Hydrocarbon Generation Process Research Articles

Hydrocarbon Generation Characteristics of Source Rocks from Different Saline Environments in the Dongpu Depression, Bohai Bay Basin, China

AbstractThe Dongpu Depression is a secondary salt‐bearing tectonic unit in the Bohai Bay Basin, eastern China. The depositional environment of this depression regarding its Paleogene strata is clearly different in plane, including the saltwater environment (SE) in the north, the freshwater environment (FE) in the south and the brackish water environment (BE) in the middle. The result of oil and gas exploration in the Dongpu Depression shows that more than 90% of the proven oil reserves are distributed in the northern saltwater environment. Previous studies indicate that the organic geochemistry characteristics and the hydrocarbon generation capacity of the source rocks are very clearly diverse under different environments, which results in the significant differences in the proved reserves between the north and the south. In order to further explore the differences in the hydrocarbon generation capacity of the source rocks under distinct depositional environments and the mechanism of their occurrence, three samples from different depositional environments (W18‐5 for SE, H7‐18 for BE, CH9 for FE) were used for confined gold tube pyrolysis experiments. The results show that the CH4 yields of W18‐5, H7‐18 and CH9 increase with increasing temperature, the maximum yields being 405.62 mg/g TOC, 388.56 mg/g TOC and 367.89 mg/g TOC, respectively. The liquid hydrocarbon yields of W18‐5, H7‐18 and CH9 firstly increase with increasing temperature and then decrease after the critical temperatures. The maximum yields of C6–14 are 149.54 mg/g TOC, 140.18 mg/g TOC and 116.94 mg/g TOC, the maximum yields of C14+ being 852.4 mg/g TOC, 652.6 mg/g TOC and 596.41mg/g TOC, respectively for W18‐5, H7‐18 and CH9. To summarize, the order of hydrocarbon potential from high to low is W18‐5, H7‐18 and CH9. On this basis, through analyzing the influencing factors of hydrocarbon differences, this paper reveals that the saltwater environment is characterized by 4 factors: higher salinity, halophilic algae, high paleo‐productivity and a strongly reducing environment, which are beneficial to the enrichment of organic matter and lead to the formation of high levels of sapropelite and exinite. According to the variation of oil and gas components in the pyrolysis experiments, the hydrocarbon generation process is divided into three stages: kerogen cracking, oil cracking and C2–5 cracking. Combined with hydrocarbon generation characteristics and stages, the evolutionary model of hydrocarbon generation for source rocks under different environments is established.

Types of biogenic quartz and its coupling storage mechanism in organic-rich shales: A case study of the Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation in the Sichuan Basin, SW China

Biogenic quartz in the Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation (Wufeng– Longmaxi) shale layers in the Sichuan Basin and its periphery is qualitatively analyzed and quantitatively characterized by organic petrologic, mineralogic, and geochemical methods to find out the coupling effect between organic matter and quartz. (1) There are two types of biogenic quartz in the shale layers: Type I quartz is submicron quartz appearing in clusters around the organic matter. Type II quartz is in nano-scale grain size and floats in spherical shape on organic matter, with grains in point-to-point or surface-to-surface contact; this type of quartz is mainly biologic origin and slightly affected by hydrothermal activity in local parts. (2) The reservoirs in the Wufeng–Longmaxi formations is consistent in distribution with biogenic silica content in them, and mainly concentrated at the bottom of the Wufeng–Longmaxi formations, and is thinner in the Changning and Weiyuan regions, while thicker in the Fuling region. (3) The biogenic quartz in the Wufeng–Longmaxi shale worked through the entire evolution process of hydrocarbon generation. The presence of biogenic quartz can enhance the development of organic matter pores and microcracks, and can effectively preserve the organic matter pores and residual intergranular pores, forming “biological silicon intergranular pores, organic pores and micro-fractures”. This would benefit later hydraulic fracturing and result in high production/stable production of well. The coupling effect between biogenic quartz development and organic matter evolution and hydrocarbon generation is a critical factor for high-quality shale reservoir development.

