditions in a transgressive marine environment. Kerogen varies from type II, to a mixture of types II and III, and to subordinate type III. Poor to fair potential for oil generation is indicated for the Itapajé Member of the Ubarana Formation. Kerogen type IV (inert or degraded) is typical in the middle shelf, and kerogen type IV and subordinate type III are typical on the outer shelf. The presence of inert kerogen is related to high-energy, oxidizing depositional environments. The hydrocarbon expulsion threshold estimated for the outer shelf is at 2106-m, for the middle shelf at 1635-m, and for the deep waters at 3632-m depths. Source rocks of the middle and outer shelves occur between 561 m and 4080 m, whereas those in deep waters occur between 2754 m and 5007 m of depth. The Active Source Rock Depth Limits (ASDL) estimated for the outer shelf is below 4500 m, whereas for deep waters, this limit is close to 6000 m. These organic geochemical constraints are important guidelines for oil and gas exploration in the Ceará and adjacent basins.

Hydrocarbon charging and accumulation in the Permian reservoir of Wangguantun Buried Hill in Huanghua Depression, Bohai Bay Basin, China

The Permian reservoirs of Wangguantun Buried Hill are deep buried reservoirs in the Bohai Bay Basin, with a depth of more than 4000 m. The superposition of multi-stage tectonic movements also increases the complexity and unclear nature of the hydrocarbon charging and accumulation history. This study aims to address these issues by considering the structural evolution and burial–thermal history of the strata and studying the hydrocarbon expulsion process of source rocks by means of rock pyrolysis experiments. In addition, petrography, fluorescence spectroscopy, GC-MS (gas chromatography–mass spectrometry) of the oil from inclusions, laser Raman spectroscopy, and microthermometry of fluid inclusions were conducted and these analyses were coupled with cathodoluminescence tests of minerals and typical geological profiles to reveal the hydrocarbon charging process of the Permian reservoir in Wangguanshan Buried Hill. The results show that the oil of the Permian reservoirs in Wangguantun Buried Hill is generated from both upper Palaeozoic coal-measure and Paleogene lacustrine mudstone. The corresponding vitrinite reflectance (Ro) values at the expulsion thresholds of the Palaeozoic coal, Palaeozoic carbonaceous mudstone, Palaeozoic mudstone, and Paleogene mudstone are 0.68%, 0.72%, 0.72% and 0.73%, respectively. The Permian reservoirs have experienced three oil and gas charging periods. In the first period, during the late Jurassic to early Cretaceous (135–100 Ma), the reservoirs were charged primarily with less mature oil. The subsequent uplift of the strata in the late Cretaceous exposed the ancient reservoir, and most of the oil transformed into carbonaceous bitumen. In the second period, the middle and late Paleogene (45–33 Ma), the reservoirs were charged primarily with less mature oil from the Paleogene source rocks and mature to highly mature oil and gas from the coal-measure source rocks. In the third period, from the late Neogene to the present (12–0 Ma), the reservoirs were primarily charged with highly mature oil from the Paleogene mudstone and highly mature and overmature oil and gas from the coal-measure. Fractures provide the main storage space for hydrocarbons, while some were stored in intergranular and dissolved pores. Consequently, fractured reservoirs should be important targets for gas and petroleum exploration in such deep reservoirs. In addition, the regional structure evolution controlled the hydrocarbon expulsion and charging processes, which guided the formulation of the hydrocarbon accumulation model of the Permian reservoir.

Hydrocarbon Generation Potential and Depositional Setting of Eocene Oil-Prone Coaly Source Rocks in the Xihu Sag, East China Sea Shelf Basin.

