Gas Reservoir Model Research Articles

A Semi-Analytical Model for Gas–Water Two-Phase Productivity Prediction of Carbonate Gas Reservoirs

The productivity prediction of gas wells in carbonate gas reservoirs is greatly affected by the characteristics of gas–water two-phase flow and fracture seepage parameters. Compared with numerical simulation, the productivity prediction based on the analytical model is fast and widely used, but the traditional analytical model is fairly simplified while dealing with the nonlinear problem of the two-phase seepage equation, leading to a large discrepancy in the results of dynamic analysis. To solve this problem, this paper considers the characteristics of gas–water two-phase flow in the reservoir and fracture, uses the dual-medium model to characterize the stress sensitivity of the fracture and reservoir, and establishes a gas–water two-phase productivity prediction model for carbonate gas reservoirs. Combining the flowing material balance equation with the Newton iteration method, the nonlinear parameters of the percolation model are updated step by step with the use of average formation pressure, and the gas–water two-phase model is linearized through successive iterations to obtain the semi-analytical solution of the model. The accuracy of the model was verified using a comparison with the results of commercial numerical simulation software and field application, the gas–water two-phase productivity prediction curve was obtained, and the influence of sensitive parameters on productivity was analyzed. The results show that: (1) the semi-analytical solution method can efficiently deal with the gas–water two-phase nonlinear seepage problem and obtain the productivity prediction curve of carbonate gas wells rapidly and (2) the water production of the carbonate gas reservoir seriously affects the productivity of gas wells. During the development process, the production pressure difference should be reasonably controlled to reduce the negative impact of stress sensitivity on productivity performance.

Symbiotic Combination and Accumulation of Coal Measure Gas in the Daning–Jixian Block, Eastern Margin of Ordos Basin, China

Coal measure gas resources, including coalbed methane (CBM), shale gas, and tight gas are abundant in the Daning–Jixian Block. The complexity of the source–reservoir–cap relationship in the coal measure strata leads to unclear symbiotic characteristics and gas accumulation, which in turn, restrict the exploration and exploitation of the coal measure gas. In this study, the enrichment and accumulation of coal measure gas are discussed and summarized in detail. The results show that there are eight lithofacies and six reservoir combinations in the superposed strata of the coal measures in the study area. Controlled by the tidal flat-lagoon facies, the “sand-mud-coal” type mainly distributes in P1s2 and P1t, showing a good gas indication. Based on the variation of the total hydrocarbon content, key strata, and pressure coefficient of the coal measure gas reservoir, four superposed gas-bearing systems are identified in the vertical direction. According to the relationship between the gas-bearing system and gas reservoir, the enrichment of coal measure gas in the study area can be divided into three modes, including an intra-source enrichment mode, a near-source migration enrichment mode, and a far-source migration enrichment mode. The symbiotic accumulation of a coal measure gas model is further proposed, that is, an “Adjacent to co-source reservoir” type superimposed coalbed methane and shale gas reservoir model, a “Three gas symbiosis” superimposed reservoir model in the local gas-bearing system, and a “Co-source far reservoir” tight sandstone gas reservoir model. Clarifying the symbiotic relationship of coal measure gas reservoirs is beneficial to the exploration and further production of unconventional gas in the study area.

“Rigid-elastic chimera” pore skeleton model and overpressure porosity measurement method for shale: A case study of the deep overpressure siliceous shale of Silurian Longmaxi Formation in southern Sichuan Basin, SW China