Combination of basin modelling and carbazoles to investigate secondary oil migration pathways in the Dongying depression of the Bohai Bay Basin, China

This study investigates pathways of secondary oil migration, which lead to oil accumulations in the Dongying Depression with both geochemistry and basin modelling techniques. Modelling of oil migration pathways was conducted for the third and fourth members (Es3 and Es4) of the Shahejie Formation, including reconstructions of thermal maturation and hydrocarbon generation processes, which were supported by parameters of carbazoles and further reinforced by distributions of oil wells and fields. The lower interval of the Es3 source rock was deposited under a sub-oxic, freshwater environment, while the upper interval of Es4 source rock was deposited under an anoxic, hypersaline environment. The investigated 38 oil samples are classified into three groups based on oil-source correlation in the Dongying Depression as the Es3-derived oils, the Es4-derived oils, and mixed oils of Es3 and Es4 in their origin. The influence of maturity variations and source facies on carbazole parameters of the non-biodegraded oils can be ignored. Carbazole parameters can be used to trace migration distances of oil for each group of oil. Eight migration pathways are determined based on the analysis of carbazole parameters. Oil migration pathways inferred from basin modelling are consistent with those determined by carbazoles. Our results suggest two favourable oil accumulation areas along the migration pathways in the Es4 member of the Dongying Depression.

Pore formation and evolution of organic-rich shale during the entire hydrocarbon generation process: Examination of artificially and naturally matured samples

Shale pore type and variation have significant influences on natural gas storage and are of vital importance for shale gas resource evaluation. To better understand the formation and evolution of shale pores during hydrocarbon generation process, organic geochemistry, X-ray diffraction, field emission scanning electron microscopy (FE-SEM), and low-pressure nitrogen gas adsorption (N2GA) were applied to samples created by thermal simulation and to naturally evolved samples of the Upper Permian Dalong Formation in the northwestern Sichuan Basin. The results show that the development of organic matter (OM) pores is controlled by kerogen type and thermal maturation level and begins at equivalent vitrinite reflectance (eqvRo) value of 0.91%. Two types of OM pores are developed during OM evolution stage, as bubble pores that are formed at the oil window stage and spongy pores which occcur at the dry gas stage. Maximum pore volume, particularly mesopore volume, occurs within two opportune development periods with the corresponding eqvRo values of 1.11–1.53% and 2.5–2.9%, respectively. The periods are known to be the two peak stages of shale pore development. The first peak corresponds to the late oil generation stage, and the second corresponds to the cracking peak of extractable OM to gas, during which numerous OM micropores and mesopores are generated. OM pore generation is generally resulted from OM decomposition, and pore structure parameters exhibit significant positive correlations with OM reduction for simulated samples. For naturally matured samples, TOC content is positively correlated with pore structures. Extractable OM generated from primary kerogen fills OM pores and mineral-related pores and further reduces shale pore volume. In terms of analysis on naturally matured samples with similar maturities, OM pores in type II1 kerogen are inferior to those in type I kerogen but more developed than those in type III kerogen. Shale pore evolution is also controlled by diagenesis. Compaction and cementation have adverse effects on shale pore preservation during early and late diagenesis stages, which leads to a significant decrease in shale pore volume, particularly that of mesopores. It should be noted that OM pores are better developed and preserved even when the eqvRo value exceeds 3.25%, which is of vital importance for extending the field of shale gas exploration of over-mature shale reservoirs.

Combining Source Rock Kinetics and Vitrinite Reflectance in Source Rock Evaluation of the Bakken Formation, Williston Basin, USA.

The elements of Bakken Petroleum System consist of two source rocks with high underlying burial depths for significant hydrocarbon generation. However, this deep hydrocarbon generation process is dependent on its kinetic properties, thermal maturity, and geochemical properties. The statistical compensation effect is a complicating factor in the kinetic analyses of the Bakken Formation. In this study, we experimentally determined the kinetics of the Bakken formation source beds, observed the presence of the residual compensation effect, and numerically established a correlation between the kinetic parameters, thermal maturity indices (Tmax), and the vitrinite reflectance (VRo) and bitumen reflectance (BRo). First, we conducted source rock analysis to determine kinetic properties and the organic geochemical assays of reactive kerogen in the Bakken source beds. Finally, we incorporated previous established studies to generate numerical correlation for Tmax in terms of VRo and BRo reflectance. Our kinetic results show evidence of the residual compensation effect in the Bakken Formation when samples are repeatedly analyzed. The simultaneous linear expression of the residual compensation effect and the regression analysis of the solutions to the Kissinger equation for heating rate, yielded a kinetic parameter solution that correlates with Tmax. Furthermore, recalculated Tmax values established a correlation between the kinetic parameters, Tmax, VRo, and BRo. The application of state-of-the-art numerical correlations to measure subsurface kinetics, source rock richness, and burial-depth temperatures will enhance the accuracy of reservoir exploration and hydrocarbon production within the Bakken Formation.

