Gas Accumulation Conditions Research Articles

Application of seismic attribute analysis in Ordovician reservoir prediction in Hechuan Tongnan exploration area, Sichuan Basin

Abstract Exploration has revealed that the Ordovician in Sichuan Basin has good conditions for oil and gas accumulation in the peripheral areas of the paleo-uplift, but it is difficult to predict the carbonate reservoirs due to their strong heterogeneity and complex planar distribution. Based on seismic, drilling, logging and analysis data, this paper makes full use of 3D seismic data from the Hechuan Tongnan exploration area to study the relationship between petrophysical parameters and geophysics parameters, the seismic response characteristics of carbonate reservoir are determined by forward modeling. On the basis of detailed interpretation, several seismic attributes with high correlation coefficients with reservoir response characteristics in this area were selected and seismic attribute reservoir prediction research was carried out in the Hechuan Tongnan exploration area, Sichuan Basin Province, through correlation intersection analysis of seismic attributes and intersection analysis of seismic attributes and well-point porosity, the optimal seismic attributes for reservoir prediction are optimized, and the reservoir distribution is characterized, it provides an important basis for risk exploration in this area.

Natural gas accumulation conditions and exploration directions of Carboniferous clastic rocks in the northeastern margin of Junggar Basin, China

The Carboniferous strata in the northeastern Junggar Basin are an important exploration field for natural gas in the basin. However, volcanic rocks have long been the primary exploration target. In contrast, the exploration and research of clastic rocks associated with source formations have been largely overlooked, resulting in an insufficient understanding of the reservoir forming conditions and exploration potential of Carboniferous clastic rocks. Through the evaluation of Carboniferous source rocks, effective source stove characterization, clastic reservoir evaluation, oil and gas source correlation, and reservoir formation model construction in this region, three key findings have been made. First, the Carboniferous in the northeastern Junggar Basin has developed three sets of high-quality gas source rocks: the Dishuiquan Formation, the Songkalsu B Member, and the Shiqiantan Formation. These formations correspond to three hydrocarbon source centers: the Sannan–Dishuiquan Sag, the Wucaiwan Sag–Dajing area, and the Dongdao Haizi Sag–Baijiahai High. Second, the Carboniferous system in the northeast has developed multiple types of large-scale reservoirs, including sand conglomerates, sandstones, turbidites, dolomitic rocks, and shale. These reservoirs are generally characterized by low porosity to ultra-low porosity and low permeability to ultra-low permeability reservoirs. There is a dissolution pore development zone at depths of 2900–4500 m. Third, a comparison of oil and gas sources reveals that all three sets of gas source rocks contribute to the natural gas found in the northeast, with obvious characteristics of near-source reservoir formation. The Carboniferous clastic rocks host two types of natural gas reservoirs: unconventional and conventional near-source reservoirs. It is predicted that there is an orderly accumulation pattern of shale gas, tight sandstone gas, and conventional natural gas reservoirs. This study reveals that the Carboniferous clastic rock source and reservoir configuration in the northeastern Junggar Basin is highly favorable, and the natural gas reservoirs in source and near-source clastic rocks represent important exploration directions.

Geological Conditions of Shale Gas Accumulation in Coal Measures

The shale of different potential layers is studied by using rock pyrolysis analysis, total organic carbon determination (TOC), kerogen microscopic component identification, mineral X-ray diffraction, scanning electron microscopy, and low-temperature nitrogen adsorption experiments. The results are as follows: (1) Shishui Formation of the Lower Carboniferous and Longtan Formation of the Upper Permian are the two most important shale gas reservoirs in the Chenlei Depression. The sedimentary environment of the target shale is a marine land interaction facies coastal bay lagoon swamp sedimentary system. Two sedimentary facies of tidal flat facies, subtidal zone, and lagoon swamp facies are developed. (2) The organic matter types of shale are Type III and II2, with TOC content greater than 1%. The maturity of shale samples is relatively higher (Ro,max is above 2%), which means they have entered the stage of large-scale gas generation. The overall brittle mineral content of the target shale sample is relatively higher (above 40%), which is conducive to artificial fracturing and fracture formation in the later stage, while an appropriate amount of clay minerals (generally stable at 40%) is conducive to gas adsorption. (3) The overall pore structure of the water measurement group and Longtan group is good, with a higher specific surface area and total pore volume (average specific surface area is 12.21 and 8.36 m2/g, respectively), which is conducive to the occurrence of shale gas and has good adsorption and storage potential. The gas content of the water measurement group and the Longtan Formation varies from 0.42 to 5 cm3/g, with an average of 2.1 cm3/g. It indicates that the water measurement group and the Longtan Formation shale gas in the study area have good resource potential.

