Hydrocarbon Expulsion Efficiency Research Articles

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).

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.

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.

Reservoir characteristics of marine–continental transitional shale and gas-bearing mechanism:Understanding based on comparison with marine shale reservoir

Transitional shale gas layers are widely distributed in China, but no significant exploration breakthrough has been made so far. This paper investigates and analyzes the characteristics and gas-bearing mechanisms of transitional shale gas reservoirs in detail, aiming to clarify the shale gas accumulation mechanism of transitional shale and provide theoretical support for the selection of favorable intervals. The transitional shale gas layer is characterized by a thin single-layer thickness, rapid lithological change, low brittle mineral content, and poor kerogen type. The lack of organic matter (OM) sponge pore development process from the oil-generation stage results in limited numbers of OM nanometer-scale pores. Shale pore space is dominated by pores and fractures related to clay minerals. The measured gas content is well consistent with the theoretically calculated gas content for marine organic-rich shales. However, the actual measured gas content is far lower than the theoretically calculated gas content for the transitional shale gas reservoir. The main mechanisms are summarized to be (1) the high hydrocarbon expulsion efficiency of the “sandwich” space structure of the sandstone–shale–coal association, which gives rise to most natural gas migrating into nearby sandstone, and (2) high water saturation resulting in insufficient storage space for free gas in the shale reservoir. Unlike marine shale gas, natural gas in the transitional shale reservoir is primarily dominated by adsorbed gas in kerogen, and free gas is relatively low. The favorable lithofacies types are organic-rich siliceous/calcareous shales. Multiple layers of siderite-bearing shales/siderites are developed vertically and continuously distributed horizontally in transitional strata, particularly in flat-lagoon facies. It is easy to form a “micro-trap” to store gas in siderite-bearing shale, and siderite-bearing shale has strong sealing properties due to low porosity, low permeability and high breakthrough pressure. This property can form overpressure and trap shale gas inside the shale, providing a new research perspective for the optimization of vertical favorable intervals, as well as exploration breakthrough in transitional shale gas. Further research should strengthen the systematic sedimentological study of transitional facies, reveal shale gas occurrence state and dynamic transformation, and optimize favorable interval evaluation systems to clarify the feasibility of coal-measure gas commingled production.

Hydrocarbon Generation Mechanism of Mixed Siliciclastic–Carbonate Shale: Implications from Semi–Closed Hydrous Pyrolysis

Affected by the complex mechanism of organic–inorganic interactions, the generation–retention–expulsion model of mixed siliciclastic–carbonate sediments is more complicated than that of common siliciclastic and carbonate shale deposited in lacustrine and marine environments. In this study, mixed siliciclastic–carbonate shale from Lucaogou Formation in Junggar Basin was selected for semi–closed hydrous pyrolysis experiments, and seven experiments were conducted from room temperature to 300, 325, 350, 375, 400, 450, and 500 °C, respectively. The quantities and chemical composition of oil, gases, and bitumen were comprehensively analyzed. The results show that the hydrocarbon generation stage of shale in Lucaogou Formation can be divided into kerogen cracking stage (300–350 °C), peak oil generation stage (350–400 °C), wet gas generation stage (400–450 °C), and gas secondary cracking stage (450–500 °C). The liquid hydrocarbon yield (oil + bitumen) reached the peak of 720.42 mg/g TOC at 400 °C. The saturate, aromatic, resin, and asphaltine percentages of bitumen were similar to those of crude oil collected from Lucaogou Formation, indicating that semi–closed pyrolysis could stimulate the natural hydrocarbon generation process. Lucaogou shale does not strictly follow the “sequential” reaction model of kerogen, which is described as kerogen firstly generating the intermediate products of heavy hydrocarbon compounds (NSOs) and NSOs then cracking to generate oil and gas. Indeed, the results of this study show that the generation of oil and gas was synchronous with that of NSOs and followed the “alternate pathway” mechanism during the initial pyrolysis stage. The hydrocarbon expulsion efficiency sharply increased from an average of 27% to 97% at 450 °C, meaning that the shale retained considerable amounts of oil below 450 °C. The producible oil reached the peak yield of 515.45 mg/g TOC at 400 °C and was synchronous with liquid hydrocarbons. Therefore, 400 °C is considered the most suitable temperature for fracturing technology.

