Gas Accumulation Model Research Articles

Main controlling factors and exploration enlightenment of aluminous rock series gas reservoirs in Ordos Basin, NW China

Based on the data of outcrop, core, logging, gas testing, and experiments, the natural gas accumulation and aluminous rock mineralization integrated research was adopted to analyze the controlling factors of aluminous rock series effective reservoirs in the Ordos Basin, NW China, as well as the configuration of coal-measure source rocks and aluminous rock series reservoirs. A natural gas accumulation model was constructed to evaluate the gas exploration potential of aluminous rock series under coal seam in the basin. The effective reservoirs of aluminous rock series in the Ordos Basin are composed of honeycomb-shaped bauxites with porous residual pisolitic and detrital structures, with the diasporite content of greater than 80% and dissolved pores as the main storage space. The bauxite reservoirs are formed under a model that planation controls the material supply, karst paleogeomorphology controls diagenesis, and land surface leaching improves reservoir quality. The hot humid climate and sea level changes in the Late Carboniferous–Early Permian dominated the development of a typical coal-aluminum-iron three-stage stratigraphic structure. The natural gas generated by the extensive hydrocarbon generation of coal-measure source rocks was accumulated in aluminous rock series under the coal seam, indicating a model of hydrocarbon accumulation under the source. During the Upper Carboniferous–Lower Permian, the relatively low-lying area on the edge of an ancient land or island in the North China landmass was developed. The gas reservoirs of aluminous rock series, which are clustered at multiple points in lenticular shape, are important new natural gas exploration fields with great potential in the Upper Paleozoic of North China Craton.

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.

A New Natural Gas Accumulation Model in the Triassic Xujiahe Formation: A Case Study in the Tongjiang-Malubei Area of the Sichuan Basin

The natural gas in the Triassic Xujiahe Formation (T3x) is reported to be mainly derived from the T3x source rock itself. Here, we report a new natural gas accumulation model, which demonstrates that the T3x gas in the Tongjiang-Malubei (TM) area is derived from both T3x and underline marine source rocks. The T3x gas in the TM area is characterized by CH4 with a gas dryness coefficient above 0.99, indicating a high thermal maturity. The δ13C values of the methane, ethane, and propane in the T3x gas in the TM area are −33.7~−29.2‰, −32.7~−28.3‰, and −32.8~−29.5‰, respectively. Compared with the T3x gas in the Yuanba area, which was sourced from the T3x source rock, the T3x gas in the TM area contains heavier δ13C in methane and lighter δ13C in ethane, showing a partial reversal carbon isotope distribution (δ13C1 > δ13C2). According to their chemical and isotopic compositions, the T3x gas in the TM area was a mixture of coal-type and oil-type gases. The coal-type gas was mainly derived from the type III kerogen of the T3x source rock, and the oil-type gas was derived from the type-I kerogen of marine source rock in the Permian Wujiaping Formation (P3w). The oil-type gas migrated upward along the deep-seated faults that connect the P3w source rock and T3x sandstone reservoirs, and then mixed with coal-type gas in the T3x reservoirs, resulting in large-scale gas accumulation. This new gas accumulation model is controlled by a dual gas source supply and a high efficiency migration via the fault system. The findings of this study can help us to better understand the gas accumulation mechanism with the development of late-stage penetrating faults, which not only have implications for future petroleum exploration and development in the TM area, but also affect other analogous areas in the Sichuan Basin.

Densification Mechanism and Natural Gas Accumulation Process, Triassic Xujiahe Formation, Hechuan Area, Sichuan Basin, China