Based on analysis of pore features and pore skeleton composition of shale, a “rigid elastic chimeric” pore skeleton model of shale gas reservoir was built. Pore deformation mechanisms leading to increase of shale porosity due to the pore skeleton deformation under overpressure were sorted out through analysis of stress on the shale pore and skeleton. After reviewing the difficulties and defects of existent porosity measurement methods, a dynamic deformed porosity measurement method was worked out and used to measure the porosity of overpressure Silurian Longmaxi Formation shale under real formation conditions in southern Sichuan Basin. The results show: (1) The shale reservoir is a mixture of inorganic rock particles and organic matter, which contains inorganic pores supported by rigid skeleton particles and organic pores supported by elastic-plastic particles, and thus has a special “rigid elastic chimeric” pore structure. (2) Under the action of formation overpressure, the inorganic pores have tiny changes that can be assumed that they don't change in porosity, while the organic pores may have large deformation due to skeleton compression, leading to the increase of radius, connectivity and ultimately porosity of these pores. (3) The “dynamic” deformation porosity measurement method combining high injection pressure helium porosity measurement and kerosene porosity measurement method under ultra-high variable pressure can accurately measure porosity of unconnected micro-pores under normal pressure conditions, and also the porosity increment caused by plastic skeleton compression deformation. (4) The pore deformation mechanism of shale may result in the “abnormal” phenomenon that the shale under formation conditions has higher porosity than that under normal pressure, so the overpressure shale reservoir is not necessarily “ultra-low in porosity”, and can have porosity over 10%. Application of this method in Well L210 in southern Sichuan has confirmed its practicality and reliability.

The High-Pressure Methane/Brine/Quartz Contact Angle and Its Influence on Gas Reservoir Capillaries

A capillary high-pressure optical cell (HPOC) combined with a confocal Raman system was used in this study of high-pressure methane/brine contact angles on a quartz surface. The contact angle was determined from the shape of the methane/brine/quartz interface; it increased with fluid pressure from 41° to 49° over a pressure range of 5.7–69.4 MPa. A linear relationship between the contact angle and the Raman shift was also observed. The experimentally measured contact angle was more accurately applied in calculations of capillary resistance than the empirically estimated 0°, and it provides an important parameter in the study of gas migration and production processes. For a natural gas reservoir, pore-throat capillary resistance was 33% lower than the traditionally accepted value, and low capillary resistance is conducive to deeply buried tight gas reservoirs becoming more gas saturated. As burial depth increases, capillary resistance initially decreases and passes through a maximum before decreasing again, rather than increasing linearly with depth. Our results provide critical parameters for gas reservoir production, modeling, and resource assessment. This non-destructive method may be useful for predicting contact angles through measurement of the Raman shift of the HPOC and fluid inclusions in the reservoir.

Architecture, genesis, and the sedimentary evolution model of a single sand body in tight sandstone reservoirs: A case from the Permian Shan-1–He 8 members in the northwest Ordos Basin, China

A single sand body is defined as a geological unit that is continuous vertically and horizontally but separated from the upper and lower sand bodies by mudstone or impermeable intercalation. The architecture of a single sand body is significant in the determination of hydrocarbon accumulation mechanisms in gas reservoirs, especially for exploitation of multiple tight sandstone gas (TSG) reservoirs. One such example is the gas reservoirs in the Tianhuan Depression, China, where the architecture and genesis of sand bodies are poorly understood. Based on the geologic background and sedimentary characteristics, the evolution of the distributary channel in the Tianhuan Depression has been examined using data from geological outcrops, cores, and well logs. The results showed that sand body architecture depends on the evolution of channel systems, and the scale and size of the channel are controlled by the sedimentary environment. Three kinds of sedimentary microfacies (distributary channel, channel mouth bar, and interdistributary bay) are mainly developed in the study area, and four types of single sand body stacking patterns (isolated, vertically superimposed, laterally tangentially superimposed, and horizontally bridged sand bodies) have formed in such a depositional environment. The target strata (Shan-1 and He-8 members) provide an ideal object for studying the evolution of the river and the architecture of the sand bodies. During the early stage of deposition, the sediment supply was insufficient, with restricted meandering river deltas dominating and sand bodies mostly existing as isolated types. Until the middle period of deposition, the sediment supply suddenly increased, the sedimentation rate accelerated with the decrease in the lake water base level, and the channel evolved into a large-scale braided river delta, generally forming superimposed sand bodies. By the late period of deposition, the provenance supply was reduced again; although braided river delta deposits were still dominant, the channel scale was restricted, and the sand bodies were predominantly isolated and horizontally bridged types. This work establishes a sedimentary evolution model for tight sandstone gas reservoirs, that is, a complete cycle of river evolution from small scale to large scale to terminal weakening, and discusses the genetic mechanism of single sand body architecture in such a depositional model.

