Tight Gas Accumulation Research Articles

Genesis and Accumulation of Paleo-Oil Reservoir in Dabei Area, Kuqa Depression, Northwest China: Implications for Tight-Gas Accumulation

Genesis and Accumulation of Paleo-Oil Reservoir in Dabei Area, Kuqa Depression, Northwest China: Implications for Tight-Gas Accumulation

Tectonic movements of the Yanshan-Himalayan period in the northern Longmenshan and their impact on tight gas accumulation of the Shaximiao formation in the Qiulin structure, China

The Jurassic strata constitute a focal area for recent exploration and development of tight gas reservoirs in the western Sichuan Basin. This study investigates the Jurassic Shaximiao Formation in the northern Longmenshan in the Western Sichuan basin, focusing on tight gas reservoirs. The research integrates core and outcrop observations, seismic interpretations, and burial history analyses to understand hydrocarbon source rocks, sedimentation, reservoir characteristics, and structural characteristics. The impact of Yanshan-Himalayan tectonic movements on tight gas reservoir accumulation in the Shaximiao Formation is dissected, primarily around the Qiulin structure. The Western Sichuan Depression basin’s formation is influenced by gravitational gliding tectonics, which can be classified into the ‘Three Zones and One Belt,’ with Longmenshan in the frontal belt. Burial history analysis reveals distinct processes in the foreland belt and the depression basin. In the Qiulin area, gas reservoirs in the Shaximiao Formation are mainly charged by source rocks from the Xujiahe Formation. Tectonic movements play a significant role in creating favorable reservoirs and conditions for hydrocarbon migration and preservation. Natural gas accumulation is primarily controlled by fault connectivity to hydrocarbon sources and effective reservoir thickness. Gravitational sliding tectonics have shaped a fluvial-lacustrine environment for the Shaximiao Formation, with fluvial sand bodies acting as favorable reservoir zones. Small-scale normal faults formed by tectonic movements serve as conduits for natural gas migration. The research findings are of significant guidance for the exploration and development of tight oil and gas resources in western Sichuan basin.

Dynamic mechanisms of tight gas accumulation and numerical simulation methods: Narrowing the gap between theory and field application

Dynamic mechanisms of tight gas accumulation and numerical simulation methods: Narrowing the gap between theory and field application

Characteristics and Controlling Factors of Tight Marl Reservoirs with an Eyelid-Shaped Structure of the First Member of the Deep Maokou Formation in Eastern Sichuan

Tight marl is a special type of unconventional oil and gas resource, and the study on its reservoir characteristics and controlling factors is of immense scientific significance. In this paper, 113 core samples of marl from Gouxi Area, Eastern Sichuan were selected. Based on organic carbon, pyrolysis, X-ray diffraction of whole rock, and X-ray diffraction of clay analysis, the reservoir evaluation of eyelid-shaped limestone in the first member of Maokou Formation was carried out. The results show that there are obvious differences between eyelid-shaped limestone reservoirs and eyeball-shaped limestone reservoirs in the target stratum. Eyelid-shaped limestone is mainly distributed in the lower members a and c of the first member of Maokou Formation. It could be the main reservoir of low porosity and permeability tight marl, as its developed apertures, micro-fractures, and pore throat structure are obviously better than that of the eyeball-shaped limestone. As eyelid-shaped limestone features obvious self-generation and self-storage characteristics, the deep-water and low-energy sedimentary environment provides it with a large amount of highly brittle minerals and clay minerals as well as a favorable reservoir-forming background for diagenetic evolution and organic matter adsorption of clay minerals in the later period. The transformation of sepiolite into talc through diagenesis provides a large number of shrinkage joints for the reservoir, which are an effective space for tight gas accumulation.

