Hydrocarbon Expulsion Research Articles

Identification and evaluation of shale oil micro-migration and its petroleum geological significance

Taking the Lower Permian Fengcheng Formation shale in Mahu Sag of Junggar Basin, NW China, as an example, core observation, test analysis, geological analysis and numerical simulation were applied to identify the shale oil micro-migration phenomenon. The hydrocarbon micro-migration in shale oil was quantitatively evaluated and verified by a self-created hydrocarbon expulsion potential method, and the petroleum geological significance of shale oil micro-migration evaluation was determined. Results show that significant micro-migration can be recognized between the organic-rich lamina and organic-poor lamina. The organic-rich lamina has strong hydrocarbon generation ability. The heavy components of hydrocarbon preferentially retained by kerogen swelling or adsorption, while the light components of hydrocarbon were migrated and accumulated to the interbedded felsic or carbonate organic-poor laminae as free oil. About 69% of the Fengcheng Formation shale samples in Well MY1 exhibit hydrocarbon charging phenomenon, while 31% of those exhibit hydrocarbon expulsion phenomenon. The reliability of the micro-migration evaluation results was verified by combining the group components based on the geochromatography effect, two-dimension nuclear magnetic resonance analysis, and the geochemical behavior of inorganic manganese elements in the process of hydrocarbon migration. Micro-migration is a bridge connecting the hydrocarbon accumulation elements in shale formations, which reflects the whole process of shale oil generation, expulsion and accumulation, and controls the content and composition of shale oil. The identification and evaluation of shale oil micro-migration will provide new perspectives for dynamically differential enrichment mechanism of shale oil and establishing a “multi-peak model in oil generation” of shale.

Discovery and inspiration of large- and medium-sized glutenite-rich oil and gas fields in the eastern South China Sea: An example from Paleogene Enping Formation in Huizhou 26 subsag, Pearl River Mouth Basin

Based on the practice of oil and gas exploration in the Huizhou Sag of the Pearl River Mouth Basin, the geochemical indexes of source rocks were measured, the reservoir development morphology was restored, the rocks and minerals were characterized microscopically, the measured trap sealing indexes were compared, the biomarker compounds of crude oil were extracted, the genesis of condensate gas was identified, and the reservoir-forming conditions were examined. On this basis, the Paleogene Enping Formation in the Huizhou 26 subsag was systematically analyzed for the potential of oil and gas resources, the development characteristics of large-scale high-quality conglomerate reservoirs, the trapping effectiveness of faults, the hydrocarbon migration and accumulation model, and the formation conditions and exploration targets of large- and medium-sized glutenite-rich oil and gas fields. The research results were obtained in four aspects. First, the Paleogene Wenchang Formation in the Huizhou 26 subsag develops extensive and thick high-quality source rocks of semi-deep to deep lacustrine subfacies, which have typical hydrocarbon expulsion characteristics of “great oil generation in the early stage and huge gas expulsion in the late stage”, providing a sufficient material basis for hydrocarbon accumulation in the Enping Formation. Second, under the joint control of the steep slope zone and transition zone of the fault within the sag, the large-scale near-source glutenite reservoirs are highly heterogeneous, with the development scale dominated hierarchically by three factors (favorable facies zone, particle component, and microfracture). The (subaqueous) distributary channels near the fault system, with equal grains, a low mud content (<5%), and a high content of feldspar composition, are conducive to the development of sweet spot reservoirs. Third, the strike-slip pressurization trap covered by stable lake flooding mudstone is a necessary condition for oil and gas preservation, and the NE and nearly EW faults obliquely to the principal stress have the best control on traps. Fourth, the spatiotemporal configuration of high-quality source rocks, fault transport/sealing, and glutenite reservoirs controls the degree of hydrocarbon enrichment. From top to bottom, three hydrocarbon accumulation units, i.e. low-fill zone, transition zone, and high-fill zone, are recognized. The main area of the channel in the nearly pressurized source-connecting fault zone is favorable for large-scale hydrocarbon enrichment. The research results suggest a new direction for the exploration of large-scale glutenite-rich reservoirs in the Enping Formation of the Pearl River Mouth Basin, and present a major breakthrough in oil and gas exploration.