A Study on the Heterogeneity Characteristics of Geological Controls on Coalbed Methane Accumulation in Gujiao Coalbed Methane Field, Xishan Coalfield, China

Commercial exploration and exploitation of coalbed methane (CBM) in Gujiao coalbed methane (CBM) field, Xishan coalfield, have rapidly increased in recent decades. The Gujiao CBM field has shown strong gas distribution heterogeneity, low gas content, and wide distribution of wells with low production. To better understand the geological controlling mechanism on gas distribution heterogeneity, the coal reservoir evolution history and CBM accumulation process have been studied on the base of numerical simulation work. The burial history of coal reservoir can be classified into six stages: shallowly buried stage; deeply buried stage; uplifting stage; short-term tectonic subsidence stage; large-scale uplifting stage; and sustaining uplifting and structural inversion stage. Mostly, coal seams have experienced two-time thermal metamorphisms with twice hydrocarbon-generation processes in this area, whereas in the southwest part, the coal seams in there suffered three-time thermal metamorphisms and hydrocarbon-generation processes. The critical tectonic events of the Indosinian, Yanshanian, and Himalayan orogenies affect different stages of the CBM reservoir accumulation evolution process. The Indosinian orogeny mainly controls the primary CBM generation. The Yanshanian orogeny dominates the second and third gas generation and migration processes. The Himalayan orogeny mainly affects the gas dissipation process and current CBM distribution heterogeneity.

Investigation on chemical structure and hydrocarbon generation potential of lignite in the different pretreatment process

Combined with the analysis of FT-IR, lignite was treated by conventional flue gas (FTD), hydrothermal (HTD), and tetralin solvent thermal pretreatment (TTD) at different temperatures. A series of infrared parameters were obtained, and the evolution of chemical structure and hydrocarbon generation potential for lignite were studied. The results showed that the HTD, TTD and FTD processes reduce the water holding ability of lignite, and in general, the order of the dewatering effect is HTD > TTD > FTD. The FTD process promotes more efficient the increase of carbon content and energy density, and the upgraded coal likely to be suitable as power fuel. For lignite, the hydrogen-enrichment parameters are not an effective means to predict hydrocarbon generation potential, because the structural characteristics are not dominant during the process of hydrocarbon generation. The aromatization occurred during the FTD, HTD, and TTD processes, and has an important contribution towards enhancing the aromaticity. The order of aromatization of lignite for the three pretreatment processes is FTD > HTD > TTD. Conversely, the upgraded coal achieved by TTD process maintains the relative integrity of organic structure and high reactivity of lignite. HTD and TTD processes improve the H/C atom ratio of lignite, which provides more hydrogen free radicals to produce chemical products. Thus, the upgraded coal is suitable as feedstock of coal pyrolysis and liquefaction. Moreover, the upgraded coal achieved by TTD process retains high reactivity and relative integrity of organic structure compared with the HTD process. Thus, it has a much better chance of producing value-added chemical products.

Orderly coexistence and accumulation models of conventional and unconventional hydrocarbons in Lower Permian Fengcheng Formation, Mahu sag, Junggar Basin

Abstract By using the latest geological, seismic, drilling and logging data, this article studies the basic conditions for the formation of the total petroleum system and the orderly coexisting characteristics and accumulation models of conventional & unconventional reservoirs in the Lower Permian Fengcheng Formation in the Junggar Basin. Controlled by thermal evolution, hydrocarbon generation and expulsion process of the high-quality source rocks in alkaline lake as well as the characteristics of multi-type reservoirs (conglomerate, sandstone, dolomite and shale), conventional structure-lithologic reservoirs and tight oil and shale oil reservoirs controlled by source-reservoir structure have been formed. On the plane, mature conventional reservoirs, medium-high mature tight oil, and medium-high mature shale oil reservoirs coexist orderly from the slope area around Mahu sag to the sag. Based on the orderly coexisting characteristics of conventional and unconventional reservoirs in the Fengcheng Formation, it is clear that oil and gas in the Fengcheng Formation accumulate continuously over a large area in three accumulation models: integrated source-reservoir, source-reservoir in close contact, and separated source-reservoir model. The three accumulation models differ in relationship between source-reservoir structure, reservoir lithology and spatial distribution, hydrocarbon migration, oil and gas type. It is pointed out that the conventional & unconventional oil and gas should be explored and developed as a whole to achieve an overall breakthrough of the total petroleum system. This study is expected to enrich the geological theory of oil and gas enrichment in continental basins and to provide an analogy for exploration and research in other hydrocarbon-rich sags.