The Xihu Sag in the East China Sea Shelf Basin is a focus for hydrocarbon exploration and development. Hydrocarbons in the Xihu Sag are believed to have mainly originated from coals in the Paleogene Pinghu Formation (shortened as Pinghu coal). In this study, the hydrocarbon generation potential, origin of organic matter, and depositional setting of the Pinghu coal were analyzed by means of optical microscopic analysis, bulk organic geochemistry, and molecular geochemistry analysis. The results reveal that the maceral compositions of the Pinghu coal are characterized by a predominance of vitrinite (73.91–96.13%) with relatively high contents of liptinite (1.47–23.02%) and only minor amounts of inertinite (0–5.18%). Type II–III kerogen and high values of TOC (total organic carbon) (8.24–56.77%), EOM (extractable organic matter) (14 601–112 259 ppm), and HI (hydrogen index) (178.76–291.18 mg·HC/g·TOC) indicate that the Pinghu coal is both gas- and oil-prone and could not only generate but also expel hydrocarbons. The results of vitrinite reflectance (0.54–0.90%), Tmax (421–453 °C), and biomarker-related parameters, including CPI (carbon preference index) (1.10–1.61), OEP (odd-to-even predominance) (1.09–1.49), 22S/(22S + 22R) for C31 homohopane (0.59–0.62), and 22S/(22S + 22R) for C32 homohopane (0.57–0.60), suggest that these coaly source rocks have entered the hydrocarbon generation threshold, most of which have entered the expulsion threshold. Biomarker-related parameters of ∑n-C21-/∑n-C22+ (0.38–3.62), Pr/Ph (3.33–9.23), Pr/n-C17 (1.91–14.88), Ph/n-C18 (0.35–1.83), 22S/(22S+22R) of C31 homohopane (0.59–0.62), 22S/(22S + 22R) of C32 homohopane (0.57–0.60), 1,2,7-TMN/1,3,7-TMN (0.74–14.39), and 1,2,5-TMN/1,3,6-TMN (2.22–21.07) suggest that organic matter in the Pinghu coal was deposited under relatively oxic peatland conditions characterized by a predominance of terrestrial higher plant input, especially the resin-rich Pinaceae and Taxodiaceae. The absence of combustion-derived PAHs indicates that neither vegetation fire nor peat fire occurred very frequently during the formation of peat. Areas in the Xihu sag with considerable thicknesses of coal should be paid particular attention for future hydrocarbon exploration. From a global perspective, Cenozoic coaly source rocks, which are characterized by a relatively high content of aliphatic components, should be paid special attention for their oil-prone properties related to the advent of conifer plants.

Hydrocarbon source potential evaluation insight into source rocks—A case study of the first member of the Paleogene Shahejie Formation, Nanpu Sag, NE China

The features of source rock hydrocarbon generation, expulsion, and retention are essential factors in petroleum resource potential evaluation. In this study, the improved hydrocarbon generation potential evaluation method was used to quantify the characteristics of the source rocks of the first member of the Paleogene Shahejie Formation (Es1) in the Nanpu Sag, Bohai Bay Basin, NE China. Based on the geological and geochemical data for the source rocks, the favorable exploration areas were predicted and the resource potential was evaluated. Our results show that Es1 is a set of high-quality source rocks with desirable geological (maximum thickness > 600 m) and geochemical (average total organic carbon content of 1.44%; dominantly type II kerogen; mature stage) characteristics. The improved hydrocarbon generation potential model shows that the hydrocarbon expulsion threshold is located at Ro=1.0%. The maximum hydrocarbon generation potential (Qg), hydrocarbon expulsion potential (Qe), hydrocarbon retention potential (Qs), and efficient hydrocarbon retention potential (Qse) are 549.31, 162.20, 387.11, and 287.11 mg HC/g TOC, respectively. The maximum hydrocarbon generation, expulsion, retention, and effective retention intensities are 250×104, 70×104, 180×104, and 150×104 t/km2, respectively. These parameters reach the highest value in the Linque and Caofeidian Sub-sag. The resource potential of the retention shale oil, the movable shale oil, and the conventional and the tight petroleum resources are 1.99×108, 4.38×108, and 1.37×108 t oil equivalent, respectively. This study offers a fresh and plain but operable workflow for resource evaluation, which can be applied in other petroliferous basins with low degree of exploration.