Carbon Isotopic Behavior During Hydrocarbon Expulsion in Semiclosed Hydrous Pyrolysis of Type I and Type II Saline Lacustrine Source Rocks in the Jianghan Basin, Central China

Abstract Organic carbon isotopic analysis is a significant approach for oil-source correlation, yet organic carbon isotopic behavior during oil expulsion from saline lacustrine source rocks is not well constrained, and this hinders its wide application for fingerprinting oils generated by saline lacustrine source rock. To resolve this puzzle, semiclosed hydrous pyrolysis was conducted on typical saline lacustrine source rocks from the Qianjiang Formation (type I kerogen) and Xingouzui Formation (type II kerogen) sampled in the Jianghan Basin, China, under high-temperature high-pressure conditions (T = 275℃–400℃; P = 65–125 MPa). Experimental results show that there is minor carbon isotopic fractionation (&amp;lt;3‰) between pyrolyzed and nonpyrolyzed retained oil fractions during the main oil generation/expulsion stage of both type I and II source rocks. Carbon isotopic fractionations between expelled and retained oil fractions are also minor (&amp;lt;2‰) during this stage. The δ13C values of retained and expelled oil fractions generated by the type I saline lacustrine source rock correlate positively with the degree of oil expulsion, whereas the influence of oil expulsion on the δ13C values of oil fractions generated by the type II source rock was not consistent. In addition, carbon isotopic analysis also unravels the mixing of oil-associated gases with different maturity levels and/or generated via different processes. Outcomes of this study demonstrate that oil expulsion from type I and II saline lacustrine source rocks cannot be able to result in large-degree carbon isotopic fractionation, indicating that carbon isotopic analysis is a feasible approach for conducting oil-source correlation works in saline lacustrine petroleum systems.

Mineral diagenesis in lacustrine organic-rich shales: Evolution pathways and implications for reservoir characteristics

Porosity in shale reservoirs is profoundly influenced by diagenetic processes that shape the evolution of pore space. In the Songliao Basin, the first member of the Qingshankou Formation (K2qn1) shale serves as a typical lacustrine clay-rich shale oil reservoir. It exhibits variable mineralogy and thermal maturity, with its reservoir quality strongly influenced by these variations. This study integrates microscopic observations, including field emission scanning electron microscopy (FE-SEM), cathodoluminescence (CL), and organic petrology, with bulk rock investigations employing X-ray diffraction (XRD), Rock-Eval pyrolysis, and elemental analysis, to reconstruct the diagenetic pathways leading to changes in porosity. The findings reveal that K2qn1 shale is primarily composed of extrabasinal grain assemblages, such as detrital quartz and clay minerals, with sedimentary organic matter mainly as lamalginite. As maturity exceeds 0.8 %Ro, the presence of authigenic clay minerals, primarily characterized by chlorite, becomes widespread, often associated with bitumen impregnation. Additionally, authigenic dolomite and pyrite form during the synsedimentary to early diagenetic stages. In immature to marginally mature stages (<0.6 % Ro), mechanical compaction is the primary factor leading to porosity reduction. Pores associated with organic matter become visible when maturity reaches the oil window (>0.7 % Ro). At the peak of hydrocarbon expulsion (approximately 1.2 % Ro), a high frequency of organic matter shrinkage pores at interfaces to clay minerals is present, likely playing a significant role in enhancing permeability. Although localized occurrences of dissolution and cementation can be observed, the development of these diagenetic processes is limited and exerts minimal influence on the physical properties of the bulk rock. This study significantly contributes to our understanding of the mechanisms governing diagenetic processes and reservoir evolution in markedly heterogeneous lacustrine shale, considering the diverse origins of grain assemblages.