Characteristics and development model of deep-ultra deep reservoirs in the Upper Wuerhe Formation of Permian in the sags of eastern Junggar Basin, China

Taking the deep-ultra deep glutenite reservoirs in the Upper Wuerhe Formation of Permian in Fukang Sag and Dongdaohaizi Sag as the research object and representative of the eastern Junggar Basin, its characteristics and main controlling factors are analyzed using various methods, including core analysis, thin section examination, and scanning electron microscope observation. High-pressure mercury injection and logging imaging were also employed to reveal the reservoir that Fukang and Dongdaohaizi sags harbor deep-ultra deep glutenite reservoirs, with Fukang Sag being a typical low porosity to ultra-low permeability reservoir, while Dongdaohaizi Sag is a low porosity to low permeability reservoir. Reservoir space types vary between the two sags, with Fukang Sag characterized by microfractures and corrosion pores, while a large number of corrosion pores with fewer fractures existing in Dongdaohaizi Sag. Both compaction and cementation exhibit a strong destructive effect on the reservoirs in the eastern Junggar Basin. However, the compaction effect in Fukang Sag is very strong, and the dissolution effect is weak. The large number of fractures generated by overpressure becomes an effective channel for ultra-deep oil and gas migration. The cracks in the Dongdaohaizi Sag are underdeveloped, and a large number of intra-particle corrosion pores generated by the dissolution of feldspar and turbidite improve reservoir properties. In addition, its rich turbidite also plays a compressive and pore retention role. There are two types of reservoir models developed in the Upper Wuerhe Formation of Permian in the eastern Junggar Basin: the deep fracture model represented by the Fukang Sag and the solution pore model rich in turbidite in Dongdaohaizi Sag. These models create favorable conditions for oil and gas accumulation in the deep-ultra deep reservoirs in the depression area.

Coupling of source rock gas expulsion intensity and reservoir quality in time and space-a key to determine gas accumulation in Upper Paleozoic tight sandstones of the Mugua gas field, Ordos Basin, China

Research on gas accumulation mechanisms and variations in gas saturation is limited in the newly established Mugua gas field in the Ordos Basin. Understanding these aspects is vital for reduce drilling uncertainty and exploration risk. This study employed a variety of methods, including: (1) the use of organic geochemical examinations to determine the gas expulsion intensity of hydrocarbon source rocks; (2) fluid inclusion analyses to determine the time of gas accumulation; (3) a combination of optical microscopy, scanning electron microscopy observations, pore-simulation and permeability tests, mercury-intrusion capillary pressure experiments, and nuclear magnetic resonance studies to assess the properties of the reservoir quality and identify the tight sandstone rock type; (4) wireline logging and interpretive data analyses to research the gas saturations features; and (5) establish reservoir quality evolution model to systematically study this problem. Integrating fluid inclusion homogenization temperatures with burial and thermal histories indicates that gas accumulation in the Mugua gas fields occurred throughout the Early Jurassic to Late Cretaceous period. Five diagenetic facies have been identified: dissolution, quartz-cemented, clay mineral filling, tightly compacted, and carbonate-cemented facies. The reservoir quality evolution model reveals that the five diagenetic facies experienced densification before the period of gas accumulation. Therefore, for gas accumulation in tight sandstones, it is essential that mature and gas-generating source rocks, provide sufficient expulsion forces to drive gas into the rocks. The mechanism of gas accumulation in the Mugua gas field's tight gas sandstone reservoirs involves the process occurring in sandstones that are either near or interbedded with source rocks, under high pore-fluid pressure generated by gas production. Compared to other Upper Paleozoic gas fields in the Ordos Basin, the gas expulsion intensity in the Mugua gas field is lower, ranging from 6.12–8.39 × 108 m3/km2. Due to the low gas expulsion intensity, the Shihezi 8 Member's tight sandstone reservoirs, situated away from the source rock, typically show low gas saturation. Conversely, the dissolution and quartz-cemented facies within the Benxi, Taiyuan, and Shanxi Formations, intimately interbedded with hydrocarbon source rocks, exhibit good reservoir quality. They offer ideal conditions for gas accumulation, making them prime candidates for exploration and development.