The hydrocarbon generation and expulsion features of source rocks and tight oil potential of the second member of the Qiketai Formation, Shengbei area in the Turpan–Hami Basin, NW China

Significant progress in tight oil exploration has been reported in the second member of the Qiketai Formation (J2q2) in the Shengbei area of the Turpan–Hami Basin. Geochemical analyses were conducted to assess the quality of the J2q2 source rocks. The improved hydrocarbon generation potential method was utilized to quantify the hydrocarbon generation and expulsion features of the source rocks. The results showed that J2q2 source rocks were deposited in a reduced lacustrine setting with a high palaeoproductivity. The J2q2 source rocks are widely distributed (approximately 1,000 km2) and have a thickness that varies from 50 to 130 m. Moreover, they can be identified as a set of high‐quality source rocks (thermally mature rocks with Ro values >0.5%, consisting mainly of types I and II kerogen and possessing an average total organic carbon content of 2.68%). The oil–source correlation results reveal that the source of crude oil in the studied area is J2q2. The improved hydrocarbon generation potential method is established for different kerogen types to limit the influence of the kerogen type on the calculation. The hydrocarbon expulsion threshold of the type I model is located at Ro = 0.6%. The type II kerogen rocks have different characteristics, and the hydrocarbon expulsion threshold is located at Ro = 0.62%. The maximum hydrocarbon generation and expulsion intensities are 700 × 104 t/km2 and 400 × 104 t/km2, respectively. The hydrocarbon generation and expulsion amount of the J2q2 source rocks are 21.4 × 108 t and 12.3 × 108 t, respectively. The tight oil potential of the J2q2 tight oil in the Shengbei area is 4.09 × 108 t. The SB10 and SB6 well areas are favourable J2q2 tight oil exploration areas in the Shengbei area. The SB10 well area has the highest hydrocarbon generation and expulsion intensities in the study area and is the best tight oil exploration target.

A revised method for reconstructing the hydrocarbon generation and expulsion history and evaluating the hydrocarbon resource potential: Example from the first member of the Qingshankou Formation in the Northern Songliao Basin, Northeast China

Reconstructing the hydrocarbon generation and expulsion history of source rocks is an essential part of evaluating the hydrocarbon resource potential by genetic method. The hydrocarbon generation potential method is an efficient tool for quantifying the hydrocarbon generation and expulsion characteristics of source rock and evaluating the hydrocarbon resource potential based on Rock-Eval data. Although various revised versions of the method are publicly available, the following problems remain to be resolved: (a) the method is subjective; (b) implicit limitations are observed; and (c) rock mass loss is not considered, which may result in unacceptable errors. In this study, we propose a revised hydrocarbon generation potential method. Expressions for calculating the original rock mass (Go), original total organic carbon (TOCo), transformation ratio (TR), hydrocarbon expulsion ratio (ER) and hydrocarbon expulsion efficiency (f) were developed and incorporated into the hydrocarbon generation and expulsion history reconstruction and hydrocarbon resource potential evaluation, and these expressions combined conventional and unconventional resource evaluations systematically with objective and accurate results. The first member of the Qingshankou Formation (K2qn1) in the Northern Songliao Basin, Northeast China, was used as an example to demonstrate the application of the proposed method. The results have been compared with the unrevised method using the same Rock-Eval data sets and verified with previous reports to demonstrate its reliability. The results also indicate that the hydrocarbon generation threshold (HGT) and hydrocarbon expulsion threshold (HET) of K2qn1 are Ro = 0.4% and Ro = 0.6%, respectively. Three hydrocarbon generation and expulsion peak stages were identified: K2n (81–74 Ma), K2m (74–66 Ma), and N2t (66–0 Ma). The hydrocarbon generation and expulsion centers of K2qn1 are mainly the Qijia-Gulong Sag and Sanzhao Sag. The resource potentials of conventional oil, unconventional tight oil, and shale oil associated with K2qn1 source rocks in the Northern Songliao Basin are 8.15 × 108 t, 22.97 × 108 t, and 62.1 × 108 t, respectively.