A tale of two vein types: Bed-parallel fibrous versus blocky filled fractures in organic-rich shales and their overpressured hydrocarbon fluids

Bed-parallel fractures are a common feature of organic-rich shales, and are generally interpreted as records of fluid overpressures due to hydrocarbon generation. However, the textural features of such cemented fractures differ widely, and the relationships between these textures and the vein-forming (fracturing and filling) processes—and, critically, their respective roles in accumulation and migration of hydrocarbons—remain uncertain. Here, we compare the physical conditions and opening mode of bed-parallel cemented fractures that show either fibrous texture indicative of antitaxial growth that kept pace with fracture dilation (commonly referred to as “beef”), or blocky texture indicative of unimpeded syntaxial crystallization into an open, fluid-filled space. Specifically, we analyzed formation conditions of bed-parallel fibrous filled fractures in the Shahejie (Eocene) shales, Bohai Bay Basin, east China, and the bed-parallel blocky filled fractures in the Wufeng-Longmaxi (Ordovician-Silurian) shales, Sichuan Basin, southwest China, to evaluate root causes for the different textures of these cements and discuss their roles in self-sourced hydrocarbon accumulation. We report that fluid inclusions in each filling type show distinct and systematic differences in the magnitude of fluid overpressure during different hydrocarbon generation stages of catagenesis. The formation of bed-parallel fibrous filled fractures, including the initial hydraulic fracturing and subsequent crystallization, occurred during the main stage of liquid hydrocarbon generation (i.e., the oil window) when lithostatic fluid pressures were achieved only sporadically and modest overpressures less than lithostatic usually prevailed. The initial bed-parallel fracturing of blocky fillings, in contrast, occurred during the main gas generation stage (i.e., the gas window), and subsequent blocky crystals precipitated after this stage during uplift after the maximum burial. In this case, super-lithostatic overpressures of the CH4-saturated fluids persisted essentially continuously and actively expanded the fractures at rates that were not met by the crystallizing cements.Such a model for blocky crystallization in an open horizontal space supported by super-lithostatic fluid pressures in petroliferous systems in sedimentary basins, is analogous to some systems in metamorphic rocks including even orogenic gold deposits, and some magmatic settings, especially related to S-type granites where they form greisens and tin-tungsten deposits by blocky filling of wolframite and quartz, and I-type granitoids where coarse muscovite veins occur for example in the deep roots of porphyry copper systems, as well as numerous pegmatites. Some elements that each of these settings share with the shale-hosted, bed-parallel blocky filled fractures, include that they involve in situ fluid production (by metamorphic devolatilization or magmatic degassing) and fluid escape is stifled by low background permeability such that fluid overpressures can build up, at least periodically, to match or exceed the lithostatic load. As a result of these divergent bed-parallel fracture filling processes, the fibrous textures record conditions of modest permeability that favored accumulation of nascent liquid oil, whereas the blocky fracture cements represent open fractures that contributed to permeability and expulsion of gas. We conclude that the fibrous filled fractures record an opening mode that was beneficial for shale oil enrichment, whereas dilation of blocky filled fractures provides important conduits for hydrocarbon expulsion and release of shale gas.

Further study on the genesis of lamellar calcite veins in lacustrine black shale—A case study of Paleogene in Dongying Depression, China

Lamellar calcite veins are prevalent in carbonate-rich, lacustrine dark shale. The formation mechanisms of these veins have been extensively debated, focusing on factors such as timing, depth, material source, and driving forces. This paper examines dark lacustrine shale lamellar calcite veins in the Paleogene strata of Dongying Depression, using various analytical techniques: petrography, isotope geochemistry, cathodoluminescence, inclusion thermometry, and electron probe micro-analysis. Two distinct types of calcite veins have been identified: granular calcite veins and sparry calcite veins. These two types differ significantly in color, grain structure, morphology, and inclusions. Through further investigation, it was observed that vein generation occurred from the shallow burial period to the maturation of organic matter, with a transition from granular calcite veins to sparry calcite veins. The granular calcite veins exhibit characteristics associated with the shallow burial period, including plastically deformed laminae and veins, the development of strawberry pyrite, the absence of oil and gas, weak fractionation in oxygen isotopes, and their contact relationship with sparry calcite veins. These granular calcite veins were likely influenced by the reduction of sulfate bacteria. On the other hand, sparry calcite veins with fibrous grains are antitaxial and closely linked to the evolution and maturation of organic matter. They contain oil and gas inclusions and show a distribution range of homogenization temperature between 90 °C and 120 °C and strong fractionation in oxygen isotopes, indicating formation during the hydrocarbon expulsion period. The carbon isotope analysis of the surrounding rocks and veins suggests that the material for vein formation originates from the shale itself, specifically authigenic micritic calcite modified by the action of methanogens. The opening of horizontal fractures and vein formation is likely driven by fluid overpressure resulting from undercompaction and hydrocarbon expulsion. Veins may form rapidly or through multi-stage composite processes. Early veins are predominantly formed in situ, while late veins are a result of continuous fluid migration and convergence. Furthermore, the veins continue to undergo modification even after formation. This study emphasizes that the formation of lamellar calcite veins in shale is a complex diagenetic process influenced by multiple factors: biology, organic matter, and inorganic processes, all operating at various stages throughout the shale's diagenetic history.