The Controls of Laminae on Lacustrine Shale Oil Content in China: A Review from Generation, Retention, and Storage

The successful development of shale oil in China has claimed that laminated shale is a favorable lithofacies for the effective extraction of petroleum. Clarifying the role of laminae in shale oil generation, migration, storage, and enrichment is urgent and important. Starting from the describing and classifying of the lamina, the common methods and terms used to delineate lamina types are briefly summarized. The results of different schemes are often mutually inclusive, which prompted scholars to work towards a unified division scheme. The influencing factors of oil retention in shale systems, including organic matter (OM) type, total organic carbon (TOC) content, OM maturity, mineral composition, pore structure, and preservation conditions, are systematically discussed. Subsequently, comparative work on source rock quality, reservoir properties, and hydrocarbon expulsion efficiency of shales with different laminar structures is carried out. The comparison results of shale with different rock structures reveal that the laminated shale has a high expulsion efficiency. However, the strong oil generation capacity and superior storage space of laminated shale synergistically control the considerable amount of retained oil in the shale system. Especially the oil mobility of laminated shale is also considered because of great pore size and pore connectivity. The fine evaluation of laminar structure and prediction of laminar distribution has great significance for the selection of shale oil “sweet spot area” or “sweet spot interval”.

Organic matter transformation ratio, hydrocarbon expulsion efficiency and shale oil enrichment type in Chang 73 shale of Upper Triassic Yanchang Formation in Ordos Basin, NW China

The major enrichment type of shale oil in the Chang 73 shale of Upper Triassic Yanchang Formation in the Ordos Basin is unknown. This paper analyzes the organic matter transformation ratio, hydrocarbon expulsion efficiency and roof/floor sealing conditions of the Chang 73 shale, and evaluates the major enrichment type of shale oil in this interval. The average organic matter transformation ratio of the Chang 73 shale is about 45%; in other words, more than 50% of the organic matters have not transformed to hydrocarbons, and the lower the maturity, the greater the proportion of untransformed organic matters. The cumulative hydrocarbon expulsion efficiency of the transformed hydrocarbon is 27.5% on average, and the total proportion of untransformed organic matters plus retained hydrocarbons is greater than 70%. The relative hydrocarbon expulsion efficiency of the Chang 73 shale is 60% on average, that is, about 40% of hydrocarbons retain in the shale. The Chang 73 shale corresponds to Chang 71+2 and Chang 8 sandstones as the roof and floor, respectively, and is further overlaid by Chang 6 shale, where extensive low porosity and low permeability–tight oil reservoirs have formed in the parts with relatively good porosity and permeability. Moreover, the Chang 73 shale is tested to be in a negative pressure system (the pressure coefficient of 0.80–0.85). Therefore, the roof/floor sealing conditions of the Chang 73 shale are poor. The retained hydrocarbons appear mostly in absorbed status, with low mobility. It is concluded that the medium–high mature shale oil is not the major enrichment type of shale oil in the Chang 73 shale, but there may be enrichment opportunity for shale oil with good mobility in the areas where the sealing conditions are good without faults and fractures and oil reservoirs are formed off Chang 71+2, Chang 6 and Chang 8. Furthermore, low–medium mature shale oil is believed to have great potential and is the major enrichment type of shale oil in the Chang 73 shale. It is recommended to prepare relevant in-situ conversion technologies by pilot test and figure out the resource availability and distribution.