Abstract We have witnessed a skyrocketing development of tight gas in China. However, all developed gas field in China face the obstacle of the decrease of production. The Xujiahe Formation in Sichuan Basin shows a promising future for the next big gas field. In this work, we will shed light on the densification mechanism and natural gas accumulation process of Triassic Xujiahe Formation, Hechuan Area, Sichuan Basin through physical experiments and theory analysis. We describe the reservoir characteristics. The diagenesis types and characteristics of sandstone reservoirs in the promising future of the next big gas field. In this work, we will shed light on the densification mechanism and natural gas accumulation process of Triassic Xujiahe Formation, Hechuan Area, Sichuan Basin through physical experiments and theory analysis. We describe the reservoir characteristics. The diagenesis types and characteristics of sandstone reservoirs in the second Member of Xujiahe Formation in Hechuan area are analyzed by means of rock thin section, cast thin section, and mercury injection. By observing the microscopic characteristics, types, and homogenization temperature distribution of fluid inclusions, the accumulation period of natural gas in Hechuan gas field is given, and the accumulation process of natural gas is revealed. The results show that (1) the natural gas charging the tight sandstone reservoirs of the Upper Triassic Xujiahe Formation in Hechuan area is a continuous process. The gas accumulation period can be roughly divided into two stages; (2) combining with the analysis of the hydrocarbon accumulation period of time, we put forward the natural gas accumulation model of the Xujiahe Formation, Hechuan area: the natural gas accumulation is accompanied by formation densification.

Research on the Tectonic Characteristics and Hydrocarbon Prospects in the Northern Area of the South Yellow Sea Based on Gravity and Magnetic Data

To further explore the geological structure and the Mesozoic–Paleozoic hydrocarbon prospects in the northern area of the South Yellow Sea (SYS), multiple geological and geophysical data were systematically gathered and compiled, including gravity and magnetic data, seismic surveys, drilling data, and previous research results. The characteristics and genesis of the gravity and magnetic anomalies are examined. This study employs residual gravity anomalies and multiple edge detection methods to identify fault lineament structures and assess the tectonic framework. Moreover, the study utilizes 2.5D gravity-seismic joint modellings and regression analysis to estimate the basement depth. Additionally, the study examines the basement characteristics and discusses the thickness of the Mesozoic–Paleozoic strata. Finally, the study further identifies prospects for hydrocarbons in the Mesozoic–Paleozoic. Our findings show that the faults are incredibly abundant and that the intensity of fault activity weakens gradually from NW to SE. Specifically, NE (NEE) trending faults are interlaced and cut off by NW (NWW), near-EW, and near-SN trending secondary faults, which form an en-echelon composite faults system with a dominant NE (NEE) orientation. Thick Mesozoic–Paleozoic strata are preserved, but we observe distinct variations in basement characteristics and the pre-Cenozoic structural deformation along the N-S direction. Therefore, the Northern Basin of SYS (NBSYS) and the Middle Uplift of SYS (MUSYS) are characterized by alternating sags and bulges in the S-N direction and in the E-W direction, respectively, forming a chessboard tectonic framework. Considering the oil and gas accumulation model, we identify three target hydrocarbon prospects in the NBSYS and two favorable hydrocarbon prospects in the MUSYS.

Natural gas characteristics and gas-source comparisons of the Lower Triassic Feixianguan Formation, Eastern Sichuan Basin, China

There is great controversy regarding the origin and source of natural gas in the Lower Triassic Feixianguan Formation in the Eastern Sichuan Basin. This seriously restricts the study of natural gas dynamics in the Feixianguan Formation and thus hampers natural gas exploration in the region, so further study is urgently required. Using experimental tests of natural gas composition, stable isotopes, and noble gas isotopes with gas chromatography (GC) and mass spectrometry (MS) studies of source rock and reservoir asphalt saturated hydrocarbons, the natural gas geochemical characteristics, the genetic identification and a gas-source comparison of the Feixianguan Formation were studied. Then, constrained by the thermal history, the histories of gas generation and expulsion were restored by basin simulation technology. Finally, a gas accumulation model was established for the Feixianguan Formation. The results showed that (1) the H2S-rich and H2S-poor gas reservoirs of the Feixianguan Formation are distributed on the east and west sides of the Kaijiang-Liangping trough in the Eastern Sichuan Basin, respectively. The carbon and hydrogen isotope compositions of the natural gas in the gas reservoirs are generally heavy and have typical characteristics of high-maturity dry gas reservoirs. (2) The natural gas of the Feixianguan Formation is organic thermogenic gas, which is mainly oil-type gas generated by the secondary cracking of crude oil. The gas-generating parent material is mainly type II kerogen. (3) The natural gas of the Feixianguan Formation in the Eastern Sichuan Basin was mainly generated by argillaceous source rocks of the Upper Permian Longtan Formation. (4) Natural gas accumulation occurred as follows: the paleo-structure heights were filled with crude oil in the Early Jurassic, and paleo-oil reservoirs were formed in the Feixianguan Formation; during the Middle-Late Jurassic, the paleo-oil reservoirs were cracked when the reservoir temperatures rose above 160 °C, and paleo-gas reservoirs were formed. Since the end of the Late Jurassic, the paleo-gas reservoirs have been adjusted and reformed to form the present-day natural gas reservoirs. These results provide a basis for studying natural gas accumulation dynamics of the Feixianguan Formation in the Eastern Sichuan Basin.