A novel method for quantifying hydrocarbon micromigration in heterogeneous shale and the controlling mechanism

Almost 70 years after shale oil was first studied, “self-souring” was widely regarded as an essential feature of shale oil. Recently, micromigration, which is a bridge connecting hydrocarbon generation, expulsion and enrichment in shale, has been discovered and confirmed as shale oil exploration deepens. However, due to strong heterogeneity, quantitative evaluation of hydrocarbon micromigration in shale remains unclear, making scientific understanding of shale oil enrichment mechanisms highly challenging. Based on the mass balance principle, we provide a quick and novel method to quantify hydrocarbon micromigration with the most commonly available geochemical data from Rock-Eval/total organic carbon (TOC) analysis by subtracting the real hydrocarbon generation potential (HGPR) from the original hydrocarbon generation potential (HGPO). The HGPR is calculated from pyrolysis parameters after light hydrocarbon calibration. Based on a kerogen kinetic theory, the HGPO is restored by utilizing a data-driven model with IBM-SPSS statistics. The results show that the Fengcheng Formation (P1f) shale features medium TOC contents, mixed kerogen types, mature to overmature levels, and high oil contents. Sixty-five percent of the P1f shale samples exhibit hydrocarbon intramicromigration, while the rest exhibit hydrocarbon extramicromigration. Shale oil contents and composition are closely related to hydrocarbon micromigration. The greater the hydrocarbon intramicromigration is, the higher the shale oil content. Micromigration occurs due to differences in hydrocarbon expulsion, pore space, and capillary pressure among shales. This method has a worldwide application for shale oil evaluation, and the findings will help to uncover shale oil differential enrichment mechanisms.

Generation and expulsion of Lower Jurassic hydrocarbon in different source rocks in the Taibei Sag, Turpan-Hami Basin, northwest China

Source rocks in the first (J1s1) and second (J1s2) members of the Lower Jurassic Sangonghe Formation (J1s) in the Taibei Sag, Turpan-Hami Basin, NW China, are shore-shallow lacustrine mudstone and semi-deep to deep lacustrine mudstone. These two sets of mudstones provide an excellent opportunity for investigating the origin and expulsion patterns of hydrocarbon from source rocks under different environments. Through systematic geochemical analysis, including total organic carbon (TOC), Rock-Eval analysis, GC-MS analysis, and major and trace element analysis, the geochemical characteristics and sedimentary environment of the Sangonghe Formation (J1s) source rocks were evaluated. By integrating kerogen kinetics modeling, a more precise assessment of the hydrocarbon generation and expulsion characteristics of the source rocks from both members of the Sangonghe Formation is achieved. The fine-grained sediments of the Sangonghe Formation were formed in a weakly oxidized brackish water body. The J1s1 mudstone was deposited in a shore-shallow lacustrine environment. The repeated river influx increased the input of terrestrial higher plants, which complicated the maceral composition and diluted the abundance of organic matter. The J1s2 source rocks were formed in the semi-deep to deep lacustrine environment during the maximum transgression period with a large thickness and high TOC values, the maceral composition was dominated by a mixed source of aquatic organisms and terrestrial plants. Consequently, the source rocks of J1s2 exhibit higher initial hydrogen index (HI0), hydrocarbon generation potential (Qg) and transformation ratio (Tr) compared to those of the J1s1 source rocks, while the interbedded mudstone with limited thickness in J1s1 exhibits a higher hydrocarbon expulsion efficiency (Re).