Tight gas accumulation caused by overpressure: Insights from three-dimensional seismic data in the western Sichuan Basin, southwest China

Tight gas is an important unconventional gas resource, but numerous aspects of its accumulation and the distribution of high-quality reservoirs remain unclear. The Mesozoic–Cainozoic strata in the Sichuan Basin in southwest China are a focus for tight gas exploration, but have a complex pore pressure distribution that makes exploration challenging. In this study, the pore pressure in Upper Triassic and Jurassic strata in the West Sichuan Depression was predicted from three-dimensional seismic data using the Fillippone method. The results indicate that overpressure has developed in the Upper Triassic Xujiahe Formation in the Xinchang Structural Belt, with pressure coefficients of 1.2–2.4, which are highest in the third member, moderate in the fourth and fifth members, and lowest in the second member. Faults have a significant effect on the pore pressure. Overpressure along regional primary faults is typically weak, but it increases with distance from the faults. The overpressure resulted from disequilibrium compaction and hydrocarbon generation during the Mesozoic, and was intensified and modified by the Himalayan Orogeny. We infer that differential overpressure in tight sandstones is a key factor in gas migration and accumulation. Weakly overpressured zones along primary faults are dominant gas accumulation zones. Secondary faults and related fractures have a limited effect on overpressure, but improve the physical properties of reservoirs by increasing the permeability and promoting water–rock interactions. We suggest that the areas with relatively low pressure around faults and fractures are the most favourable targets for hydrocarbon exploration in tight sandstones.

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.

Gas expansion caused by formation uplifting and its effects on tight gas accumulation: A case study of Sulige gas field in Ordos Basin, NW China

Gas expansion caused by significant exhumation in the Sulige gas field in the Ordos Basin since Late Cretaceous and its effects on hydrocarbon accumulation have been investigated systematically based on comprehensive analysis of geochemical, fluid inclusion and production data. The results indicate that gas volume expansion since the Late Cretaceous was the driving force for adjustment and secondary charging of tight sandstone gas reservoirs in the Sulige gas field of the Ordos Basin. The gas retained in the source rocks expanded in volume, resulting in gas re-expulsion, migration and secondary charging into reservoirs, while the gas volume expansion in the tight reservoirs caused the increase of gas saturation, gas-bearing area and gas column height, which worked together to increase the gas content of the reservoir and bring about large-scale gas accumulation events. The Sulige gas field had experienced a two-stage accumulation process, burial before the end of Early Cretaceous and uplifting since the Late Cretaceous. In the burial stage, natural gas was driven by hydrocarbon generation overpressure to migrate and accumulate, while in the uplifting stage, the gas volume expansion drove internal adjustment inside gas reservoirs and secondary charging to form new reservoirs. On the whole, the gas reservoir adjustment and secondary charging during uplifting stage is more significant in the eastern gas field than that in the west, which is favorable for forming gas-rich area.

The Tight Sand Reservoir Characteristics and Gas Source in Coal Measures: A Case Study of Typical Areas in China

Interbedded sandstones, shales, and coal seams were formed in marine-continental transitional environments of coal measures, and the gas source of its tight sand gas has been uncertain, which hinders the progress of natural gas exploration. This article uses the Longtan tight sand gas in west Guizhou as an example to investigate the reservoir features, gas charging history, and main source rock of tight sand gas by examining thin sections, scanning electron microscopy images, X-ray diffraction results, and the fluid inclusions with burial and thermal histories and noble gas analysis. The Longtan sandstones in this study are classified as litharenites which are characterized by low compositional and textural maturities, and high clay contents, and are distinguished petrographically from conventional sandstones by the extensive existence of micropores and microfractures. The results of the homogenization temperatures of the fluid inclusions show that the Longtan tight sand gas is a single-stage accumulation which occurred during the Late Triassic. Furthermore, through the analysis of the helium and argon isotopes of noble gases, a calculation model was established for determining the shale and coal contributions to the tight sand gas. The research results show that the Longtan tight sand gas mainly belongs to the crust-derived gas, mostly from the Longtan shale-derived contribution and to a lesser extent from the Longtan coal-derived contribution. The measured 40Ar/36Ar values of the Longtan shales and coals are consistent with the forecasted 40Ar/36Ar values from the calculation model, demonstrating that the model is viable to calculate the source rock contribution to the tight sand gas. Therefore, the Longtan shales as main source rocks can generate hydrocarbons to charge neighboring tight sandstones to form tight gas accumulation in the Longtan Formation, which provides an opportunity for tight gas development in west Guizhou.