Pressure Evolution Mechanism of Marine Shale Reservoirs and Shale Gas Accumulation Model: Evidence from Fluid Inclusions in the Wufeng–Longmaxi Formation in the Basin Margin Structural Transition Zone in Northern Guizhou Province, China

The Wufeng–Longmaxi Formation in northern Guizhou Province is the dominant shale gas exploration and development strata in China. This study investigates the Shixi and Daozhen synclines, which are located in the basin margin transition zone. This region experienced complex tectonic stages and superimposed transformations, resulting in heterogeneous preservation conditions and shale reservoir pressure evolution in different tectonic units of the Wufeng–Longmaxi Formation. Based on fluid inclusion analysis, the types of fluid inclusion and the fluid filling stages of the Wufeng–Longmaxi shale reservoir were determined by laser Raman analysis and homogenization temperature and salinity tests. It was found that the fluid inclusion density and paleopressure in each filling stage were then restored. The results confirm that: ① Both the Shixi syncline and Daozhen syncline Wufeng–Longmaxi shale reservoirs experienced two fluid filling phases, in the early Yanshanian and late Yanshanian–Himalayan, respectively. In the course of tectonic evolution, the Wufeng–Longmaxi Formation in the Shixi and Daozhen synclines experienced pressure relief to some extent during the two aforementioned key fluid charging periods but remained in overpressurized states overall; ② The Wufeng–Longmaxi Formations of the Shixi and Daozhen synclines are characterized by high-density methane inclusions; ③ Based on the differences in the structural preservation conditions, the pressure evolution mechanisms of the Wufeng–Longmaxi Formation Shales during the important tectonic evolution period in northern Guizhou Province were revealed. Furthermore, differential enrichment and accumulation models of shale gas were established and named “facing thrust structural sealing type (Shixi syncline)” and “reverse fault lateral blocking type (Daozhen syncline)”.

Oil and gas exploration potential in the exclusive economic zone of the Cuba's sector of the Gulf of Mexico

Based on the latest interpretation results of 2D seismic data, combined with drilling, logging, and geochemical data, the reservoir‐forming conditions of the exclusive economic zone in the Cuba's sector of the Gulf of Mexico (Hereinafter refer to GOM) are studied systematically, and the oil and gas accumulation model in the study area is predicted. The favourable exploration zones are evaluated and optimized. The results show that: ① High quality Upper Jurassic‐Lower Cretaceous and potential Middle‐Lower Jurassic source rocks are developed in the study area. ② A set of Upper Jurassic‐Lower Cretaceous petroleum system and a potential Middle‐Lower Jurassic petroleum system are mainly developed in the study area. ③ At present, the proved petroleum system are found in the Upper Jurassic‐Lower Cretaceous strata. The oil and gas mainly comes from the Upper Jurassic‐Lower Cretaceous source rocks, and the reservoirs are mainly Upper Jurassic‐Lower Cretaceous fractured carbonate. The main seals are inter‐reservoir tight limestone, marl, and Palaeocene mudstone. ④ The thrust structural traps in the footwall of the fold thrust belt on the south side of the Florida platform, the margin zones of the Florida platform and Yucatan platform, and the Middle‐Lower Jurassic structural traps on the south side of the Yucatan platform have superior source‐reservoir‐cap configuration conditions. It is suggested that these areas have good oil and gas exploration potential in GOM.