Petroleum system of the fold-and-thrust belt of the United Arab Emirates: New insights based on 1D and 2D basin modeling

The hydrocarbon potential of the fold-and-thrust belt (FTB) in the United Arab Emirates (UAE)-Oman mountains has received limited attention to date, leading to a poor understanding of the petroleum systems in this region. Despite the existence of hydrocarbon fields within the FTB, the source rock potential has not been adequately studied. This study aims to address this knowledge gap using 1D and 2D basin modeling approaches to evaluate the petroleum system of the FTB. In addition, gas chromatographs are also used to correlate hydrocarbon occurrences with their source rock. This study's findings identify the Silurian, Upper Cretaceous, Paleocene–Eocene, and Oligocene formations as the primary source rocks in the study area. Silurian shales, encountered in a well in the northern UAE, are currently considered overmature. The Cenozoic source rocks exhibit a spectrum of Total Organic Carbon (TOC) content, ranging from less than 1 to as high as 2 wt%, leading to variable degrees of expulsion efficiency. The maturity of these rocks varies based on their position in relation to the FTB and foredeep, with increasing maturity towards the north. The Upper Cretaceous sequences display low TOC and Hydrogen Index, indicating very low expulsion efficiency. The present-day distribution of maturity is largely influenced by Late Cretaceous and Oligocene–Miocene compressional events that affected the northern and northeastern Arabian Plate. This analysis shows that hydrocarbon expulsion from the Silurian source rocks was initiated during the Middle-Late Jurassic. These hydrocarbons are presumed to have migrated through Upper Permian, Jurassic, and Lower and middle Cretaceous reservoirs. Westward hydrocarbon migration, towards a regional bulge, may have also occurred following compressional events that resulted in lithospheric flexure and formation of the foreland basin. Notably, certain exceptions to migration towards the bulge include structural entrapment of hydrocarbons beneath the main frontal thrust zone of FTB and some structural traps beneath the Lower Fiqa Formation.

Role of magmatism in efficient gas accumulation in Upper Ordovician-Lower Silurian shales in the Yangtze plate, South China: Evidence from the calcite U-Pb ages and gas C-N isotopes

Shale gas exploration in the Yangtze plate has been hindered by strong heterogeneity of gas compositions resulting from magmatism. Borehole core and gas samples from Upper Ordovician-Lower Silurian in the Upper Yangtze plate and the Lower Yangtze plate were analyzed to explore the effects of magmatism on gas accumulation. The analyses included nitrogen isotope of gas, pore structure and X-ray photoelectron spectroscopy of shales, and U-Pb ages of fracture-filling calcites. Our results suggest that magmatism caused the development of micro-fractures in shale reservoirs and accelerated the thermal evolution rate of organic matter. Magmatism in the Upper Yangtze plate predates the peak of gas generation of Upper Ordovician-Lower Silurian shales. Generation and expulsion of hydrocarbon at high temperatures removes 12C from carbon reservoir. After the magmatism, the continuous subsidence of the strata led to further hydrocarbon generation of organic matter. Moreover, the self-sealing property of shale reservoirs were enhanced by the closure of micro-fractures, development of graphite structures, and enrichment of 13C in residual methane, which favor the efficient accumulation of shale gas. Conversely, magmatism in the Lower Yangtze plate occurred after the peak of gas generation of Upper Ordovician-Lower Silurian shales. Magmatism compromised shale gas reservoirs by disrupting sealing conditions, facilitating methane diffusion and atmospheric nitrogen influx. Additionally, overburden pressure led to the collapse of graphitized OM-hosted pores, further inhibiting gas accumulation. Our findings underscore the pivotal role of magmatism in various stages of shale gas accumulation and are critical for exploration strategies in sedimentary basins with prevalent magmatic activities.