Modeling a Multi-Parameter Interaction of Geophysical Controls for Production Optimization in Gas Shale Systems.

Well bottomhole pressure optimization issue has been a significant concern for efficiently developing unconventional systems due to strong stress sensitivity. Therefore, it is of practical interest to clarify influence mechanisms involved in stress sensitivity for gas shale, which is further included in the production model to determine main controlling factors for bottomhole pressure strategy optimization for long term hydrocarbon extraction. Currently, many production models were limited in exploring stress sensitivity mechanisms but adopted common empirical equations regarding net pore stress instead. In addition, geophysical control analysis for unconventional systems optimization was mostly conducted using local sensitivity qualitative analysis, which should be validated to be reliable and applicable to fields using multi-parameter interaction influence. As a result, in this paper, an efficient workflow to rationally optimize gas well production system was provided by combining the production model, orthogonal design approach, and response surface method. To be specific, the compound flow model for shale gas reservoirs, incorporating multiple stress sensitivity mechanisms, was proposed to function as a theoretical basis for production optimization simulation. Last but not least, local sensitivity analysis was conducted to qualitatively analyze the impact of influencing factors on 20 year-production of gas wells under different bottomhole production methods. The simulation results showed that the managed pressure drawdown scheme can be adopted for reservoirs with high reservoir pressure and tight matrix properties, while the high-pressure drawdown scheme is suitable for reservoir with better fracturing effect and high external water content. Finally, based on the proposed gas flow model and orthogonal design experiments, response surface design and single factor analysis as well, an optimization mathematical model for shale gas multi-parameter interaction was established, which intuitively quantified the effects of multi-geophysical controls on EUR increase in different production durations, including matrix properties, fracture properties, and production system indicator parameters. These findings provide a more reliable reference for production system optimization based on a series of mathematical approaches to improve overall long-term recovery from shale gas reservoirs.

Numerical Simulation and Sensitivity Analysis of Hydraulic Fracturing in Multilayered Thin Tight Sandstone Gas Reservoir

Hydraulic fracturing is a necessary measurement to realize the commercial exploitation of oil and gas, but its application in multilayered thin tight sandstone gas reservoirs is still not perfect, which usually have thin gas layers mixed with complex intervals, and shows a dramatic variation in geological and geomechanical properties in the vertical direction. When conventional hydraulic fracturing methods are applied to this kind of reservoir, it is hard to get proper fracture propagation, especially for fracture height control. Facing this situation, this paper proposes a numerical study of the hydraulic fracturing mechanism and analyzes its influencing factors in the multilayered thin tight sandstone gas reservoir. Relying on a real reservoir in the Ordos Basin in China, relevant geological and geomechanical parameters of major gas layers and interlayers are obtained. According to these parameters, the hydraulic fracturing simulation in the multilayered thin tight gas reservoir model is carried out, based on which, the sensitivity analysis of different geological and fracturing parameters which affect the fracture propagation is performed. Furthermore, a real low-production well after fracturing in this kind of reservoir is selected as an example, and based on the analysis, an optimized fracturing scheme is proposed to adapt to the characteristics of the reservoir. According to the comparison of fracturing and production simulations, the optimized fracturing scheme can prevent hydraulic fractures from breaking through thin interlayers, control the fracture height, and prevent fractures from communicating strata with a high water-bearing layer. At the same time, with the same amount of proppant and fracturing fluid, longer fracture length and better fracture conductivity are created, so that the productivity of the optimized fracture has been greatly improved.