Coevolutionary Dynamics of Organic-Inorganic Interactions, Hydrocarbon Generation, and Shale Gas Reservoir Preservation: A Case Study from the Upper Ordovician Wufeng and Lower Silurian Longmaxi Formations, Fuling Shale Gas Field, Eastern Sichuan Basin

Shale gas deposits are self-sourced, self-accumulating, and self-preserving in the Upper Ordovician Wufeng Formation and Lower Silurian Longmaxi Formation of the Fuling Shale Gas Field in the eastern Sichuan Basin. They were both seemingly mixed by secondary oil cracking and kerogen cracking gases during the high maturation window. The reservoir space primarily consists of mineral pores and organic matter (OM) pores, and the shale gas was mainly trapped by a high-pressure system. In this study, the Fuling O3w-S1l Shale Gas Field in the eastern Sichuan Basin was used as a case study to discuss the coevolutionary process and organic-inorganic interactions of hydrocarbon generation, accumulation, and preservation. The results indicate that the processes and mechanisms of organic-inorganic interactions and coevolution of hydrocarbon generation and reservoir preservation are quite different among the shale graptolite zones (GZ) with respect to hydrocarbon generation, types and characteristics of shale gas reservoirs, seal characteristics, and their spatiotemporal relations. In the WF2-LM4 GZ, the favorable OM, biogenic authigenic quartz and organic-inorganic interactions are highly coupled, leading to the high level of coevolution demonstrated within the field, as well as to the favorable conditions for shale gas accumulation. Conversely, the overlying LM5-LM8 GZ seemingly exhibits early densification and late charge and has a reverse mode of reservoir development (i.e., low degree of coevolution). These two coevolutionary processes were conducive to the development of a high degree of spatiotemporal matching between the reservoir (i.e., WF2-LM4 GZ) and the seal (i.e., LM5-LM8 GZ). This is due to underlying differences in their coevolutionary histories. The synthetic work presented here on the coevolutionary processes and mechanisms of formation for organic-inorganic interactions and hydrocarbon generation and reservoir preservation reveals insights into the driving mechanisms of shale gas enrichment, providing a basis for effectively predicting favorable enrichment intervals for shale gas worldwide.

Phase characteristics of hydrocarbons generated from different types of kerogen at different maturity levels in closed system

For studying phase characteristics of hydrocarbons generated from different types of kerogen at different maturity levels, pyrolysis data of MM type-I and II kerogen (Maoming oil shale) and Coal type-III (Turpan coal) were collected and used for building phase models by PVT simulation technology. Then, phase diagrams, as well as physical properties (GOR, density, and viscosity) related to different kerogen types and along with maturity history, were output and carried out for comparative studies. The results show that three different types of kerogen perform different hydrocarbon generation processes, which form various yields and hydrocarbon compositions, leading to different petroleum types and diverse phase characteristics. The GORwt and the relative proportion of light and heavy hydrocarbons are two critical factors to shape the phase envelopes. The nature of kerogen with different maturity processes controls the changes of hydrocarbon compositions to form diverse phase characteristics. Their phase diagrams and physical properties on the ground conditions confirmed the different maturity ranges of black oils, light oils, and gas condensates generated by kerogen, respectively. Our study clarified that all types of kerogen at early generations (relatively low maturities) extensively generate black oils even though phase characteristics are different. In contrast, at a relatively high maturity by considering yields and expulsions of hydrocarbons, the MM type-II kerogen prefers to generate light oils, while the MM type-I kerogen prefers to generate black oils and the Coal/type-III kerogen prefers to generate gas condensates.