The effect of lamina and lithofacies assemblage on molecular maturity of oil in a shale source-rock reservoir

This paper discusses the effect of the source rock–reservoir assemblage and the assemblage–induced variability in hydrocarbon expulsion and the subsequent molecular composition as well as molecular thermal maturity within a hybrid shale system. The characterization work was conducted on lithofacies and microlamina scales using core samples from the Chang 73 sub-member of the Triassic Yanchang Formation in the Ordos Basin, China. Samples were collected from a narrow interval with a depth range of less than 15 m, and the main characterization work was performed by Rock-Eval pyrolysis and GC–MS analysis. The results show that chemical fractionation of preferential expulsion and migration of the saturated fraction exists in the source rock–reservoir assemblages at both the lithofacies and lamina scales. However, the molecular composition behaves differently at the lithofacies and lamina scale's source rock–reservoir assemblages, in which ∑C21−/∑C22+ is higher in lamina scale reservoir but lower in lithofacies scale reservoir. It is assumed that the low-molecular weight n-alkanes also follow molecular fractionation. The lithofacies reservoir has a lower ∑C21−/∑C22+ because of the strong storage capacity of the laminated micro-reservoir within shale, which prevents the newly generated lighter oil from being charged into the lithofacies reservoir. The variation trends of thermal maturity indices Ts/hopane, the relative pregnane content, and TA(I)/TA(I + II) ratios, which have the same chemical basis with ∑C21−/∑C22+, carry the same maturity signature as ∑C21−/∑C22+. The above profile of the molecular composition and molecular-derived thermal maturity parameters indicate that within the short interval of a shale system where no differences in thermal maturity are expected, chain scission reactions and their derived thermal maturity indicators are very sensitive to source rock and reservoir. In addition, within a shale system, oil is more easily to expel out from the organic-rich lithofacies that are interbedded with organic-lean lithofacies. Oil expulsion may promote both chain cracking of oil and subsequently kerogen decomposition. This may provide geological evidence to explain why the frequent-stacking assemblage of source rock and reservoir lithofacies in a hybrid shale system is an ideal target for shale oil exploration.

Expulsion of small molecule hydrocarbons and expansion of nanopores effect in tectonically deformed coal evolution

This work aimed to investigate the impact of the evolution of small molecular structures during the deformation of coal on the constraints imposed on nanoscale pores and adsorption behaviors. Both undeformed and tectonically deformed coal (TDC) from the Huaibei mining area in China were collected for analysis. The pyridine was employed for the extraction of small molecules from coal, which was further complemented by Fourier-transform infrared spectroscopy (FTIR) and low-pressure CO2 and N2 adsorption experiments (LP-CO2/N2AD). The study yielded the following results: (1) Intense tectonic stresses facilitate the removal and recombination of small molecular side chains within the basic structural units (BSU) of coal. As deformation occurs, hydroxyl groups, aliphatic hydrocarbons, C=O, C=C, aromatic hydrocarbons, and 'C' structures tend to accumulate, resulting in an enhanced extraction rate. (2) The deformation process of the coal demonstrates a significant pore-expansion effect, with the most substantial increase observed in micropores (surface area increased by over 70 %), followed by mesopores and macropores. This enlargement facilitates the aggregation of small molecules and gas storage. (3) Intense deformation stages involving shear slip, ductile deformation, and maceral fragmentation result in small molecular fractures and an increased number of micropores. The removal and recombination of I, DOC, and CH2/CH3 within BSUs lead to the formation of larger interconnected pores accompanied by the aggregation of hydroxyl groups (OH–), C=O, C=C, aliphatic hydrocarbons, and 'C' structures. (4) The adsorption capacity of residual coal is lower than that of the raw coal before extraction, indicating that small molecular structures contribute to increased adsorption. This likely plays a significant role in the higher gas content observed in structurally deformed coal. The removal of small molecular structures effectively diminishes the adsorption capacity, providing novel perspectives for coalbed methane development and gas extraction in TDC areas.

Geochemical Characteristics and Hydrocarbon Expulsion Efficiency of Different Types of Shale: Taking Chang 7 Member and Shanxi Formation in Ordos Basin, China, as Examples

Geochemical Characteristics and Hydrocarbon Expulsion Efficiency of Different Types of Shale: Taking Chang 7 Member and Shanxi Formation in Ordos Basin, China, as Examples

Gulong shale oil enrichment mechanism and orderly distribution of conventional– unconventional oils in the Cretaceous Qingshankou Formation, Songliao Basin, NE China