Study on the Tight Gas Accumulation Process and Model in the Transition Zone at the Margin of the Basin: A Case Study on the Permian Lower Shihezi Formation, Duguijiahan Block, Ordos Basin, Northern China

Recent discoveries of oil and gas have principally been located in the central part of the Ordos Basin, which is a petroliferous basin with the largest discovered reserves and annual production of tight sandstone gas in China. For tight sandstone gas reservoirs in the transition zone of the basin margin, the process of natural gas accumulation has remained relatively vaguely understood, because of the transitional accumulation of geological conditions such as structure, sedimentation, and preservation. In this study, thin-section identification and scanning electron microscopic observations of the reservoir core, measurement of the physical properties of the reservoir, microscopic petrography research and measurement of the homogenization temperature of fluid inclusions, digital simulations, and laser Raman spectroscopy analysis were combined to analyze the process of natural gas accumulation of the Permian Lower Shihezi Formation in Duguijiahan block, Hangjinqi area, northern Ordos Basin. The results showed that the Lower Shihezi Formation reservoir in the Duguijiahan block began gas charging in the southern part as early as the Early Cretaceous (130–128 Ma), and then gradually charged in the northern part. Three stages were identified in the digital simulations of gas charging, i.e., the breakthrough, rapid, and fully saturated stages. The initial porosity of the Lower Shihezi Formation reservoir ranged between 28% and 40%. Later, because of strong compaction and interstitial filling during burial, the sandstone porosity decreased rapidly, and densification (porosity < 10%) occurred in the mid–late Jurassic. This late tectonic uplift caused a continuous reduction in ground temperature, and diagenesis had a weak effect on pore transformation. The present porosity of the Lower Shihezi Formation reservoir basically inherited its characteristics in the late Early Cretaceous. The current average porosity of the reservoir is 8.58%, and the average permeability is 0.88 mD, and it can thus be characterized as a tight reservoir. The gas accumulation process of the Lower Shihezi Formation has three stages: (1) the depositional stage (C–P), corresponding to the depositional stage of the source-reservoir-cap combination in gas reservoir; (2) the natural gas accumulation stage (T–K1), corresponding to the period of rapid source rock maturation and natural gas charging step-by-step; and (3) the gas reservoir adjustment stage (K2–present), corresponding to the period of uplift and natural gas charging in the early stage that gradually migrated and accumulated northward along the fracture zone. Finally, the gas accumulation model in the transition zone at the margin of basin was established.

Determining the gas accumulation period using fluid inclusion observations: Xiang Zhong Basin, China

Abstract There are a large number of natural gas shows in the Upper Paleozoic of the central Hunan Basin. However, the hydrocarbon accumulation process was complicated due to the strong tectonic reformation in this area. A study of the natural gas accumulation period is of significance for determining gas accumulation models. In this research, the fluid inclusion samples were tested, the fluid inclusion occurrence characteristics, uniform temperature data, and reservoir evolution were analyzed, and four diagenetic periods and four diagenetic periods and three hydrocarbon accumulation periods were identified. (i) For the syntaxial stage, the filling is dark and nonluminous, and the fluid captured by the overgrowing cement around the particles is mainly seawater; (ii) for the (Early) Mesogenetic burial stage, the calcite cement grows around the particles or micritic calcite matrix, and the fluid captured is mainly brine; (iii) for (Late) Mesogenetic burial stage, two sets of decomposed fissures developed in massive calcite colloids with non-luminous gas-rich hydrocarbon inclusions within the crystals; and (iv) for Telogenetic burial stage, weakly fluorescent pure gaseous hydrocarbon inclusions are developed in luminescent calcite veins. The result indicates that the organic inclusions in the Lower Carboniferous of the central Hunan Basin are dominated by weakly fluorescent and nonfluorescent rich gas inclusions and pure gas-phase inclusions, with three stages of hydrocarbon filling. By integrating the average homogenization temperatures on burial curves, the three charging orders correspond to 260–250 Ma during the Late Permian, 249–245 Ma during the Early Triassic, and 208–170 Ma during the Late Triassic. Dense reservoir characteristics reveal deep basin gas reservoir in deep basin.