Modeling hydrocarbon generation of the Wenchang formation in Zhu III Sub-basin, Pearl River Mouth Basin South China by confined pyrolysis

The Zhu III Sub-basin is an important petroliferous basin in the Pearl River Mouth Basin. To obtain the evolution of liquid and gaseous hydrocarbon of the kerogen in the Zhu III Sub-basin, a sample of Wenchang formation in the sub-basin was used in the confined pyrolysis experiments in the present study. The results show that the kerogen has very good hydrocarbon generation potential, with the maximum ΣC1-C5 and ΣC6+ yields of 999.69ml/g·TOC and 808.71mg/g·TOC, respectively, at 600°C. To further study the process of the process of hydrocarbon generation in geological conditions of the sub-basin, the burial, temperature, and thermal history are reconstructed. The kerogen of Wenchang formation started to generate oil and gas at 37Ma and 25Ma, respectively. The transformation ratio value of ΣC6+ reached 100% at 14.45Ma, and that of ΣC1-C5 reached 37%, mainly ΣC2-C5, at present.

Oil shale in situ catalytic conversion over clin/SBA-15 composites under subcritical water

The massive reserves of oil shale in China offer the potential to lessen energy dependence on conventional sources. A novel oil shale in situ upgrading process over mineral-based clin/SBA-15 catalysts has been proposed, and catalytic pyrolysis behavior was intensively studied. Clinoplilolite was chosen for clin/SBA-15 preparation. The apparent activation energy Ea of hexadecane cracking on clin/SBA-15(3.0) is 90.37 kJ/mol that is 35 kJ/mol less than that of thermal cracking. DSC curves of n-C16 conversion under 3 MPa N2 reveals that the cracking peak temperature was declined to 365 °C and 372 °C from 417 °C (thermally) on clin/SBA-15 and kaolin/SBA-15, respectively. The extracted kerogen was converted at 280 °C with a biphasic solvent (water and decalin) to mimic the hydrocarbon generation process, and the products were mainly concentrated in C9, C10 and C11. Oil shale conversion was carried out at 280 °C under subcritical water. Non-catalytic converted products mainly contains hydrocarbons (34.01 %), long-chain fatty acids (esters), alcohol, and ketones. Catalytically produced oil have a strongly aliphatic nature, and the hydrocarbon yield is up to 70.50 % for clin/SBA-15. The clin/SBA-15 played a remarkable role on H/C ratio rising (1.98–2.08) and O/C ratio declining (0.10 to 0.04) because of the catalytic decarboxylation. Clin/SBA-15 showed no activity decay on seven-day oil shale aqueous conversion test.

Natural gas accumulation processes of tight sandstone reservoirs in deep formations of Songliao Basin, NE China

The deep formations (underlying strata of the 3rd Member of Quantou Formation, Upper Cretaceous) in Songliao Basin possess a large natural gas potential, with a proven reserve of more than 200 × 109 m3 (706.3bcf). However, due to deep burial depth, multiple tectonic evolutions, and sets of source rocks, complex gas accumulations and different gas reservoir types developed, which may seriously restrict the natural gas exploration and target selection. This study focuses on the hydrocarbon generation, porosity evolution, and hydrocarbon accumulation processes of the tight sandstone gas (TSG) reservoir in the Cretaceous Shahezi Formation. 1) The timing and cumulative amounts of hydrocarbon generation were ascertained, with the Huoshiling being 143–10 Ma and 108.00 mg/g TOC and the Shahezi being 122–44 Ma and 30.00 mg/g TOC, respectively. 2) The mean original porosity of the Shahezi sandstone was 23.11%, and experienced the porosity decreasing of compaction (avg. = 12.57%) and cementation (avg. = 7.07%), and porosity increasing of dissolution (avg. = 3.25%), and the average present porosity is 6.72%. The sandstone densification (porosity <10%) occurred in the late period of Early Cretaceous (~115–105 Ma). 3) Four main stages of hydrocarbon accumulation in the K1sh occurred: I) Early oil accumulation stage (128–114 Ma)，corresponding to the 1st episode of charging; II) Middle oil and gas accumulation stage (111–90 Ma), corresponding to the 2nd episode of charging; III) Late gas accumulation stage (77–67 Ma), corresponding to the 3rd episode of charging; and IV) Adjustment stage (63 Ma–present), corresponding to the uplift stage. The 2nd and 3rd stages were the main gas accumulation stages. 4) Two types of tight sandstone gas reservoirs developed in the K1sh: I) tight conventional gas, and II) tight deep gas. The tight deep gas reservoirs, with favorable potentials, are the main exploration targets in the Shahezi Formation of Songliao Basin.