Analysis of water invasion effect and development scheme design for deep water HHT gas reservoir: A case study of LS25 gas field

Based on the South China Sea deepwater high temperature and high pressure gas reservoir LS25 gas field, 3D geological model and a numerical reservoir model of LS25 gas field are established. Through numerical simulation of gas reservoir production, quantitative analysis of water invasion characteristics of 11 wells has been completed. The whole process of water invasion in space is as follows: bottom water conies in the early stage, forming water cone shape, the scale of the water body to the ridge increases, and the horizontal section completely emerges. Through comparative study, it is concluded that the combined water control technology of variable density screen pipe has the best water control effect. According to the prediction and analysis of the final production plan of variable density technology, it can prolong the water-free gas production period of the gas reservoir by 0.7 years, prolong the total production time by 1.9 years, increase the gas production by 1.9×108m3, and increase the recovery factor by 10.5% compared with that without water control measures. The research results are aimed to establish an optimal water control development model for buried hill gas reservoirs, and provide a good technical support for reasonable and scientific water control research of horizontal wells in offshore buried hill fractured gas reservoirs.

Experimental study of variable density compound water control based on continuous packer——A case study of deep-water HP/HT LS25 gas field in the South China Sea

Based on the deep-water high temperature and high pressure LS25 gas field in the Nanhai Reservoir, through the design of heterogeneous formations and the design of water control experimental schemes, physical simulation experiments of different gas reservoir water control processes have been completed, focusing on evaluating the variable density compound water control technology based on continuous packers. In terms of the adaptability of deep-water gas reservoirs, on this basis, combined with the experiment-mine scale conversion method, a water-controlled exploitation plan for deep water high-temperature and high-pressure gas reservoirs is given. The experimental results show that: (1) Under elastic production conditions, the water body of the bottom water in the gas reservoir rises in a “progressive” manner in the initial stage, and generally develops in a “cone progression” in the middle and late stages. (2) There are obvious differences in the effects of various water control processes. A single continuous sealing body has no obvious effect on bottom water control during the gas production period of a gas well, and a single variable density screen process has no obvious effect on water control in the early stage of gas well production. The effect is good, but the risk of water channeling cannot be avoided after the gas well breaks through. The experimental effect of the variable density composite water control process based on the continuous packer is good, and the bottom water coning effect has changed to a certain extent. The experiments show that the water-free gas production period of the composite water control process is 13.7 years, the total gas production time is extended to 15.8 years, the total gas production after water control is as high as 12.37×108m3, and the recovery rate of gas wells is 9.2%, which is higher than that of elastic production. The research results aim to establish an optimal water control development model for high temperature and high-pressure deep water gas reservoirs and provide a good technical support for rational and scientific research on water control in horizontal wells of offshore deep water gas reservoirs.

Simulation of gas flow behavior in shale gas reservoir

The importance of shale gas production in altering the global energy system is growing. There is consensus that hydraulic fracturing in horizontal wells is the most cost-effective and efficient method for accessing shale gas resources. For hydraulic fracturing to be successful in the long run as shale gas production expands, a number of key characteristics must be optimized. The research focuses on the development of reservoir simulators (Companion of St. Michael and St. George-International Monetary Exchange (CMG-IMEX)) and analyzing the parameters, which have a major impact on gas flow in the shale gas reservoir. In the process of gas flow characterization, the approach is to consider a dual porosity model for analyzing the reservoir simulation model of a shale gas reservoir. With the use of a model, we are able to analyze the flow of shale gas from tight reservoirs through the conductive fractures to the wellbore. The development of this research could lead to enhanced production from the shale gas wells.