Characterization Method of Tight Sandstone Reservoir Heterogeneity and Tight Gas Accumulation Mechanism, Jurassic Formation, Sichuan Basin, China

Although significant progress has been made in tight gas exploration and development, there is still a limited understanding of the gas accumulation mechanism in tight formation. The description of heterogeneity in the tight reservoir is still an obstacle during tight gas exploration. In this work, we will develop a 3D gas accumulation facility that can reflect the high temperature and pressure under the geological condition to simulate the gas accumulation process in the tight formation of the Jurassic Formation, Sichuan Basin. Both the physical experiment simulation and numerical simulation methods will be combined to reveal the mechanism of gas accumulation. The results show that (1) the permeability ratio can characterize the heterogeneity of tight reservoirs. Based on this parameter, petroleum geologists can understand the interlayer heterogeneity during fluvial deposition and predict the sweet spots of tight gas; (2) the permeability ratio relationship between hydrocarbon accumulation of the tight sandstone reservoir mainly manifests as long as there is the existence of the differential permeability and there will be differences in natural gas migration dynamics, so that the natural gas accumulates in pores and depends on the extent of source rock; and (3) although the difference between capillary force curves is at the core of the influence of the permeability ratio on the gas-bearing capacity of the “sweet spot” sand body, the permeability ratio is a parameter of practical engineering significance. This work adds new methods to tight gas formation heterogeneity characterization and sheds light on the mechanisms of hydrocarbon accumulation in tight formation.

Controlling factors of tight sandstone gas accumulation and enrichment in the slope zone of foreland basins: The Upper Triassic Xujiahe Formation in Western Sichuan Foreland Basin, China

The accumulation and enrichment of hydrocarbon reflect different degrees of hydrocarbon charging, which is important for hydrocarbon exploration. In this study, we discuss the controlling factors of tight sandstone gas accumulation and enrichment of Xujiahe Formation in Jinhua-Zhongtaishan area, the slope zone of the Western Sichuan Foreland Basin, Southwest China, based on the analysis of the characteristics of the area's source rock, reservoir, and fault, combined with the tectonic background. This study shows that the accumulation and enrichment of tight sandstone gas in the slope zone of foreland basins are controlled by different factors. The natural gas derived from Xu1 Member is easily accumulated in Xu2 Member sandstone reservoir by vertical migration. The high quality source rock generated a large number of natural gas, which preferentially charge into the high quality sandstone reservoir and finally accumulate at the structural high position. The accumulation of tight gas is controlled by high quality source rock (source rock coefficient >10), high-quality reservoir (reserve coefficient >110), and favorable structure (high position of the local structure). When tight sandstone gas meets all prerequisites above for hydrocarbon accumulation, high content of total organic carbon (TOC) benefits enrichment of tight sandstone gas. In addition, the type I faults could be in favor of the natural gas from Xu1 Member to migrate to the upper part of Xu2 Member high quality sandstone reservoir, especially when the natural gas is generated by the middle and lower part of Xu1 Member high quality source rock, which could significantly improve the gas accumulation efficiency and promotes the gas enrichment and high production. In that case, the enrichment of tight gas is controlled by organic matter abundance of source rock (TOC >1.1%) and favorable source-reservoir communication conditions (the development of Type I faults). As a result, the areas with high-quality source rock and sandstone reservoir, favorable structure and migration pathway will be potential targets of tight sandstone gas in the slope zone of foreland basin.

The upper and lower limits and grading evaluation of the Shahezi tight gas reservoirs in the Xujiaweizi Rift, northern Songliao Basin: Implications from microscopic pore structures