Comparative Study of the Characteristics of Lower Cambrian Marine Shale and Their Gas-Bearing Controlling Factors in the Middle and Lower Yangtze Areas, South China

This study comparatively analyzed the geological, geochemical, reservoir, and gas-bearing characteristics of the lower Cambrian marine shale in the Middle and Lower Yangtze regions. The main factors controlling the gas-bearing properties of the shales were identified, and the favorable and unfavorable conditions for shale gas accumulation are discussed. The results show that the organic carbon contents and thermal evolution degree of the organic matter in the lower Cambrian marine shale in the Lower Yangtze area were higher than those generally found in the Middle Yangtze area. The brittle mineral composition of the Middle Yangtze area was typically low silicon and high calcium, whereas the Lower Yangtze area was characterized by high silicon and low calcium. The development of micropores in the Lower Yangtze area was poorer than in the Middle Yangtze area, with the organic pores being particularly underdeveloped. The adsorption capacity of shale in the Lower Yangtze area was obviously higher than in the Middle Yangtze area. It was considered that the organic carbon content, thermal evolution degree, and molecular structure of kerogen were the main factors that controlled the adsorption properties of the shale. In addition, the Lower Yangtze area suffered a stronger tectonic transformation and frequent magmatic activity, and the preservation conditions were inferior to those in the Middle Yangtze area.

Geochemical characteristics and genesis of the Ordovician sub-salt natural gas in the Ordos Basin, China

A significant amount of natural gas resources has been discovered in the Ordovician reservoirs under a thick layer of gypsum-salt strata as a result of ongoing research into deep natural gas in China’s Ordos Basin, however, the genetic type and source of the Ordovician sub-salt natural gas remain contentious. These limits understanding how the geochemical properties of the natural gas in Ordos Basin have evolved and how to best guide future exploration and development. Based on the components, carbon and hydrogen isotopic ratios of natural gas from the latest exploration wells, combined with the geological background, this study systematically analyzed the genetic types and sources of sub-salt natural gas of the central and eastern Ordos Basin. The results show that the Ordovician natural gas is mainly composed of hydrocarbon gases with low content of heavy hydrocarbons and dryness (CCH4/CCH4+) above 0.95, belonging to typical dry gas. Non-hydrocarbon gases mainly include N2 and CO2, and some natural gas samples contained H2S. The Ordovician sub-salt natural gas is primarily a self-generating and self-preserving oil-cracking gas with relatively high maturity (Ro ranging from 1.5% to 2.1%) mixed with coal-derived gas generated from upper-Paleozoic coal with relatively low maturity (Ro ranging from 1.1% to 1.5%). Due to the dual-source hydrocarbon supply, the Ordovician sub-salt reservoirs provide favorable gas accumulation conditions and development prospects. This study offers a reasonable explanation for the anomalous geochemical characteristics of the Ordovician sub-salt reservoirs in the Ordos Basin, and also may serve as a guide for future exploration of natural gas in the carbonate gypsum-salt sedimentary system in other basins.

Periods and Processes of Oil and Gas Accumulation in the HZ-A Structure Double Paleogene Field, Pearl River Mouth Basin

The source of oil and gas and the stages of oil and gas accumulation in the “double-Paleo” field of the HZ-A structure in the Pearl River Mouth Basin are analyzed, and the spatiotemporal coupling relationship of the key conditions of oil and gas accumulation are discussed to reconstruct the process of oil and gas accumulation. Based on previous research results, which are based the characteristics of biomarker compounds, the oil and gas in the HZ-A structure double Paleogene field came from the Paleogene Wenchang Formation hydrocarbon source rocks in the HZ26 sub-sag. By means of the casting thin section identification and inclusion homogenization temperature measurement, this paper reveals the three major hydrocarbon accumulation periods and corresponding fluid charging types in the “double-Paleo” field of the HZ-A structure in the Pearl River Mouth Basin. The results show that 13.8–10 Ma is the charging period of low mature crude oil, 10–5.3 Ma is the charging period of mature crude oil, and from 5.3 Ma is the natural gas charging period. Based on actual geological, drilling, logging, and seismic data, the key conditions for hydrocarbon accumulation in the HZ-A structure “double-Paleo” field are sorted out; that is, the source conditions are characterized by high-quality lacustrine source rocks generating early oil and late gas and a near-source continuous hydrocarbon supply. The reservoir conditions are characterized by weathering and superposition of a fracture zone that transforms into a reservoir, and a large-scale sandstone rock mass that transforms into a reservoir. The caprock conditions are characterized by the stacking of several thin mudstones that form a seal and the combination of multiple lithologies that block hydrocarbon migration. The trap conditions are characterized by multistage uplift structure traps and fracture-lithology combination control traps. The transport conditions are characterized by multi-stage cross-bed transport of source-connected faults and lateral differential transport of shallow sand in deep fractures. Finally, oil and gas accumulation models of the HZ-A structure double Paleogene field were established, and the accumulation process was reconstructed. The overall process involved three stages, with the first stage being the localized oil-displacing-water mode, the second being the large-scale oil-displacing-water mode, and the third being the late progressive gas-displacing-oil mode.