Study on Permeability Stress-Sensitivity in Seepage-Geomechanical Coupling of Fractured Deep Tight Sandstone Gas Reservoirs

Accurately predicting the characteristics and influencing factors of permeability stress-sensitivity contributes to improving gas production in gas reservoirs. In this paper, the effects of effective stress on the permeability of fractured deep tight sandstone reservoirs were studied by laboratory tests. With the experimental results, a coupled seepage-geomechanical model for fractured deep tight sandstone gas reservoirs was constructed. The influences of pore pressure and geo-stress on permeability characteristics and gas production were studied by numerical simulation. The results indicate: (1) When the effective stress increases from 0 to 65 MPa, the permeability of the natural sample with fractures decreases by 81.28%, and the permeability of the intact core sample decreases by 54.67%. (2) When the pore pressure decreases from 120 to 85 MPa, the three-dimensional effective stress increases. The largest increase of the effective stress was along the vertical direction, which increased by 11~19 MPa. In addition, the permeability of the fractured zone and the intact rock along the vertical direction decreased by about 40% and 16%, respectively. (3) The mean square error between the historical gas production results and the results by simulation was 2.22 when considering the permeability stress-sensitivity, and 4.01 without considering the permeability stress-sensitivity. The proposed coupled seepage-geomechanical model with permeability stress-sensitivity proved to be more accurate in historical gas production comparison and prediction. This study provides a reliable optimization scheme for the development of fractured deep tight sandstone gas reservoirs.

A General Model for Analyzing the Unsteady Pressure Performance of Composite Gas Reservoirs

Based on the previous study of a single medium model, the dual medium model for the fractured composite reservoir and the triple medium model for a fracture–cavity composite reservoir was established, respectively. The similarities and differences in the corresponding pressure dynamic curves of each model were analyzed, and the general model of a composite gas reservoir composed of different inner and outer zones was obtained. The general model can be more easily used in actual production, and the accuracy and practicability of the model were verified by case analysis.

High-resolution sequence stratigraphy applied to turbidites: The case study of jurassic los molles formation, Neuquén basin, Argentina

High-Resolution Sequence Stratigraphy is fundamental for attaining a refined and representative geological 3D model for oil and gas reservoirs. For its application on turbidite systems it is essential to have a robust facies and facies association framework, recognizing architectural elements and the cyclicity in different frequencies on the stacking pattern. This study is widely based on a multi-scale approach (4th and 5th orders), integrating satellite image, outcrop descriptions and microscopic data to achieve a predictive depositional model through time. The Jurassic Los Molles Formation, Neuquén Basin, was chosen as a case study due to its outcrop quality of offshore shelf (Carreri section) and slope/basin plain settings (La Jardinera section). This enabled a rich comparison between facies associations, architectural elements, stacking patterns and cyclicity on turbidite systems of different palaeo physiographic settings. The Carreri offshore shelf turbidites display higher confinement with predominance of tractive structures and coarser grain-sizes as opposed to deepwater deposits. Their base level variations are recorded by the stacking of turbidite channel-overbank systems to delta front deposits and tidal bars that culminate important regressions. In contrast, in La Jardinera slope and basin plain succession, the falling stage system tract of turbidite sequences is characterized by amalgamated composed lobes and wide composed channels with coarser grain-sizes and erosive contacts. The lowstand system tract is represented by less amalgamated lobes and interlobes, suggesting the system backstepping until the muddy transgressive system tract. The workflow of this study allows a better understanding of the evolution of a sedimentary system, correlating this to important stratigraphic surfaces that can represent fluid flow barriers and reservoir heterogeneities that could impact on production data. High resolution sequence stratigraphy, especially in turbidite systems, is key for more accurate reserve estimates and for developing predictive and economic exploration and production strategies in the petroleum industry.