Accumulation Conditions and Pattern of Tight Oil in the Lower Submember of the Fourth Member of the Shahejie Formation in the Damintun Sag, Bohai Bay Basin

To determine the accumulation conditions and pattern of tight oil in oil shales in the Damintun Sag, Bohai Bay Basin, this study investigated the basic geological conditions of the source rocks and reservoirs in the sag using methods such as organic carbon analysis, whole-rock XRD analysis, and field emission scanning electron microscopy. The results show that: (1) The high-quality source rocks in the lower submember of the fourth member of the Shahejie Formation (E2S42) in the Damintun Sag have high organic matter abundance, favorable organic matter types, high hydrocarbon expulsion efficiency, and high fluidity. Therefore, they provide sufficient oil sources for tight oil accumulation.; (2) During the burial of organic-rich shales, the thermal degradation of organic matter produces large amounts of organic acids, which can dissolve carbonate minerals. In this way, secondary pores are formed.; (3) The special microscopic pore structure that connects fractures to pores is the key to the enrichment of tight oil is a key factor for the high oil saturation of pores in oil shales; (4) The breakthrough pressure (up to 100 MPa) and specific surface area of dolomitic mudstones in the E2S42 submember are significantly higher than those in other horizons. As a result, the dolomitic mudstones can effectively seal the underlying tight reservoirs; (5) Compared with the tight oil in tight sandstones, the tight oil in the oil shales in the study area has significantly superior geological conditions for reservoir formation, such as the favorable arrangement of hydrocarbon expulsion channels, low filling resistance, and the presence of reservoir spaces.

Study on Pyrolysis Hydrocarbon Generation Kinetics and Shale Gas Formation Process of Marine Continental Transitional Rocks in Shanxi Formation, Ordos Basin

The marine continental transitional facies shale of Shan23 sub member of Shanxi Formation in Ordos Basin was selected, and the hydrocarbon generation kinetics of Shan 23 sub member marine continental transitional facies shale was studied through open system thermal simulation experiment. The experimental results show that the pre exponential factor of Shan 23 shale is 12.92*1015/s, and the activation energy is mainly concentrated in 52~82kcal/mole. On this basis, combined with petromod basin simulation software, the burial history, thermal evolution history and hydrocarbon generation history of Shanxi Formation shale are established, and the formation process of shale gas is clarified. Finally, using the genetic method, combined with the original TOC restored by Petromod basin simulation software and the hydrocarbon generation obtained from the open system thermal simulation experiment, the resources of the study area are calculated when the hydrocarbon expulsion efficiency is 50%. The calculation results show that the shale gas resource in the study area is 12.41*1012m3, which shows a good exploration potential of sea land transitional facies shale in the study area.

Geochemical characteristics and shale oil exploration potential of the Da’anzhai Member in the Sichuan Basin, southwest China

Based on the analysis of the organic geochemical characteristics of the shale in the Da’anzhai Member in the Sichuan Basin, southwest China, we discuss the hydrocarbon generation potential, hydrocarbon expulsion efficiency ( EH), and oil-bearing properties to identify the dominant exploration direction for shale oil. The results indicate that: (1) the Da’anzhai shale has low organic matter content and high maturity with the average total organic carbon (TOC) content of 1.27% and average vitrinite reflectance (Ro) of 1.29%, (2) the EH of the Da’anzhai shale ranges from 0% to 92% with an average value of 72%, (3) the lower limit of TOC for shale commercial production is 1.5%, which is lower than any current standard in China and North America, and (4) shale oil in the center lacustrine basin is more enriched compared with the outskirts of the basin with [Formula: see text], Ro < 1.25%, EH < 67%, and oil saturation index > 100 mg/(g·TOC). These results indicate that the prospects for shale oil exploration in the central basin are optimistic and should be the key exploration area for shale oil in the future.