Study of the gas sources of the Ordovician gas reservoir in the Central-Eastern Ordos Basin

The source of the natural gas in the Lower Paleozoic Ordovician strata in the Ordos Basin, China is a controversial issue. In the present study, the genesis and distribution characteristics of the Ordovician natural gas were qualitatively investigated based on the composition of the natural gas and the hydrocarbon isotopic composition. Then, the kinetics of the carbon isotope were analyzed to determine the proportions of the gas in the Ordovician gas reservoir contributed from the Carboniferous-Permian and Ordovician strata. The results show the following. Compared to the Upper Paleozoic natural gas, the Ordovician natural gas has a large dryness coefficient. In core areas where gypsum-salt rocks are developed, the gypsum-salt rocks completely isolate the gas sources. The weathering crust of the reservoir in the fifth member of the Majiagou Formation (Ma51+2) originates primarily from the Upper Paleozoic coal-measure source rocks, while the Ma55 and the pre-salt natural gas are mainly derived from the Ordovician source rocks. In the areas where the gypsum-salt rocks are relatively well-developed, the gypsum-salt rocks isolate the gas source to some extent, the pre-salt gas reservoir is mainly derived from the Lower Paleozoic source rocks, and this contribution gradually increases with increasing depth. In the areas where the gypsum-salt rocks are not developed, the proportion of the contribution of the Upper and Lower Paleozoic source rocks to the gas source of the Ordovician gas reservoir is mainly controlled by the volume of gas generated and the other accumulation conditions, and it does not reflect the isolation effect of the gypsum-salt rocks on the gas source. The Ordovician natural gas accumulation models in the central-eastern Ordos Basin can be divided into four types according to the differences in the gas sources.

Reservoir Forming Conditions and Enrichment Law of Tight Sandstone Gas in Upper Paleozoic in Ordos Basin

With the popularization of natural gas and the requirement of environmental protection, the development and utilization of natural gas are particularly important. The status of natural gas in China’s oil and gas exploration and development is constantly improving, and the country pays more and more attention to the exploitation and utilization of natural gas. The tight sandstone of Upper Paleozoic in Ordos Basin has the characteristics of low porosity, low permeability, and large area of concealed gas reservoirs. With the increasing demand for natural gas in China, systematic analysis and research on the geological conditions and enrichment law of large area gas reservoirs of tight sandstone of Upper Paleozoic in Ordos Basin to guide exploration and production also pose a great challenge to the current level of natural gas exploration and development in China. In order to solve this problem, this paper takes the Upper Paleozoic tight sandstone in Hangjinqi area in the north of Ordos Basin as the research object, summarizes the natural gas accumulation conditions of tight sandstone according to the geological characteristics of Ordos Basin, determines the main control factors of gas accumulation by superposition method in combination with the distribution characteristics of natural gas, simulates the dynamic process of gas accumulation, establishes the gas accumulation model, analyzes the conditions of gas accumulation and enrichment by statistical methods, summarizes the accumulation and enrichment rules of natural gas, and predicts the favorable exploration areas for natural gas. The results show that the relationship between hydrocarbon source rocks, traps, migration and transportation, and other reservoir-forming conditions and the distribution characteristics of natural gas is summarized, and the main controlling factors of reservoir-forming are determined by superposition method. We simulate the evolution process of faults, strata, oil, gas, and water flows in the study area and establish the dynamic reservoir-forming process of natural gas. By combining the reserve data with the reservoir source distance, reservoir facies type, and gas filling times, the reservoir-forming and enrichment conditions are studied by statistical analysis method, and the reservoir-forming and enrichment rules are summarized by combining the main controlling factors. The enrichment of natural gas is controlled by the development degree of source rocks, favorable tight sandstone combination, confluence channel, and local structure. According to the law of accumulation and enrichment, the division standards of favorable areas in different horizons are established, and the favorable exploration areas in the study area are predicted. The results provide theoretical data support for natural gas exploration in the study area.

Characteristics and the Model of Thermal Evolution and Gas Generation of Late Paleozoic Coal in the Qinshui Basin, Based on Hydrous Pyrolysis.