Organic geochemistry, hydrocarbon generation, and expulsion characteristics and their impact on tight oil: A case study of the third member of the Upper Palaeogene Shahejie Formation, Nanpu Sag, Bohai Bay Basin, NE China

In recent years, exploration of tight oil in the Nanpu Sag has made significant progress in the third member of the Upper Palaeogene Shahejie Formation (Es3) in the Nanpu Sag, Bohai Bay Basin, Northeast China, showing excellent prospects. However, owing to insufficient understanding of the hydrocarbon generation and expulsion characteristics of Es3 source rocks and their matching relationship with the reservoir tightening time, the genetic type and resource potential of tight oil systems are not precise, which limits the further exploration of tight oil. In this study, the geological and geochemical characteristics of Es3 source rock are identified through a comprehensive geological and organic geochemistry analysis. In addition, hydrocarbon generation and expulsion patterns are established using a hydrocarbon generation potential model. On the basis of these results, combined with sandstone reservoir evolution histories, we have identified the genetic type and resource potential of the tight oil. The results show that the kerogen types of the Es3 source rocks of the Nanpu Sag, are widely distributed in an area of nearly 1,000 km2 and have a large thickness of more than 700 m, are mainly Types II and III with a high average total organic carbon (TOC) value of 1.63%. Moreover, the source rocks are primarily in the mature stage, with an average vitrinite reflectance (Ro) of 1.06%. The Es3 source rock reached the hydrocarbon expulsion threshold at Ro = 0.7%, and the hydrocarbon expulsion efficiency was approximately 70%. Two hydrocarbon generation and expulsion centres are identified, the Gaoshangpu and Laoyemiao structural belts, with maximum hydrocarbon generation and expulsion intensities of 100 × 106 t/km2 and 80 × 106 t/km2, respectively. In addition, two genetic types of tight oil are identified with accumulation before and after tightening, respectively. The resources of these types are 2.3 × 108 t and 20.4 × 108 t, respectively, with a total of 22.7 × 108 t, which indicates significant prospects for tight oil exploration.

Quality, hydrocarbon generation, and expulsion of the Eocene Enping Formation source rocks in the Wenchang Depression, western Pearl River Mouth Basin, South China Sea

Recently, increasing numbers of oil and gas reservoirs have been discovered in the Wenchang Depression, western Pearl River Mouth Basin, South China Sea, revealing prospects for hydrocarbon exploration. The Enping Formation (E3e) is a key target layer for the development of source rocks. However, previous work has only focused on lacustrine swamp source rocks of E3e in the Wenchang A Sag, without a systematic study of shallow lacustrine source rocks. In this study, the quality of E3e shallow lacustrine source rocks is reevaluated, and the hydrocarbon generation and expulsion characteristics are analyzed using relevant geological data and constructing a conceptual model. The results show that the E3e2 source rocks have greater thickness (50–600 m) and similar organic matter abundance (0.5–2.5%) compared with the E3e1 source rocks (50–500 m and 0.5–2.5%). On the whole, the E3e source rocks were deposited in the continental environment and are dominated by Type II and Type III kerogen. Meanwhile, the E3e source rocks of the Wenchang A Sag are in the stage of mature to over mature, while those of the Wenchang B Sag are in the stage of low mature. Vertically, the hydrocarbon generation potential of the E3e2 source rocks is greater than E3e1. Also, the cumulative hydrocarbon production of steep slope in the Wenchang A Sag is larger than that in the Wenchang B Sag. In addition, the corresponding vitrinite reflectances of hydrocarbon expulsion threshold and peak are 0.72 and 0.96%, respectively. Horizontally, four hydrocarbon generation and expulsion centers were mainly concentrated in different subsags of the Wenchang A and B Sags for E3e. The maximum values of hydrocarbon generation and expulsion intensity for E3e1 are 1500 × 104 t/km2 and 1000 × 104 t/km2, respectively, while those for E3e2 are 1800 × 104 t/km2 and 1200 × 104 t/km2, respectively, with the expulsion efficiency of 75%.