Organic Matter Source, Fluid Migration, and Geological Significance of Stylolites in Organic-Lean Carbonate Rocks: A Case from the Sichuan Basin

Carbonate rocks exhibit significant heterogeneity as both a source rock and reservoir. Stylolite formation plays a crucial role in the enrichment of organic matter and the migration of geofluids within carbonate rocks. In order to study the enrichment mechanism of organic matter and the geofluid migration mode in the stylolites developed in carbonate rocks, stylolite-bearing core samples from the Dachigan structural belt in the eastern Sichuan Basin were collected. The stylolites and matrix were subjected to the total organic carbon (TOC) test and Rock-Eval pyrolysis, thin-section observation under fluorescent light, whole-rock X-ray diffraction, carbon and oxygen isotope analysis, and scanning electron microscopy. The organic matter occurring in the stylolites is mainly in the form of three types: soluble organic matter, pyrobitumen, and bitumen. This suggests that the organic matter within the stylolites mainly consists of secondary migrated organic matter. The stylolites also exhibit well-developed secondary dolomite and pyrite resulting from late-diagenetic recrystallization. These minerals contribute to the preservation of intercrystalline pore spaces and fractures, providing favorable conditions for oil and gas accumulation and migration. The strong cementation observed at the contact between the stylolites and matrix, along with the presence of secondary minerals nearby, may be attributed to the fractionation of light and heavy oil components during the migration of hydrocarbon fluids from the matrix to the stylolites. The thicknesses of the stylolites vary within the bulk, indicating severe diagenesis in thinner areas. Consequently, this leads to significant fractionation effects. The fractionation of crude oil components by stylolites poses challenges for the study of definitive oil–source correlations. To overcome these challenges, future research could investigate biomarker compounds to attempt oil–source correlations. Additionally, future efforts should take into consideration the spatial variation in the crude oil properties. Understanding the role of stylolites in organic matter enrichment and geofluid migration is crucial for optimizing exploration strategies in the Sichuan Basin, a region of growing importance in the energy industry. Moreover, our findings shed light on the complex interactions within stylolite-bearing rocks, which are not limited to this specific basin. These insights offer valuable contributions to the broader field of geology and reservoir characterization, enhancing our ability to predict and interpret similar geological formations globally.

Discussion on Transitional Shale Gas Accumulation Conditions from the Perspective of Source-Reservoir-Caprock Controlling Hydrocarbon: Examples from Permian Shanxi Formation and Taiyuan Formation in the Eastern Margin of Ordos Basin, NW China

Transitional shale gas, rich in resources, is expected to be a practical contributor to the increase in shale gas reserves and production in China. Its exploration prospect has been demonstrated by several wells in the Daning-Jixian block on the eastern margin of the Ordos Basin. In this paper, the Lower Permian Shanxi Formation (P1s) and Taiyuan Formation (P1t) in the eastern margin of Ordos Basin were compared for organic geochemical parameters, revealing that the overflow fan + lagoon combination (OLC) of the third sub-member of the second member of Shanxi Formation (P1s23) and the marine + lagoon combination (MLC) of the first member of Taiyuan Formation (P1t1) are the most favorable shale gas intervals. The two intervals were comparatively analyzed with respect to mineral composition, brittleness, caprocks, and preservation conditions. It is found that the OLC of P1s23 has a similar porosity to and much lower permeability than the MLC of P1t1 (or MLC1) and a BET surface area of 10–15 m2/g, which is smaller than the MLC1 (15–20 m2/g). Moreover, OLC has a brittle mineral content equivalent to MLC1 but a brittleness index of 33.73–62.36 (avg. 49.86), smaller than MLC1 (53.34–58.27, or avg. 55.85). OLC contains sandstones at both the roof and floor, with a higher permeability than shale in the interval, which cannot serve as good physical seals. In contrast, MLC1 contains limestones with lower permeability at the roof and floor, which, together with the overlying coal seams, have hydrocarbon generation capacity and can physically seal the MLC1 shale but also fill it with hydrocarbons, making MLC1 have higher gas content and superior for shale gas exploration than the OLC shale. Due to the multi-lithologies developed in transitional facies, besides the organic matter enrichment, and reservoir characteristics, it is necessary to find a suitable lithological combination to ensure the gas in shale can be better preserved and retained.