The Qinshui basin is an important coal-accumulating basin in China, and its Late Paleozoic coal is an important source rock of coalbed methane in the basin. Its thermal evolution and gas generation characteristics determined the grade of coalbed methane resources, especially the coal measure free gas resources in the basin. Late Paleozoic coal samples were collected for organic geochemical analysis, a high-volatile bituminous coal was used for hydrous pyrolysis, to propose the thermal evolution characteristics, gas generation characteristics, thermal evolution, and free gas accumulation model, and the Ordos Basin is compared. The results show that the variation trends of various geochemical parameters are different with the increase in Ro. Hydrous pyrolysis shows that the gas production potential of coal is excellent. The gases produced consist mainly of CH4, C2–, CO2, and H2. C2– is produced only before the simulated temperature of 550 °C, and oil is produced only before the temperature of 500 °C. The thermal evolution stages can be divided into the immature stage, symbiosis stage, wet gas stage, and dry gas stage, and the symbiosis stage can be divided into the preliminary stage and mainly gas stage. Ro, Tmax, (2+3)MP/(1+9)MP, saturated+arene, Vdaf, and H/C can be used as indicators of the thermal evolution stages. On the plane, the distribution of thermal evolution stages of the Shanxi Formation and the Taiyuan Formation is very alike. The gas generating strength of the Taiyuan Formation is higher than that of the Shanxi Formation. The gas generating strength in the north of the Taiyuan Formation is higher, while that in the south of the Shanxi Formation is higher. The second gas generation stage has a good spatio-temporal configuration relationship with accumulation factors, and the gas production is large, which is beneficial to the enrichment of the coal measure free gas resources. Relatively, the Ordos Basin has better prospects for exploration and development.

Oil Accumulation Model and Its Main Controlling Factors in Lower Yanchang Formation, Wuqi-Dingbianarea, Ordos Basin, China

Based on the studies of sedimentary facies, oil-source correlation, formation pressure structure, homogenization temperature of fluid inclusions, etc., the oil and gas accumulation model and main controlling factors in lower Yanchang Formation in Wuqi-Dibian area have been discussed. It is believed that two sets of source rocks, C7 and C9, are developed in study area, and hydrocarbon produced from layers of C8 and C9 is mainly from C7 source rock, followed by C9, according to oil-source correlation; hydrocarbon-generating pressurization of C7 source rock is the main driving force for the downward migration of oil. The high value area formed by the low value of overpressure difference between C7 and C8 is the main hydrocarbon accumulation area; deltaic front subaqueous distributary channel and mouth bar in lower Yanchang formation are the main accumulation spaces due to their good porosity and permeability; besides, C8 reservoir shows the characteristics of “episodic filling and continuous accumulation,” and they both are the undersource reservoir-forming combination; it is believed that the distribution of oil reservoir in Triassic series is controlled by the factors of “near source, low pressure, superior facies.”

Analysis of accumulation models of Middle Permian in Northwest Sichuan Basin

Great progress has been made in middle Permian exploration in Northwest Sichuan in recent years, but there are still many questions in understanding the hydrocarbon accumulation conditions. Due to the abundance of source rocks and the multi-term tectonic movements in this area, the hydrocarbon accumulation model is relatively complex, which has become the main problem to be solved urgently in oil and gas exploration. Based on the different tectonic backgrounds of the middle Permian in northwest Sichuan Basin, the thrust nappe belt, the hidden front belt, and the depression belt are taken as the research units to comb and compare the geologic conditions of the middle Permian reservoir. The evaluation of source rocks and the comparison of hydrocarbon sources suggest that the middle Permian hydrocarbon mainly comes from the bottom of the lower Cambrian and middle Permian, and the foreland orogeny promoted the thermal evolution of Paleozoic source rocks in northwest Sichuan to high maturity and over maturity stage. Based on a large number of reservoir physical properties data, the middle Permian reservoir has the characteristics of low porosity and low permeability, among which the thrust nappe belt and the hidden front belt have relatively high porosity and relatively developed fractures. The thick mudstone of Longtan formation constitutes the regional caprock in the study area and the preservation condition is good as a whole. However, the thrusting faults destroyed the sealing ability of the caprock in the nappe thrust belt. Typical reservoir profiles revealed that the trap types were different in the study area. The thrust fault traps are mainly developed in the thrust nappe belt, while the fault anticline traps are developed in the hidden front belt, and the structural lithological traps are developed in the depression belt. The different structural belts in northwest Sichuan have different oil and gas accumulation models, this paper built three hydrocarbon accumulation models by the analysis of reservoir formation conditions. The comprehensive analysis supposed the hidden front belt is close to the lower Cambrian source rock, and the reservoir heterogeneity is weak, faults connected source rock is developed, so it is a favorable oil and gas accumulation area in the middle Permian.