Evaluation method of hydrocarbon yield of source rocks in open, semiopen, and closed systems: A case study on the K1qn Formation, northern Songliao Basin, China

Hydrocarbon yield of source rocks is an important parameter in the evaluation of oil and gas resources, and its value determines the potential of conventional and unconventional oil and gas resources. There is no oil cracking into gas in the thermal pyrolysis experiment data of an open system, whereas kerogen cracking into oil in a closed system is involved in the calculation of oil cracking into gas. However, most source rocks in sedimentary basins are a process of hydrocarbon generation and hydrocarbon expulsion, which could lead to insufficient understanding of hydrocarbon yield of source rocks. Based on the multiple thermal pyrolysis experiment data, three hydrocarbon generation kinetic models, and actual geologic data (burial history, thermal history, and hydrocarbon generation threshold), we established the evaluation method and chart of hydrocarbon yield of source rocks under open, semiopen, and closed systems by using the hydrocarbon generation kinetics method. The concept of degree of openness was proposed. From a closed system to an open system, the degree of openness increases gradually, and its value changes from 0 to 1. Taking the K1qn Formation in the northern Songliao Basin as an example, the hydrocarbon expulsion efficiency of the K1qn Formation source rock is approximately 70%, and it can be approximated as the degree of openness. Based on our method for evaluating hydrocarbon yield of source rocks, the charts of hydrocarbon yield of source rocks under open system, semiopen system with a degree of openness of 0.7, and closed system of the K1qn Formation in the northern Songliao Basin were established. The oil and gas yields of the K1qn Formation source rocks in a semiopen system with a degree of openness of 0.7 are approximately 540 and 105 mgHC/gTOC at a burial depth of 2000 m, respectively. Our results indicate that the hydrocarbon yield of source rocks in a semiopen system is closer to the hydrocarbon yield of source rocks under geologic condition. We use the thermal pyrolysis experiment data, hydrocarbon generation kinetics model, and geologic data to propose a very valuable evaluation method of hydrocarbon yield of source rock, which has a solid theoretical basis and strong applicability.

Impact of Minerals and Sealing Systems on the Pore Characteristics of the Qiongzhusi Formation Shale in the Southern Sichuan Basin

The characteristics, distribution, and preservation of pores are vital in controlling the storage and distribution of shale gas. The Qiongzhusi Formation shales taken from different members with similar tectonic and thermal evolutions were used to evaluate the response of pore characteristics to minerals and sealing systems using field-emission scanning electron microscopy and gas adsorption. Because of differences in mineral structure and arrangement, feldspar, organic matter (OM)–clay, OM–rutile, and OM–apatite aggregates facilitate multiple types of pores in the shale and influence the relative proportions of surface porosity for different types of pores owing to differences in mineral structure and arrangement. Rigid frameworks and pressure shadows formed by rigid minerals and OM–mineral aggregates preserved OM and pores to some extent. The sealing capacity of the floor controls the sealing system and hydrocarbon expulsion efficiency of the Qiongzhusi Formation in different members. During thermal evolution, the amount of hydrocarbons generated and expelled affected the stress equilibrium state between the pore pressure and external stress, influencing the compaction intensity of shales. The OM pore development characteristics were evolved with variation in the stress equilibrium state in different sealing systems. Once the stress equilibrium state was disrupted, the OM pores deformed, narrowed, or even closed under the influence of compaction owing to the loss of overpressure support. The pore characteristics of the Qiongzhusi Formation shales responded significantly to different sealing systems. A few OM pores are flat and slitlike in the open system, whereas numerous OM pores are round and elliptical in the semiopen system. Meanwhile, the average diameter of the OM pores in the open system was reduced by approximately 40.2% compared with that of the semiopen system. Furthermore, the pore volume and specific surface area of the mesopores for open system shales were reduced by 38.4% and 37.7%, respectively, compared to the semiopen system. These findings will improve the understanding of the distribution and preservation of pore in shale and help assess the sweet-spot members for the Qiongzhusi Formation shale gas.