Structural deformation characteristics and its influence on shale gas preservation of the Wufeng−Longmaxi Formation in the Wuxi area, Chongqing, China

The Upper Ordovician Wufeng to Lower Silurian Longmaxi Formation has a good material basis for marine shale gas development, and the structural preservation condition is the key factor to control the rich and integrated shale gas reservoirs in the Wuxi area of Chongqing City, China. Based on the seismic-structural interpretation data, combined with the regional structural background and drilling effect, the structural deformation characteristics and shale gas structural preservation conditions are comprehensively analyzed in the study area. The Wuxi area is located at the structural junction of the Sichuan Basin and southern Dabashan along with strong structural deformations. Seven rows of NW to near EW structural belts are mainly developed. The fold styles and fault development degrees of different structural belts are different, and the difference in the structural preservation conditions of shale gas is also obvious. The study results reveal that the shale gas structure preservation conditions of the Wufeng−Longmaxi Formation in the Wuxi area are overall poor and only locally better. The structure preservation conditions for shale gas enrichment and accumulation are divided into four grades, such as the good Class I area, the general Class II area, the poor Class III area, and the very poor Class IV area. Among them, the Heiloumen structural zone and Huangcaoping buried structural zone nearby the Sichuan Basin have good preservation conditions and are classified as the good Class I preservation area. The macroscopic preservation type of shale gas in the Wufeng−Longmaxi Formation of the Wuxi area belongs to the complex structural preservation of the basin margin. Three structural preservation modes of shale gas in the study area have also been confirmed, including the lost destruction type, lost residual type, and trap preservation type. The trap preservation type is more conducive to the preservation of shale gas, which is the most favorable structural mode for shale gas exploration.

Hydrocarbon accumulation conditions and favorable exploration zones in the Lunpola Basin, Tibet

By systematically reviewing and summarizing the previous studies on the petroleum geology of the Lunpola Basin, combined with the latest oil and gas exploration results, the oil and gas accumulation conditions of this basin are summarized, and the favorable zones with the most exploration potential are pointed out. The results show that: ① The Paleogene mainly develops three sets of source rocks, including Niu-1 section, Niu-2 section and lower Niu-3 subsection. The lithology is mainly semi-deep and deep lacustrine gray-dark shale. Among them, the source rock of Niu-2 section is the best. However, the source rock of Niu-1 section is only developed in the Jiangjiacuo depression. The effective source rocks have the largest thickness in the central and western parts of the basin and have the best hydrocarbon-generating capacity. The thickness and abundance of the source rocks have decreased eastward. The organic matter are mainly Type I and Type II1, with a maturity of 0.58%–1.08%. ② The study area is dominated by clastic rock reservoirs, which can be divided into three types according to the strata distribution, and the overall reservoir conditions are not good. The reservoir porosity is between 0.1% and 32.6%, mainly between 2.0% and 10.0%, with an average of 6.5%; the permeability is between 0.0005 mD and 116.0 mD, mainly between 0.01 mD and 0.5 mD, which means ultra-low porosity and ultra-low permeable fracture-porous reservoirs. ③ Three sets of seals are mainly developed in the Lunpola Basin, including two regional seals of the middle Niu-2 subsection and Dingqinghu section, and a direct seal of upper Niu-2 subsection. These three sets of seals are well developed and have good preservation conditions in the relatively stable central depression and the footwall of thrust nappe structural belt . ④ The oil and gas reservoirs in the Lunpola Basin have the distribution law of “structural traps in the north and south, and lithologic traps in the center”. Structural traps are mainly distributed in the thrust nappe belt in the north and the Changshan uplift in the south, forming “self-generation and self-storage” or “lower-generation and upper-storage” reservoirs. While lithologic traps are mainly distributed in the central sag, forming “self-generation and self-storage” reservoirs. ⑤ The source-reservoir-caprock combination conditions are good in the structural traps in the footwall of the northern thrust nappe belt and the lithologic traps in the southern slope belt of Jianjiacuo depression,, and they are the most favorable oil and gas exploration zones in the Lunpola Basin.