Natural Gas Accumulation Characteristics in the Linxing Area, Ordos Basin, NW China: Revealed from the Integrated Study of Fluid Inclusions and Basin Modeling

The Linxing area is located in the north of the eastern margin of the Ordos Basin, which has great resource potential for tight gas. In this paper, fluid inclusion analysis and basin modeling are the main means to clarify the gas accumulation mechanism of the Upper Paleozoic in the Linxing area. Petrographic analysis shows that fluid inclusions can be classified into 5 types: aqueous inclusions, hydrocarbon-bearing aqueous inclusions, hydrocarbon inclusions, crystal-bearing aqueous inclusions, and aqueous-carbonic inclusions. According to the statistical analysis of homogenization temperature and salinity of fluid inclusions, combined with the burial-thermal evolution, the study area was divided into 3 areas: the inner-magma baking area, the middle-anomal thermal area, and the outer-normal thermal area. The gas accumulation characteristics are differences among the 3 areas, the closer to Zijinshan magmatic pluton, the earlier gas accumulation period; and the vertical gas accumulation in the inner-magma baking area and the middle-anomal thermal area was not a slow and gradual process from bottom to top. The period from the Middle Jurassic to the Early Cretaceous is the key period for rapid pressure accumulation in the Upper Paleozoic reservoirs, which is consistent with the period of natural gas accumulation. The area near the Zijinshan magmatic pluton was the high fluid potential area during the gas accumulation period, which indicates that natural gas and other fluids migrated from Zijinshan magmatic pluton to the surrounding area. It is concluded that in the Linxing area, the Zijinshan magmatic pluton had a significant impact on natural gas accumulation, and the natural gas accumulation model under the control of magmatic thermal-tectonic effect was proposed.

Formation conditions and exploration direction of large natural gas reservoirs in the oil-prone Bohai Bay Basin, East China

Abstract The Bohai Bay Basin is a typical oil-prone basin, in which natural gas geological reserves have a small proportion. In this basin, the gas source rock is largely medium-deep lake mudstone with oil-prone type II2-II1 kerogens, and natural gas preservation conditions are poor due to active late tectonic movements. The formation conditions of large natural gas fields in the Bohai Bay Basin have been elusive. Based on the exploration results of Bohai Bay Basin and comparison with large gas fields in China and abroad, the formation conditions of conventional large-scale natural gas reservoirs in the Bohai Bay Basin were examined from accumulation dynamics, structure and sedimentation. The results show that the formation conditions of conventional large natural gas reservoirs in Bohai Bay Basin mainly include one core element and two key elements. The core factor is the strong sealing of Paleogene “quilt-like” overpressure mudstone. The two key factors include the rapid maturation and high-intensity gas generation of source rock in the late stage and large scale reservoir. On this basis, large-scale nature gas accumulation models in the Bohai Bay Basin have been worked out, including regional overpressure mudstone enriching model, local overpressure mudstone depleting model, sand-rich sedimentary subsag depleting model and late strongly-developed fault depleting model. It is found that Bozhong sag, northern Liaozhong sag and Banqiao sag have favorable conditions for the formation of large-scale natural gas reservoirs, and are worth exploring. The study results have important guidance for exploration of large scale natural gas reservoirs in the Bohai Bay Basin.

Analysis of major controlling geological factors on coalbed methane enrichment and accumulation model of low coal rank in Tuha-Santanghu Basin