Rock physics model for shale gas reservoirs with nanopore adsorption

Abstract Shale gas is primarily concentrated in nanopores extensively distributed in shale. The elastic properties of nanopores are significantly different from those of pores of larger sizes due to surface effects. How nanopores and adsorbed fluids affect the overall elastic properties of rock is rarely studied. Based on a recently developed nano-elasticity theory, a new method for calculating elastic modulus of nanoporous media considering adsorption is proposed by performing a detailed analysis on the relationship of surface adsorption with surface effects. The surface parameters of nanopores (pore radius, surface elastic moduli) are converted to adsorbed gas ratio and adsorbed gas elastic moduli. The proposed method is then used in rock physics modeling to estimate the elastic properties of nanoporous shale. The quantitative relationships of the effective velocities with adsorbed gas ratio, adsorbed gas elastic modulus and porosity of the shale are established, respectively. An important finding is that the elastic properties of nanoporous shale can be enhanced by increasing adsorbed gas ratio and adsorbed gas elastic moduli. A comparison between the theoretical model with laboratory data and the well data is performed and the results indicate that they are in good agreement. The results in this paper may provide certain insights on rock physics for the quantitative characterization of elastic properties of shale.

Numerical Simulation of Well Type Optimization in Tridimensional Development of Multi-Layer Shale Gas Reservoir

Aimed at the development of shale gas reservoirs with large reservoir thickness and multiple layers, this paper carried out a numerical simulation study on the optimization of three different well types: horizontal well, deviated well, and vertical well. To make the model more in line with the characteristics of shale gas reservoirs, a two-phase gas–water seepage mathematical model of shale gas reservoirs was established, considering the adsorption and desorption of shale gas, Knudsen diffusion effect, and stress sensitivity effect. The embedded discrete fracture model was used to describe hydraulic fracture and natural fracture. Based on Fortran language, a numerical simulator for multi-layer development of shale gas reservoirs was compiled, and the calculation results were compared with the actual production data of Barnett shale gas reservoirs to verify the reliability of the numerical simulator. The spread range of hydraulic fractures in the reservoir with different natural fracture densities is calculated by the simulation to determine well spacing and fracture spacing. The orthogonal experimental design method is then used to optimize the best combination of well spacing and fracture spacing for different well types. The results show that the well productivity of the high-density (0.012 m/m2) natural fractures reservoir > the well productivity of the medium-density (0.006 m/m2) natural fractures reservoir > the well productivity of the low-density (0.001 m/m2) natural fractures reservoir. According to the design of the orthogonal test, it can be seen that the most significant factor affecting the productivity of horizontal wells is the fracture spacing in the Y direction. For deviated wells and vertical wells, the X-direction well spacing has the greatest impact on its productivity.

Fluid evolution and hydrocarbon accumulation model of ultra-deep gas reservoirs in Permian Qixia Formation of northwest Sichuan Basin, SW China

The fluid evolution and reservoir formation model of the ultra-deep gas reservoirs in the Permian Qixia Formation of the northwestern Sichuan Basin are investigated by using thin section, cathodoluminescence, inclusion temperature and U-Pb isotopic dating, combined with gas source identification plates and reservoir formation evolution profiles established based on burial history, thermal history, reservoir formation history and diagenetic evolution sequence. The fluid evolution of the marine ultra-deep gas reservoirs in the Qixia Formation has undergone two stages of dolomitization and one phase of hydrothermal action, two stages of oil and gas charging and two stages of associated burial dissolution. The diagenetic fluids include ancient seawater, atmospheric freshwater, deep hydrothermal fluid and hydrocarbon fluids. The two stages of hydrocarbon charging happened in the Late Triassic and Late Jurassic–Early Cretaceous respectively, and the Middle to Late Cretaceous is the period when the crude oil cracked massively into gas. The gas reservoirs in deep marine Permian strata of northwest Sichuan feature multiple source rocks, composite transportation, differential accumulation and late finalization. The natural gas in the Permian is mainly cracked gas from Permian marine mixed hydrocarbon source rocks, with cracked gas from crude oil in the deeper Sinian strata in local parts. The scale development of paleo-hydrocarbon reservoirs and the stable and good preservation conditions are the keys to the forming large-scale gas reservoirs.