Dynamic reconstruction of the hydrocarbon generation, accumulation, and evolution history in ultra-deeply-buried strata

The evolution mechanism of hydrocarbons in ultra-deeply-buried and ultra-old strata is the core issue of petroleum geology moving towards Deep Earth. Reconstructing the evolutionary history of ultra-deeply-buried hydrocarbons is the key to shedding light on deep hydrocarbon accumulation and evolution mechanisms. Furthermore, it can help point out directions for oil and gas exploration in Deep Earth. Anyue gas field in the central Sichuan Basin is the Frontier of deep natural gas exploration in China. This study selected the natural gas reservoirs of the Upper Sinian Dengying Formation in the central Sichuan Basin as the research object. By integrating analysis of natural gas geochemical characteristics, source rock evaluation, reservoir bitumen-source correlation, inclusion analysis, one-dimensional and two-dimensional hydrocarbon accumulation simulations, the generation and evolution of hydrocarbons in different structural regions, namely the inherited paleo-uplift and slope area in central Sichuan Basin, have been dynamically restored and compared. The results show that: 1) The natural gas of the ultra-deeply-buried Sinian Dengying formation in central Sichuan is typical oil-cracking gas from the paleo-oil reservoir. The Sinian gas is mainly sourced from the Qiongzhusi/Maidiping Formation. 2) The formation of Sinian gas reservoirs includes three stages: the formation of paleo-oil-reservoirs; the cracking of paleo-oil-reservoirs into paleo-gas-reservoirs; the adjustment of the paleo-gas-reservoirs. 3) Source rock and reservoir evaluation, quantitative solid bitumen analysis, and hydrocarbon accumulation simulation show that the natural gas accumulation conditions in the slope area are better than in the inherited uplift area. The scale of the paleo-oil-reservoirs in the slope area may be greater than that in the inherited uplift area.

Natural gas accumulation conditions and exploration prospects of the Middle Permian Qixia Formation in the Sichuan Basin

Exploration of natural gases in the Middle Permian Qixia Formation has achieved a breakthrough in the central and western Sichuan Basin since 2010. This study discusses the quality of dolomite reservoirs and source rocks, trap types and hydrocarbon charging history and proposes that good accumulation conditions are the basis for the large-scale enrichment of natural gas in the Qixia Formation. The high-quality reservoirs in the Qixia Formation are dolomites that primarily occur along platform margins and in the inner-platform shoals surrounding the Caledonian palaeo-uplifts. The Qixia gases originated mainly from the Cambrian and Permian mudstone source rocks. The overlaying Permian source rocks and the underlying Cambrian source rocks are both widely distributed and could provide sufficient gases for dolomite reservoirs. Additionally, the structural or structural-lithologic traps formed by an overlap of the Qixia dolomites and structurally high are favourable for oil and gas accumulation. The Qixia Formation had experienced four episodes of oil and gas charging from the middle-late Triassic to the Early Cretaceous, and traps located in structural-high zones are most favourable for hydrocarbon accumulation. Thus, the Qixia Formation has excellent accumulation conditions for the formation of large-scale gas fields. The concealed structural belts in the footwall of fault No. 1, the Longmenshan–Daxingchang structural belts and the periphery Gaomo–Shehong palaeo-uplift are the key zones for large-scale gas exploration in the Qixia Formation. The Qixia Formation is an important strategic replacement field for natural gas exploration in the Sichuan Basin following the Ediacaran Dengying Formation and the Cambrian Longwangmiao Formation.

Study on gas accumulation conditions of continental shale in Es3 member in the northern dongpu depression, eastern China

The organic-rich shales in the northern Dongpu Depression were deposited in deep and semi-deep lakes based upon evidence from the geochemical characteristic and rock mineral of the Es3 member. The results show that these rocks gradually decrease in abundance and deterioration of organic matter types from the center of the salt lake towards the edges. The development of high-quality shales in Es3 member is due to stratified sedimentation of a deep water, narrow basin water body. The saline lake region has a high TOC content, primarily type I derived from low-grade aquatic organisms. The minerals consist of a variety of mainly clay minerals (31–71%), quartz (11.2–57.9%), plagioclase (3.3–22.1%), dolomite (1.8–19.9%), and pyrite (1–4.1%). The water body was mainly brackish to super-brackish, which has solid limitations and severe salinity stratification, resulting in stable anoxic conditions of the bottom water and conducive to preserving organic matter. The shales were divided into massive silty shale facies, laminated paste shale facies, and laminated gray shale facies according to the mineral composition and microstructure. Comparing the geochemical characteristics, the laminated calcareous shale lithofacies of the deep to semi-deep lacustrine environments favor shale oil and gas occurrence. Pores consist of inorganic pores (intergranular mineral pores, dissolution pores, clay mineral interlayer cracks, mineral intergranular pores micropores, dissolution pores, clay mineral layer cracks, and cracks) with relatively few organic pores. There are many types of natural gas in the study area. The oil-type gas came from the lacustrine shale rock in Es3 member of Shahejie Formation, the coal-derived gas came from the high mature coal-based gas in the deep Carboniferous-Permian system, and the mixed gas was the mixed source of the above two source rocks. Multiple sets of overlying halite provided adequate seals within the depression and were conducive to the accumulation and preservation of hydrocarbons throughout the basin.