The low-rank coalbed methane resources in the Tuha-Santanghu Basin are rich, but the degree of exploration is low. The main controlling factors and accumulation model of coalbed methane accumulation are insufficiently understood, which restricts the exploration and development practice. In order to find out the main controlling factors and accumulation mode of low rank coalbed methane in Tuha-Santanghu Basin, from the aspects of low coal rank coal seam distribution, coalbed methane gas types and origins, comprehensive considerations such as hydrogeology, tectonic and sedimentary conditions, etc, the reservoir-forming conditions of low rank coalbed methane gas are analyzed, and the accumulation model is proposed to further explore direction. The results show that hydrogeological condition affect the generation and enrichment of low rank coalbed methane in this area, which is an important conditions for the formation of low rank coalbed methane. It is advantageous to save the low-rank coalbed methane with weak runoff. Different tectonic conditions have different effects on the preservation of coalbed methane, which can be divided into favorable preservation and destructive preservation. The influence of coal-forming environment on coal’s gas-generating potential, top and bottom lithology and coal reservoir physical has an important impact on low rank coalbed methane. The comprehensive study proposes two types of low-rank coalbed methane accumulation models in the Tuha-Santanghu Basin: gas accumulation model of basin margin slope zone and gas accumulation model of stagnant confined water + lithologic plugging coalbed methane in small fault sag. Comprehensive analysis shows that coal-bearing slope zone of basin margin with favorable hydrogeological conditions and coalbed methane reservoir with good preservation conditions in small fault sag with retaining confined water+lithologic plugging characteristics will be the key exploration area in the future.

Distribution Characteristics and Accumulation Model for the Coal‐formed Gas Generated from Permo‐Carboniferous Coal Measures in Bohai Bay Basin, China: A Review

Coal‐formed gas generated from the Permo‐Carboniferous coal measures has become one of the most important targets for deep hydrocarbon exploration in the Bohai Bay Basin, offshore eastern China. However, the proven gas reserves from this source rock remain low to date, and the distribution characteristics and accumulation model for the coal‐formed gas are not clear. Here we review the coal‐formed gas deposits formed from the Permo‐Carboniferous coal measures in the Bohai Bay Basin. The accumulations are scattered, and dominated by middle‐small sized gas fields, of which the proven reserves ranging from 0.002 to 149.4×108 m3 with an average of 44.30×108 m3 and a mid‐point of 8.16×108 m3. The commercially valuable gas fields are mainly found in the central and southern parts of the basin. Vertically, the coal‐formed gas is accumulated at multiple stratigraphic levels from Paleogene to Archaeozoic, among which the Paleogene and Permo‐Carboniferous are the main reservoir strata. According to the transporting pathway, filling mechanism and the relationship between source rocks and reservoir, the coal‐formed gas accumulation model can be defined into three types: “Upward migrated, fault transported gas” accumulation model, “Laterally migrated, sandbody transported gas” accumulation model, and “Downward migrated, sub‐source, fracture transported gas” accumulation model. Source rock distribution, thermal evolution and hydrocarbon generation capacity are the fundamental controlling factors for the macro distribution and enrichment of the coal‐formed gas. The fault activity and the configuration of fault and caprock control the vertical enrichment pattern.

Remigration and leakage from continuous shale reservoirs: Insights from the Sichuan Basin and its periphery, China

Shale gas in the Sichuan Basin and its periphery potentially plays an important role in the world shale gas industry. An understanding of remigration and leakage from continuous shale reservoirs is very important for shale gas exploration, especially in the Sichuan Basin and its periphery. The shale gas accumulation models that relate to remigration and leakage were developed within the Wufeng and Longmaxi black shales in the Jiaoshiba and the Youyang blocks. First, a tectono-sedimentary history of the Wufeng and Longmaxi black shales in the Sichuan Basin and its periphery was developed based on the published literature. The history exhibits a continuous distribution of high-quality Wufeng and Longmaxi black shale, which is the foundation of the shale gas formation. Second, the shale gas remigration–accumulation model in the anticlines was clarified by using data collected from the shale gas fields in Jiaoshiba block. The shale gas model for the Jiaoshiba block was developed on the basis of a continuous shale reservoir distribution, differentiated structural deformation, and a gas self-sealed system. Third, the shale gas fault failure leakage model in the fault blocks and the erosion model in the residual areas were revealed based on the shale reservoir and shale gas content heterogeneity in the Youyang block. These two models were validated by available data including 13 two-dimensional seismic lines and 2 shale gas exploration vertical wells in the Youyang block. Shale gas areas with high gas resource and gas production rates in the anticlines were defined by the remigration–accumulation model. The fault failure leakage model was used to find shale gas with limited commercial potential, whereas commercial shale gas was largely lacking according to the erosion residual model. The study on remigration and leakage from continuous shale reservoirs in the Sichuan Basin and its periphery can be used to better understand and improve the exploration efforts based on resource preservation.