Through the study of organic matter enrichment, hydrocarbon generation and accumulation process of black shale of the Cretaceous Qingshankou Formation in the Songliao Basin, the enrichment mechanism of Gulong shale oil and the distribution of conventional–unconventional oil are revealed. The Songliao Basin is a huge interior lake basin formed in the Early Cretaceous under the control of the subduction and retreat of the western Pacific plate and the massive horizontal displacement of the Tanlu Fault Zone in Northeast China. During the deposition of the Qingshankou Formation, strong terrestrial hydrological cycle led to the lake level rise of the ancient Songliao Basin and the input of a large amount of nutrients, resulting in planktonic bacteria and algae flourish. Intermittent seawater intrusion events promoted the formation of salinization stratification and anoxic environment in the lake, which were beneficial to the enrichment of organic matters. Biomarkers analysis confirms that the biogenic organic matter of planktonic bacteria and algae modified by microorganisms plays an important role in the formation of high-quality source rocks with high oil generation capability. There are four favorable conditions for the enrichment of light shale oil in the Qingshankou Formation of the Gulong Sag, Songliao Basin: the moderate organic matter abundance and high oil potential provide sufficient material basis for oil enrichment; high degree of thermal evolution makes shale oil have high GOR and good mobility; low hydrocarbon expulsion efficiency leads to a high content of retained hydrocarbons in the source rock; and the confinement effect of intra-layer cement in the high maturity stage induces the efficient accumulation of light shale oil. The restoration of hydrocarbon accumulation process suggests that liquid hydrocarbons generated in the early (low–medium maturity) stage of the Qingshankou Formation source rocks accumulated in placanticline and slope after long-distance secondary migration, forming high-quality conventional and tight oil reservoirs. Light oil generated in the late (medium–high maturity) stage accumulated in situ, forming about 15 billion tons of Gulong shale oil resources, which finally enabled the orderly distribution of conventional–unconventional oils that are contiguous horizontally and superposed vertically within the basin, showing a complete pattern of “whole petroleum system” with conventional oil, tight oil and shale oil in sequence.

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.

Mass balance of generation, retention, and production for the Wolfcamp-sourced hydrocarbon in the Permian Delaware Basin: Insight on remaining recoverable resource and expulsion efficiency

Detailed quantification of basin-wide hydrocarbon (HC) masses from generation to production is necessary for a quantitative petroleum system analysis, and ultimately, for accurate resource estimation. Such quantified HC masses must be balanced following the fundamental laws of mass conservation. Mass balance is particularly important for unconventional-conventional petroleum systems in which expulsion efficiency (EE) is a critical parameter defining HCs in place, within the source rock (SR) interval and outside. This study performs an HC mass balance assessment aiming primarily to obtain insights on the remaining recoverable and EE, applied to the Wolfcamp Formation (Fm) in the Permian Delaware Basin. Calculated generated HC volumes from the Wolfcamp Fm based on the assumed 3D geologic model and p90/50/10 SR properties are 878/2107/4514 billion barrels of oil equivalent (BBOE). The mass balance is performed with three calculation scenarios: (1) inversion of EE (based on the United States Geological Survey [USGS]-estimated remaining recoverable HC in the Wolfcamp Fm), (2) forward calculation with multiple assumed EE, and (3) HC expulsion simulation. The mass balance with the inversion of EE indicates that the p90/50/10 of 58%/62%/69% overall EE is required for the Wolfcamp Fm to achieve the USGS-estimated remaining recoverable HC of 35/78/140 BBOE. Both mass balance with forward calculation and expulsion simulation predict overall lower p90/50/10 EE of 50% and 30%/56%/75%, respectively, thus resulting in higher than the USGS-estimated remaining recoverable HC in the Wolfcamp Fm in most scenarios. All of the mass balance calculations are also consistent with the interpretation of Wolfcamp unconventional play as a self-sourced play. This workflow is an efficient tool for taking a quantitative look at the petroleum system, especially related to the possibilities of generated HC distribution in the system. The calculated mass balance can serve as a reference in modeling unconventional systems and resources.