A preliminary study on the geological conditions and indexes for the accumulation of shale gas in the marine-continental transitional facies sediments in the South North China Basin

At present, the Carboniferous-Permian shale gas in the South North China Basin is still in the exploration stage, and the understanding of the microscopic pore structures, mineral composition and hydrocarbon enrichment law of the marine-continental transitional shale gas reservoirs in this area is extremely limited. In this paper, taking the Carboniferous-Permian shale gas reservoir in the South North China Basin as an example, the geological conditions of shale gas accumulation have been systematically studied using a large amount of sedimentary, logging, seismic, core, geochemical, physical property, and scanning electron microscope data. The study shows that the transitional dark shale is stable and widely distributed in the South North China Basin. Among them, the average thickness of the high-quality shale in the Taiyuan Formation is 67 m, while that of the Shanxi Formation is 56 m. Carboniferous and Permian are the main strata for the distribution of shale gas resources. Among them, the dark shale developed in the Taiyuan and Shanxi Formations has the largest thickness and the highest organic matter abundance. In addition, the organic matter types of the Upper Paleozoic coal-measure source rocks in the South North China are mainly II2-III types, and a small part of them belong to II1 types. The brittle minerals in the target shale are mainly quartz, and the content of illite is the highest among the clay minerals. Porosity is negatively correlated with clay mineral content, and positively correlated with quartz and TOC content. In addition, the permeability is negatively correlated with the organic matter content. Finally, the criteria for key indicators of the transitional shale gas reservoirs in the South North China Basin were developed.

Geological Characteristics and Controlling Factors of Deep Shale Gas Enrichment of the Wufeng-Longmaxi Formation in the Southern Sichuan Basin, China

Abstract To identify the factors controlling high-quality deep shale gas reservoirs and the exploration and development potential of the Lower Paleozoic marine shale in the Sichuan Basin, the sedimentary environment of deep shale was comprehensively analysed using core thin sections, scanning electron microscopy, gamma ray spectrometry logging, and elemental logging data. In addition, the geological conditions of deep shale gas accumulation and the effect of tectonic processes on the preservation conditions are discussed based on the experimental data of mineral composition analysis, geochemical features, and reservoir spatial characteristics. (1) The sedimentary environment changes from an anoxic water environment to an oxygen-rich oxidizing environment from bottom to top in the Wufeng-Longmaxi Formation in southern Sichuan. The deep shale gas reservoir shows overpressure and rich gas characteristics, namely, high formation pressure (2.0~2.2), high porosity (20%~55%), and high gas content (4.0~5.0 m3/t). (2) The favourable sedimentary environment has a higher hydrocarbon generation potential and deposits of rich organic matter and siliceous particles. During the hydrocarbon generation process, the rich organic matter generates a large number of organic pores and a large specific surface area, which provides the main reservoir and adsorption space for free and adsorbed shale gas. A large number of biogenic siliceous particles provide a solid rock support framework for the shale reservoir, thereby maintaining excellent reservoir physical properties. (3) Late and small stratigraphic uplifts result in a short shale gas escape time and favourable preservation conditions. Additionally, the small-scale faults and a high-angle intersection between the fracture strike and the geostress direction are conducive to the preservation of shale gas. (4) A high formation pressure coefficient, a sedimentary environment rich in organic siliceous deep-water continental shelf microfacies, and a relatively stable tectonic structure are conducive to the accumulation of deep shale gas.