Study on the characterization of pore structure and main controlling factors of pore development in gas shale

Shale has a complex pore structure, which leads to complex petrophysical characteristics. The porosity, pore type, pore size, pore volume, TOC, and other petrophysical parameters of shale all affect the shale gas content. Therefore, using multiple methods to jointly characterize the pore structure of shale with different gas content and study on the main controlling factors of pore development have an important guiding role in the exploration and development of shale gas. In this study, we carry out gas shale samples in different areas. The samples collected from wells in the Sichuan Basin have high gas content, collected from wells near the Pengshui, and Tongren areas have medium gas content and collected from wells near the Guiyang area have low gas content. Shale in these areas with different gas production has been characterized, by the integration of geophysical and petrophysical data, in terms of pore type and pore connectivity, including X-ray diffraction, low-field Nuclear Magnetic Resonance (NMR), low-pressure N2 and CO2 adsorption isotherms, porosity, permeability, thin-section observations, scanning electronic microscopy (SEM) and mercury injection capillary pressure (MICP) measurement. The results show that the pore types are clay mineral intercrystalline pores and intergranular pores, rock skeleton mineral pores, organic pores, and micro-fractures. The high gas-bearing shale has a small pore size, a large specific surface area, and pore volume, and the T2 distribution is bimodal, with a peak value around 1 ms. It shows that micropores and mesopores are widely developed in high gas-bearing shale, which provides the main place for adsorbing gas, especially shale with high TOC content. During the hydrocarbon generation process, a large number of organic pores favorable for gas adsorption will be produced. The low gas-bearing shale has a large pore size, a small specific surface area, and pore volume, and the T2 distribution presents a bimodal shape with a wider peak and the lowest spectral value. This shows that low gas-bearing shale mainly develops macropores and micro-fractures, and the pore connectivity is good, especially the interconnection between small pores and fractures, which leads to gas escape. In the high gas-bearing samples, bone needles and radiolaria are distributed in large quantities, and the silicon content of biological sources is high, which provides a lot of organic matter. In the low gas-bearing samples, the horizontal layer is not developed and the mineral particles are evenly distributed.

Differential evolution and the influencing factors of low-maturity terrestrial shale with different types of kerogen: A case study of a Jurassic shale from the northern margin of Qaidam Basin，China

The Jurassic terrestrial shale on the northern margin of Qaidam Basin is characterized by high contents of organic matter but low maturity resulting in a lack of further research on shale gas in this area. To better understanding the shale gas potential of organic matter with different types, we conducted thermal maturity experiment of hydrocarbon generation from different kerogen types of low-mature shales under closed conditions. The results show that type II and type III kerogen have experienced similar hydrocarbon generation stages, but they differ in the hydrocarbon generation interval and evolution process between liquid hydrocarbon and gaseous hydrocarbon. Compared with Type III kerogen, type II kerogen is characterized by a low initial temperature at each evolutionary stage and wide temperature range, which caused the overall evolution of type III Kerogen lagged behind that of type II kerogen. The differential evolutions mainly result from the differences in hydrocarbon generation mechanism, hydrocarbon generation activation energy and kerogen macerals among different kerogen types. We summarized the evolution model of type II and type III Kerogen based on the characteristics of kerogen in hydrocarbon generation, carbon isotope change, pore development and other aspects. This work can provide theoretical and data support for reconstructing the hydrocarbon generation process of terrestrial shale gas, investigating the hydrocarbon generation mechanism, and predicting the hydrocarbon resources of terrestrial shale oil and gas on the northern margin of Qaidam basin and even China.