Geochemical Characteristics and Process of Hydrocarbon Generation Evolution of the Lucaogou Formation Shale, Jimsar Depression, Junggar Basin

Lacustrine shale, represented by the Middle Permian Lucaogou Formation in the Jimsar Depression in the eastern Junggar Basin, has become one of the main areas of shale oil exploration in China. In this study, we used 137 samples of shale from the Lucaogou Formation, drawn from 14 wells in the Jimsar Depression, to investigate their characteristics of pyrolysis, organic carbon and soluble organic matter content, biomarkers, organic microscopic composition, and vitrinite reflectance. Basin simulation and hydrocarbon generation thermal simulation experiments were also conducted in a closed system. The results of this study indicate that the input of an algae source was dominant in the source rocks of the Lucaogou Formation, that the water in which the rocks were deposited had high salinity and strong reducibility, and that the source rocks were oil-prone. The Lucaogou source rocks generally had good hydrocarbon generation capability, but showed significant heterogeneity. At the end of the Cretaceous period, the shales in the Lucaogou Formation entered the oil-generation window as a whole. Currently, the shales of the Lucaogou Formation are generally in the high-maturity stage in the deep part of the depression, producing a large amount of high-maturity oil and condensate gas, while those in the shallow part have relatively low maturity and can only produce a large amount of conventional crude oil. The maximum crude oil generation rate of the Lucaogou Formation shale obtained from the thermal simulation results was 220.2 mg/g of the total organic carbon (TOC), and the maximum hydrocarbon expulsion efficiency was estimated to be 59.3–76.4%.

Calculation and controlled factors of hydrocarbon expulsion efficiency using corrected pyrolysis parameters: A Songliao case study

In recent years, rock pyrolysis parameters combined with a mass balance method have been used to calculate the hydrocarbon expulsion efficiency. However, due to the experimental procedure of rock pyrolysis, the residual hydrocarbon amount (S1) is underestimated, and the hydrocarbon-generation potential of kerogen (S2) is overestimated, so that the hydrocarbon expulsion efficiency calculated from the pyrolysis parameters before correction is higher than the actual value. In this paper, the pyrolysis parameters were corrected by performing pyrolysis before and after the extraction of source rocks, and the hydrocarbon expulsion efficiency of the mudstone of the Qing 1 member of the Ha14 well in Songliao basin was calculated using the chemical kinetics method. The hydrocarbon expulsion efficiencies before and after the correction were considerably different, the hydrocarbon expulsion efficiency of the Ha14 well after correction was 17.5% lower than that before correction. The study show that the higher the abundance and maturity of source rock are, the higher the hydrocarbon expulsion efficiency is; the oil-type organic matter has a higher hydrocarbon-expulsion efficiency than the gas-type organic matter; the interbedded sand and mud type source-reservoir configuration relationship is beneficial to hydrocarbon expulsion; the underwater diversion channel phase has the highest hydrocarbon expulsion efficiency.

Gas content evolutionin western Guizhou and differential occurrencein China of Permian shale with type III kerogen

Permian organicmatter(OM) in China mainly comes from higher plants rich in type III kerogen. Exploring gas content evolution and occurrence mechanisms is of great significance for shale gas exploration. Shales of western Guizhou in China were collected from wells and subjected to experiments under formation conditions (e.g. thermal simulation, Rock-Eval pyrolysis, X-ray diffraction and CH4 isotherm adsorption). A thermogenic gas generation model was established based on the logistic model, a hydrocarbon expulsion model was established based on the hydrocarbon potential method, and an adsorbed gas volume model was established based on temperature, pressure and total organic carbon(TOC). Various gas content of shale with type III kerogen were calculated in a special geological history. The differences of shales between the western Guizhou and the northeastern Ordos Basin in China were compared in terms of gas generation, expulsion and adsorption capacity. The results showed that the gas generation capacity of the western Guizhou samples was stronger because of the higher TOC and hydrogen index (HI). Limited differences in hydrocarbon expulsion efficiency were observed between the two areas. The source area of the samples had no significant effect on the adsorption capacity. Due to its high TOC, low geothermal gradient, high pressure gradient and suitable burial depth (500–1500 m), the shale in western Guizhou has a stronger adsorption capacity. Obvious differences in the free gas volume and proportion in different areas were observed and should be analyzed separately in combination with the TOC, HI, geothermal gradient, pressure gradient and depth.