Hydrocarbon accumulation model based on threshold combination control and favorable zone prediction for the lower Enping Formation, Southern Lufeng sag

Deep complex oil and gas reservoirs are the future directions of oil and gas exploration. The exploration potential of Paleocene deposits in the Lufeng sag is enormous. However, due to the greater burial depth and complex oil and gas accumulation conditions of the Paleocene, few large-scale reservoirs have been discovered and the next exploration strategy is unclear. In this study, based on the Paleocene geological data of the Southern Lufeng sag, a model of hydrocarbon accumulation based on functional element control is constructed using geostatistical and numerical simulation techniques. The hydrocarbon accumulation elements, thresholds, boundaries and scopes are clarified, and the favorable zones of hydrocarbon accumulation of the lower Enping Formation are predicted using the model of hydrocarbon accumulation based on threshold combination control. The results indicate that the source rock, reservoir, caprock, and low-potential area are the four functional elements controlling hydrocarbon accumulation. Since there are three types of low-potential zones, a total of six accumulation elements are considered to control hydrocarbon accumulation, and the corresponding hydrocarbon accumulation control thresholds are determined by the model of hydrocarbon accumulation according to the controlling effects of these accumulation elements. The predicted Type I favorable zones are located in the eastern part of Lufeng 13 east sub-sag and the northern and southern parts of Lufeng 7 sub-sag; Type II favorable zones are located in the western part and around the Lufeng 13 east sub-sag; Type III favorable zones are adjacent to Type II favorable zones. The hydrocarbon shows are all located in the overlapping zone of five or more accumulation elements. Cited as: Zhang, L., Pang, X., Pang, H., Huo, X., Ma, K., Huang, S. Hydrocarbon accumulation model based on threshold combination control and favorable zone prediction for the lower Enping Formation, Southern Lufeng sag. Advances in Geo-Energy Research, 2022, 6(5): 438-450. https://doi.org/10.46690/ager.2022.05.08

Reservoir Characteristics and Resource Potential Analysis of Transitional Shale Gas in Southern Sichuan Basin

Natural gas is a clean and efficient energy source. Shale gas, one of the unconventional natural gases, is becoming an indispensable part of natural gas. Compared with marine facies shale gas, which has large-scale exploitation, marine and continental transitional facies shale gas have greater development potential. It could be the new direction of development in the future. In this article, the basic geological characteristics, sedimentary environment, and reservoir characteristics of organic-rich transitional facies shale in the southern Sichuan basin are analyzed by lithologic characteristics, chemical element analysis, reservoir space, gas bearing characteristics, and so on and are compared with domestic and abroad transitional shale gas. The results show that the sedimentary period of transitional shale of Upper Permian Leping Formation has a high paleoproductivity level and deposition rate favorable for the accumulation of organic matter in southern Sichuan basin. It was warm and humid paleoclimatic by Sr, V, Cr, Ni, Co, and other trace elements analysis. According to the experimental test analysis of reservoir characteristics, the organic matter is mainly type Ⅲ kerogen, and the thermal evolution degree is mainly overmature in the reservoir. The reservoir space is mainly of microfractures and micropores. The main types of micropore development are intergranular pore, intragranular pore, and organic pore. Compared with other shale gas regions that form industrial airflow, the study region with large thickness, highly brittle mineral content, high level of organic carbon content, and excellent gas-bearing characteristics, it has favorable conditions for shale gas accumulation. The southern Sichuan basin could be the key area for breakthroughs in the exploration and development of transitional shale gas in the next step.

Methane Storage Capacity of Permian Shales with Type III Kerogen in the Lower Yangtze Area, Eastern China

Marine–terrestrial transitional Permian shales occur throughout South China and have suitable geological and geochemical conditions for shale gas accumulation. However, the Permian shales have not made commercial exploitation, which causes uncertainly for future exploration. In this study, high-pressure methane (CH4) adsorption experiments were carried out on the Permian shales in the Lower Yangtze area, and the influences of total organic carbon (TOC) content and temperature on adsorption parameters were investigated. The characteristics and main controlling factors of methane storage capacity (MSC) of the Permian shales are discussed. The results show that the maximum adsorption and the adsorbed phase density of these Permian samples are positively correlated with TOC contents but negatively correlated with temperatures. The pores of organic matter in shale, especially a large number of micropores and mesopores, can provide important sites for methane storage. Due to underdeveloped pore structure and poor connectivity, the methane adsorption capacities of the Permian shales are significantly lower than those of marine shales. Compared with the Longmaxi shales, the lower porosity and lower methane adsorption of the Permian shales are reasonable explanations for their lower gas-in-place (GIP) contents. It is not suitable to apply the index system of marine shales to the evaluation of marine–terrestrial transitional shales. The further exploration of Permian shales in the study area should be extended to overpressure stable reservoirs with high TOC contents (e.g., >5%), high porosity (e.g., >3%), and deep burial (e.g., >2000 m).