Main controlling factors and enrichment model of a multi-layer tight sandstone gas reservoir: case study from the Linxing Gas Field, eastern Ordos Basin, Northern China

Main controlling factors and enrichment model of a multi-layer tight sandstone gas reservoir: case study from the Linxing Gas Field, eastern Ordos Basin, Northern China

Multiple Fuzzy Parameters Nonlinear Seepage model for Shale Gas Reservoirs

Multiple Fuzzy Parameters Nonlinear Seepage model for Shale Gas Reservoirs

Two-Phase Modeling Technology and Subsection Modeling Method of Natural Gas Hydrate: A Case Study in the Shenhu Sea Area

It is found that natural gas hydrate is not only a pore-filling material but also exists in the reservoir in the form of rock skeleton particles. Therefore, the traditional petrophysical simulation method cannot well describe the physical properties of natural gas hydrate reservoir. At the same time, the physical properties of the hydrate layer and its associated free gas layer are quite different, so it is difficult to fit the physical properties of the two media using traditional modeling methods. The two-phase modeling technology used in this paper is the equivalent medium modeling technology based on BK solid substitution theory and Gassmann fluid substitution theory, which simulates hydrate particles in rock skeleton and hydrate filling in pores, respectively. The forward simulation results show that the two-phase simulation technology of natural gas hydrate can well fit the P-wave and S-wave velocity information of the medium. At the same time, the equivalent medium model of the free gas reservoir is established by using only Gassmann fluid substitution theory. The practical application shows that the subsection modeling method can well solve the problem of the too large difference between the two sets of reservoir physical properties and make the calibration results of forward modeling synthetic records more accurate.

Formation mechanisms, potentials and exploration practices of large lithologic gas reservoirs in and around an intracratonic rift: Taking the Sinian—Cambrian of Sichuan Basin as an example

By examining structures, sediments, reservoirs and accumulation assemblages in the Deyang—Anyue rift and its surrounding area, four new understandings are obtained. First, during the initiation period of Deyang—Anyue rift, multiple groups of faults developed in the rift due to the effect of tensile force, bringing about multiple mound and shoal belts controlled by horsts in the second member of the Sinian Dengying Formation; in the development stage of the rift, the boundary faults of the rift controlled the development of mound and shoal belts at the platform margin in the fourth member of Dengying Formation; during the shrinkage period of the rift, platform margin grain shoals of the Cambrian Canglangpu Formation developed in the rift margin. Second, four sets of large-scale mound and shoal reservoirs in the second member of Dengying Formation, the fourth member of Dengying Formation, Canglangpu Formation and Longwangmiao Formation overlap with several sets of source rocks such as Qiongzhusi Formation source rocks and Dengying Formation argillaceous limestone or dolomite developed inside and outside the rift, forming good source-reservoir-cap rock combinations; the sealing of tight rock layers in the lateral and updip direction results in the formation model of large lithologic gas reservoirs of oil pool before gas, continuous charging and independent preservation of each gas reservoir. Third, six favorable exploration zones of large-scale lithologic gas reservoirs have been sorted out through comprehensive evaluation, namely, mound and shoal complex controlled by horsts in the northern part of the rift in the second member of Dengying Formation, isolated karst mound and shoal complex of the fourth member of Dengying Formation in the south of the rift, the superimposed area of multi-stage platform margin mounds and shoals of the second and fourth members of Dengying Formation and Canglangpu Formation in the north slope area, the platform margin mounds and shoals of the second and fourth members of Dengying Formation in the west side of the rift, the platform margin mound and shoal bodies of the fourth member of Dengying Formation in the south slope area, etc. Fourth, Well Pengtan-1 drilled on the mound and shoal complex controlled by horsts of the second member of Dengying Formation in the rift and Well Jiaotan-1 drilled on the platform margin mound and shoal complex of the North Slope have obtained high-yield gas flows in multiple target layers, marking the discovery of a new gas province with reserves of (2—3)×1012 m3. This has proved the huge exploration potential of large lithologic gas reservoir group related to intracratonic rift.