Formation, preservation and connectivity control of organic pores in shale

In view of strong heterogeneity and complex formation and evolution of organic pores, field emission scanning electron microscopy (FESEM), Raman spectrum and fluid injection + CT/SEM imaging technology were used to study the macerals, organic pores and connectivity of organic pores in the lower Paleozoic organic-rich shale samples from Southern China. Combined with the mechanism of hydrocarbon generation and expulsion and pore forming mechanism of organic matter-based activated carbon, the relationships between organic pore development and the organic matter type, hydrocarbon generation process, diagenesis and pore pressure were explored to reveal the controlling factors of the formation, preservation and connectivity of organic pores in shale. (1) The generation of organic pores goes on through the whole hydrocarbon generation process, and is controlled by the type, maturity and decomposition of organic matter; the different hydrocarbon generation components and differential hydrocarbon-generation evolution of kerogen and solid asphalt lead to different pore development characteristics; organic pores mainly develop in solid bitumen and hydrogen-rich kerogen. (2) The preservation of organic pores is controlled by maturity and diagenesis, including the steric hindrance effect of in-situ hydrocarbon retention, rigid mineral framework formed by recrystallization, the coupling mechanism of pore-fluid pressure and shale brittleness- ductility transition. (3) The R o of 4.0% is the maturity threshold of organic pore extinction, the shale layers with R o larger than 3.5% have high risk for shale gas exploration, these shale layers have low gas contents, as they were in an open state before uplift, and had high hydrocarbon expulsion efficiency and strong aromatization, thus having the “congenital deficiency” of high maturity and pore densification. (4) The pores in the same organic matter particle have good connectivity; and the effective connectivity between different organic matter pores and inorganic pores and fractures depends on the abundance and distribution of organic matter, and development degree of pores and fractures in the shale; the accumulation, preservation and laminar distribution of different types of organic matter in high abundance is the prerequisite for the development and connection of organic pores, grain margin fractures and bedding fractures in reservoir.

Identification of effective source rocks in different sedimentary environments and evaluation of hydrocarbon resources potential: A case study of paleogene source rocks in the Dongpu Depression, Bohai Bay Basin

Source rocks in lacustrine rifting basins have great heterogeneity, which leads to imprecise assessments of hydrocarbon resources. Previous studies evaluated the source rocks of different sedimentary environments in lacustrine basins or depressions using the same lower limit of effective source rocks (i.e., the minimum total organic carbon (TOC) at which the source rocks are capable of expelling hydrocarbons). In this study, the source rock samples were selected from five formations in the Dongpu Depression for organic geochemical experiments and quantitative simulations of hydrocarbon expulsion. According to salinity differences, every formation was divided into a saline area, transition area and freshwater area. The results show that the maximum thickness of source rocks developed in the saline and transition areas is 700 m. Additionally, source rocks with a higher TOC and oil-prone organic matter types (II1 and II2) also develop in the saline and transition areas, and most have entered the mature stage. The TOC values corresponding to the lower limit of effective source rocks in the saline, transition, and freshwater areas are 0.3%, 0.4% and 0.5%, respectively. Furthermore, the hydrocarbon expulsion ratio (amount of hydrocarbon discharged per unit of TOC from the source rocks) for the freshwater area is 253.1 mg/g, while the ratios in the saline and transition areas are relatively higher at 439.4 mg/g and 369.3 mg/g, respectively. The hydrocarbon expulsion rate (change in the expulsion ratio per unit thermal evolution degree) and hydrocarbon expulsion efficiency (ratio of cumulative hydrocarbon expulsion amount to generation amount) in the saline, transition and freshwater areas present maxima when the Ro (vitrinite reflectance) values are 0.95%, 0.85% and 0.82%, respectively. The hydrocarbon expulsion quantities in the saline, transition and freshwater areas account for 24%, 49% and 27% of the total, respectively. Therefore, the main hydrocarbon expulsion area is the transition area of the Dongpu Depression associated with the thickest source rocks. Es3M and Es3L source rocks in the transition area with high organic matter abundant and type II kerogen are more promising than the other formations. This study is the first to report on effective source rocks in different sedimentary environments in lacustrine basins and can provide guidance for future exploration in the Dongpu Depression and a reference for future research on source rocks in other lacustrine basins.