Diversified roles of mineral transformation in controlling hydrocarbon generation process, mechanism, and pattern

Organic matter (OM) is intimately associated with minerals in clay-rich mudstones, leading to widespread organic-mineral interaction during hydrocarbon generation in argillaceous source rocks. What we are concerned is the effects of the different mineral properties on hydrocarbon generation process and mechanism during mineral transformation. In this way, pyrolysis experiments with smectite-octadecanoic acid complexes (Sm-OA and Ex-Sm-OA) were conducted to analyze correlation of mineralogy and pyrolysis behaviors. Based on organic-mineral interaction, hydrocarbon generation process was divided into three phases. At 200–300 ​°C, collapse of smectite led to desorption of OM, resulting in high yield of resin and slight increase in saturates. Subsequently, enhanced smectite illitization at 350–450 ​°C was accompanied with large amounts of saturates and a mere gaseous hydrocarbon. Featured by neoformed plagioclase, ankerite, and illite, 500 ​°C saw plenty of asphaltene and methane-rich gaseous hydrocarbons, revealing cracking reactions of OM. Noteworthy is that saturated and gaseous hydrocarbons in Ex-Sm-OA were considerably more than that in Sm-OA during second and third phases. Quantitative calculation of hydrogen revealed organic hydrogen provided by cross-linking of OM could not balance hydrogen consumed by cracking reactions, but supply of inorganic hydrogen ensured cracking could readily occur and consequently greatly promoted hydrocarbon generation. Further investigating characteristics of mineralogy and pyrolytic products, as well as effects of solid acidity on hydrocarbon generation, we concluded desorption of OM and decarboxylation promoted by Lewis acid were dominated at 200–300 ​°C, resulting in low-degree hydrocarbon generation. While high yield of saturated and gaseous hydrocarbons in second and third phases, together with occurrence of ankerite, indicated predominance of decarboxylation and hydrogenation promoted by Lewis and Brønsted acid, respectively. Variations in organic-mineral interactions indicated (1) the controls of mineral transformation on hydrocarbon generation process and mechanism include desorption, decarboxylation, and hydrogenation reactions; (2) clay minerals acted as reactants evolving together with OM rather than catalysts. These findings are profoundly significant for understanding the hydrocarbon generation mechanisms, organic-inorganic interactions, and carbon cycle.

Hydrocarbon generation from lacustrine shales with retained oil during thermal maturation

Thermal maturation in the shale oil/gas system is inherently complex due to the competitive interplays between hydrocarbon generation and retention processes. To study hydrocarbon generation characteristics from shales within different stages of thermal maturation under the influence of retained oil, we performed Micro-Scale Sealed Vessels (MSSV) pyrolysis on a set of artificially matured lacustrine shale samples from the Shahejie Formation in the Dongpu Depression in Bohai Bay Basin, China. Experimental results show that hydrocarbon yields of shale samples with or without retained oil at various thermal maturities follow different evolution paths. Heavy components (C15+) in samples crack at high temperatures and generally follow a sequence, where they first transform into C6–14 then to C2–5 and C1. Methane accounts for most of the gaseous products at high temperatures in all samples, with different origins. The cracking of C2–5 is the main methane-generating process in samples with retained oil, whereas the source of methane in samples without retained oil is kerogen. In the studied shales, retained oils at early-mature stage retard the transformation of liquid to gaseous hydrocarbon and prompt the cracking of C2–5 to C1 to some extent. TSR reaction related to gypsum in the studied samples is the primary reason that can explain the loss of hydrocarbon yields, especially at high temperatures. In addition, transformation of volatile hydrocarbons to gas and coke also accounts for the loss of generated hydrocarbon, as a secondary factor.

Distinct evolution trends of nanometer-scale pores displayed by the pyrolysis of organic matter-rich lacustrine shales: Implications for the pore development mechanisms

Organic matter (OM) compositions greatly affect hydrocarbon generation and expulsion processes, which are critical for the organic porosity development in shale. Lacustrine shale samples of low thermal maturity were pyrolyzed using two pyrolysis systems (closed and semi-closed systems). Pore development was measured by low-pressure gas adsorption and field emission-scanning electron microscopy (FE-SEM), and bulk porosity was modeled utilizing organic geochemical data. The gas adsorption analysis indicated that shale samples of different OM compositions differed in pore volume evolution with thermal maturity, mainly related to the different amounts of hydrocarbon generated and expelled. Residual bitumen significantly reduced the pore volume of OM-rich oil generative shale samples, and restricted the micro-, meso-, and macro-pore volumes to different extents. Calculations and experiments both showed that OM-rich and oil generative shale experienced a greater increase in pore volume after the oil peak. In addition, it was observed that variations in the main pore types were associated both with shale compositions and with exerted overburden pressure. Increase in overburden pressure were found to greatly facilitate the development of nanometer-size spongy and complex OM pores in shales containing type Ⅱ/Ⅲ kerogens, possibly as a result of the expulsion of gaseous hydrocarbons. By contrast, the shale with abundant type Ⅰ kerogen tended mainly to develop relatively large pores following oil expulsion regardless of overburden pressure. The modeled organic porosity of pyrolyzed samples of type III OM was similar to the porosity of geological shale, but the porosity of OM-rich oil generative shale samples with high expulsion efficiency at the oil generation stage was two to three times the measured porosity of the geological shale. In some cases, the higher modeled shale porosity might be related to the higher expulsion efficiency. For geological shales of expulsion efficiency comparable to the pyrolyzed samples, geological processes (e.g., compaction and cementation) may have greatly reduced the OM-associated pore volume.