Hydrogen's organic genesis

Natural hydrogen exploration has been restricted in scope due to the predominance in thinking that various rock interactions with water in cratonic settings offer the best natural hydrogen sources. The limited exploration findings in these areas in conjunction with advances in the understanding of hydrogen generation via anthropogenic methods suggest that other source alternatives such as organic hydrogen generation need to be revisited. The ideas on the maturation of organic matter may need to be reassessed with respect to hydrogen. It is suggested that an overlapping thermo-catalytic set of processes occurs to produce hydrocarbons and hydrogen. Initially clay reacts with kerogen producing hydrocarbons, hydrogen and amorphous carbon, the alteration of clays releasing hydronium. During the late catagenic phase thermo-catalysis of hydrocarbons by amorphous carbon create shorter chained hydrocarbons and hydrogen whilst amorphous carbon degrades to carbon black. During expulsion of hydrocarbons and hydrogen the permeability of the source rock becomes more heterogeneous, isolating some reactants creating pyrobitumens and other carbonaceous materials. At higher temperatures during metagenesis isolated pyrobitumens and other carbonaceous materials in shales are turned to graphite releasing gaseous hydrocarbons and eventually diatomic hydrogen in a second phase by thermo-catalytic reaction with carbon black. This matches the temperatures and results at which laboratory experiments and petrochemical processes used to generate hydrogen are observed. The current conclusion of the hydrocarbon generation story at the methane preservation limit should be recognized as the start of hydrogen generation and graphitization as the end of the process. Instead of basin exploration focused solely on hydrocarbons and stopping due to concerns of over maturity of source and reservoir, exploration may continue deeper in search of organic hydrogen. This should be noted as a primary hydrogen generation mechanism globally and provide a suitable model to aid hydrogen exploration and lead the energy transition into a hydrogen economy.

Numerical modeling of microfracturing and primary hydrocarbon expulsion in the Jurassic Lower Tuwaiq Mountain Shale: A conceptual framework

Numerical modeling of microfracturing and primary hydrocarbon expulsion in the Jurassic Lower Tuwaiq Mountain Shale: A conceptual framework

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.

Shale oil enrichment evaluation and production law in Gulong Sag, Songliao Basin, NE China

Based on the results of drilling, tests and simulation experiments, the shales of the Cretaceous Qingshankou Formation in the Gulong Sag of the Songliao Basin are discussed with respect to hydrocarbon generation evolution, shale oil occurrence, and pore/fracture evolution mechanism. In conjunction with a substantial amount of oil testing and production data, the Gulong shale oil enrichment layers are evaluated and the production behaviors and decline law are analyzed. The results are drawn in four aspects. First, the Gulong shales are in the stage of extensive hydrocarbon expulsion when Ro is 1.0%–1.2%, with the peak hydrocarbon expulsion efficiency of 49.5% approximately. In the low–medium maturity stage, shale oil migrates from kerogen to rocks and organic pores/fractures. In the medium–high maturity stage, shale oil transforms from adsorbed state to free state. Second, the clay mineral intergranular pores/fractures, dissolution pores, and organic pores make up the majority of the pore structure. During the transformation, clay minerals undergo significant intergranular pore/fracture development between the minerals such as illite and illite/smectite mixed layer. A network of pores/fractures is formed by organic matter cracking. Third, free hydrocarbon content, effective porosity, total porosity, and brittle mineral content are the core indicators for the evaluation of shale oil enrichment layers. Class-I layers are defined as free hydrocarbon content equal or greater than 6.0 mg/g, effective porosity equal or greater than 3.5%, total porosity equal or greater than 8.0%, and brittle mineral content equal or greater than 50%. It is believed that the favourable oil layers are Q2–Q3 and Q8–Q9. Fourth, the horizontal wells in the core area of the light oil zone exhibit a high cumulative production in the first year, and present a hyperbolic production decline pattern, with the decline index of 0.85–0.95, the first-year decline rate of 14.5%–26.5%, and the single-well estimated ultimate recovery (EUR) greater than 2.0×104 t. In practical exploration and production, more efforts will be devoted to the clarification of hydrocarbon generation and expulsion mechanisms, accurate testing of porosity and hydrocarbon content/phase of shale under formation conditions, precise delineation of the boundary of enrichment area, relationship between mechanical properties and stimulated reservoir volume, and enhanced oil recovery, in order to improve the EUR and achieve a large-scale, efficient development of shale oil.