Assessment of shale gas potential from geochemical data in the Late Devonian shale succession, Liard Basin, Canada

The shale gas potential of a Late Devonian shale sequence in the Liard Basin, an important unconventional gas reservoir, was assessed using the retained gas volume based on gas generation potential and hydrocarbon expulsion efficiency. Evaluation of gas generation potential in the Liard Basin depends on understanding the characteristics of the original organic matter. However, due to high thermal maturity, it is difficult to estimate the characteristics of the original organic matter from conventional methods. The type of original organic matter was inferred from inorganic geochemical proxies that reflect productivity (Ex-SiO2), terrestrial sediment input (Al2O3, Zr), and oxygen level in the bottom water (MoEF and UEF). By considering the present day TOC (TOCpd) and the type of original organic matter, the original hydrogen index (HIo) and original total organic carbon (TOCo) values were calculated to range from 200 to 700 mgHC/gTOC and from 0.3 to 29.0 wt%, respectively. The measured TOCpd values were similar to the TOCpd calculated from the 1-D petroleum system model using the original organic matter characteristics inferred in this study, which indicates that the TOCo values are reliable. Based on the evolution of the TOCo during its thermal history, the total gas generation potential in the Late Devonian shale sequence (550 ft) of the Liard Basin is estimated to be 1690 bcf/section. Considering the total gas in place (496 bcf/section), based on the estimated ultimate recovery, approximately 70% of the hydrocarbon might have been expelled. The retained gas volume fluctuates vertically in the Late Devonian shale sequence. The retained gas volume is higher in the 3946–3993 m (136 bcf/section) and 3993–4047 m (281 bcf/section) intervals than other intervals (less than 60 bcf/section), indicating that these intervals are the most prospective for shale gas exploration and development in the studied well.

Hydrocarbon generation-retention-expulsion mechanism and shale oil producibility of the permian lucaogou shale in the Junggar Basin as simulated by semi-open pyrolysis experiments

The shale of the Permian Lucaogou Formation in the Jimusar sag, Junggar Basin (abbreviated as the Lucaogou shale) is a typical lacustrine type-II source rock, and is among the most representative target zones for shale oil exploration in China. However, little attention has been paid to the dynamic changes of the shale decomposition; hydrocarbon generation, retention, and expulsion; physico-chemical properties; and producibility of shale oil at different stages of maturation in this shale. Semi-open pyrolysis experiments were performed on the Lucaogou shale; products including expelled gas, oil (expelled oil), bitumen (retained oil), and residual rock were obtained, and their quantities and chemical and physical compositions were comprehensively characterized. The results show that the density and molecular weight of the oil are lower than those of the bitumen, whereas the API gravity of the oil is higher than that of the bitumen, indicating the preferential expulsion of light hydrocarbons and short chains. The saturate, aromatic, resin and asphaltene (SARA) percentages of oils under the current semi-open pyrolysis experiments were similar to those of natural oils recovered from the Lucaogou Formation, suggesting that semi-open pyrolysis can achieve the same purpose as hydrous pyrolysis to simulate natural oil composition. The measured vitrinite reflectance (Ro) of the pyrolyzed shale was lower than the calculated Easy%Ro, which is in accord with findings from the Chang 7 shale (another typical lacustrine type-II shale in China) but distinct from previously reported type-III coals and marine type-II shales. Similar to the Chang 7 shale, the decomposition process of the Lucaogou shale did not follow the sequential reaction model described as kerogen → bitumen → oil or kerogen → NSOs → HCs. The generation of HCs (oil) and NSOs (bitumen) was independent and followed the “alternate pathway” mechanism under semi-open pyrolysis conditions. In the early oil window (Ro ˂ 1.0%), the hydrocarbon expulsion efficiency was relatively low, meaning that the shale simultaneously retained considerable amounts of oil during peak oil generation. The producibility of shale oil reached its maximum at the end of the oil window (1.0–1.2 %Ro), and this interval is considered the most suitable for fracturing technology.