Influence of the Emeishan basalt eruption on shale gas enrichment: A case study of shale from Wufeng-Longmaxi formations in northern Yunnan and Guizhou provinces

The eruption or invasion of the Emeishan basalt has a systematic impact on the maturity of shale organic matters, hydrocarbon-generation evolution, reservoir physical properties and gas-bearing properties of shale, which is directly related to the preservation and accumulation of shale gas. By taking four typical shale gas wells in northern Yunnan and Guizhou provinces of China as examples, the influence of the basalt eruption on shale gas enrichment of Wufeng-Longmaxi formations is analyzed. The results show that: The shale near the basalt eruption area reached the late stage of over-mature ahead of time, with the equivalent Ro greater than 3.0%. Close to the basalt eruption zone, the porosity and permeability are significantly reduced. The low shale gas content and high N2 component are related to the abnormal thermal effect of the basalt and the acceleration of hydrocarbon-generation process. N2 content indicates the shale gas preservation conditions. Near the basalt eruption area, the formation temperature increases, the liquid hydrocarbon wet gas is formed early, the peak-period of gas-generation moves forward greatly, the shale gas experiences more tectonic movements and prolonged preservation periods. In conclusion, the eruption or invasion of the Emeishan basalt is unfavorable for the shale gas enrichment of Wufeng-Longmaxi formations, while the large amount of discharged shale oil and gas in the early stage is favorable for the conventional natural gas accumulation of overlying strata. It is suggested that the exploration should be focused on conventional gas and supplemented by shale gas in area with large basalt distribution.

Quantitative study on hydrocarbon expulsion mechanism based on micro-fracture

The significance of source rocks for oil and gas accumulation has been indisputably acknowledged. Moreover, it has been gradually realized that there is difference between hydrocarbon generation capacity and hydrocarbon expulsion capacity, and this has prompted research on hydrocarbon expulsion efficiency. However, these studies dominantly highlight the results of hydrocarbon expulsion, and investigation into the corresponding process and mechanism is primarily from a macroscopic perspective. Despite its wide acceptance as the most direct hydrocarbon expulsion mode, hydrocarbon expulsion through micro-fractures is still not sufficiently understood. Therefore, this study obtains observations and performs experiments on two types of source rocks (mudstones and shales) of the Chang 7 oil group of the Yanchang Formation in Ordos Basin, China. Microscopy reveals that organic matter is non-uniformly distributed in both types of source rocks. Specifically, mudstones are characterized by a cluster-like organic matter distribution, whereas shales are characterized by a layered organic matter distribution. Thermal evolution simulation experiments demonstrate that the hydrocarbon generation process is accompanied by the emergence of micro-fractures, which are favorable for hydrocarbon expulsion. Moreover, based on the theories of rock physics and fracture mechanics, this study establishes micro-fracture development models for both types of source rocks, associated with the calculation of the fracture pressure that is needed for the initiation of fracture development. Furthermore, the relationship between the fluid pressure, fracture pressure, and micro-fracture expansion length during micro-fracture development is quantitatively explored, which helps identify the micro-fracture expansion length. The results indicate that the development of micro-fractures is commonly impacted by the morphology and distribution pattern of the organic matter as well as the mechanical properties of the source rocks. The micro-fractures in turn further affect the hydrocarbon expulsion capacity of the source rocks. The results of this study are expected to provide theoretical and practical guidance for the exploration and exploitation of tight oil and shale oil.