The upper and lower limits and grading evaluation scheme of tight gas reservoirs (TGRs) at a microscopic pore structure level were explored by conducting high-pressure mercury intrusion porosimetry (HMIP), rate-controlled mercury intrusion porosimetry, nuclear magnetic resonance (NMR), and wettability experiments on tight rock samples from the Lower Cretaceous Shahezi (SHZ) Formation in the Xujiaweizi Rift, northern Songliao Basin. The results showed that the upper throat radius limit of the SHZ TGRs corresponds to 1.86 μm, derived from the microscopic equilibrium state of buoyance and capillary forces. The above value is closely related to several geological factors, including a pore-to-throat radius ratio, the density difference between formation water and gas, formation dip angle, gas–water interfacial tension, and wettability. The SHZ Formation enters a tight reservoir stage when the burial depth is deeper than 3460 m. A new method integrating HMIP and NMR experiments was proposed to estimate the thickness of the adsorbed water film with a value of ∼21.56 nm. The theoretical lower throat radius limit of the SHZ TGRs was determined as ∼22 nm, considering the individual methane dimension. Natural gas can be scarcely injected into tight reservoirs below the theoretical lower limit, serving as theoretically invalid tight reservoirs in the study area. From the configuration relationship between pores and throats, two TGR types were identified in the SHZ Formation (types I and II). Type-I TGRs are characterized by relatively excellent seepage capacity, with the maximum connected throat radius and permeability of 0.4 μm–1.86 μm and (0.015–0.27) × 10−3 μm2, respectively, and their storage space mainly comprises abundant dissolution and residual intergranular pores. Furthermore, an adequate storage space (3.6% to more than 12%) and an appropriate burial depth (<5000 m) promote type-I TGRs to be the most favorable targets for current SHZ tight gas accumulation development in the Xujiaweizi Rift.

Characteristics of heterogeneous diagenesis and modification to physical properties of Upper Paleozoic tight gas reservoir in eastern Ordos Basin

To correctly evaluate reservoir quality and determine promising tight gas zones, the characteristics of heterogeneous diagenesis and modifications to physical properties in the Upper Paleozoic tight gas reservoir in the eastern Ordos Basin (UPTGREOB) were assessed by comprehensively analyzing lithology, petrophysics, and organic geochemistry data. It was found that the types of sandstones in UPTGREOB mainly include (feldspathic) detritus sandstones and detritus feldspathic sandstone in low–ultralow porosity and permeability, with complex pore structure. Sandstone pores can be divided into two types: primary (primary intergranular and residual primary intergranular pores), secondary (intercrystalline, dissolved intragranular, dissolved intergranular, and dissolved cementing pores and microfractures). The main types of diagenesis are compaction, cementation, dissolution, and metasomatic alteration. Shiqianfeng Formation and Upper Shihezi Formation belong to period B of the syndiagenesis stage and period A1 and A2 of the mesodiagenesis stage; Lower Shihezi Formation and Shanxi Formation are entirely in the mesodiagenesis stage; Taiyuan Formation can be regarded to be in periods A2 and B of the mesodiagenesis stage and period A of the telodiagenesis stage. The original porosity of UPTGREOB was approximately 34%. Compaction was the primary destructive diagenesis rather than cementation, while dissolution was found to be the primary constructive diagenesis. The heterogeneous diagenesis played different roles in the UPTGREOB: in syndiagenesis B, the UPTGREOB began to densify under the compaction and early cementation; in mesodiagenesis A, dissolution and metasomatic alteration produced massive secondary dissolved pores and intercrystalline pores, improving the porosity and permeability; in mesodiagenesis B, dissolved pores were filled by new cements, resulting in decreased porosity and permeability; in telodiagenesis A, intensified compaction and cementation made the UPTGREOB retain extra low porosity and permeability. In general, the reservoirs of Shiqianfeng Formation and Upper/Lower Shihezi Formation in the mesodiagenesis stage A have preferable physical properties for tight gas accumulation.

Effects of micro-fracture and micro-coal line on tight gas accumulation, Triassic Xujiahe Formation, Sichuan Basin, China

The study of natural gas migration and accumulation of tight gas has become the focus of the energy industry in recent years. One of the priorities is the research of hydrocarbon migration carrier system of the formation. This study reveals two types of hydrocarbon carrier systems (micro-fractures and micro-coal lines) in the tight formation through a large amount of geological observations, data statistics, and simulations. This study also first put forward the view that the coal lines can be a type of hydrocarbon carrier system in tight sandstone formation. During the research process, an improved permeability testing method and apparatus are used to test the core permeability widely. Based on the real core, three models are established to describe the micro-fracture/micro-coal line characteristics. According to the three typical models, the Voronoi method is used to rebuild the network models. The migration and accumulation process in tight formation is simulated with the Multiple Relaxation Time lattice Boltzmann method in numerical simulation and with displacement apparatus in physical simulation. The results indicate that the micro-fracture/micro-coal line will significantly improve the percolation capacity of sandstone as the hydrocarbon migration carrier system in tight formation, the mechanism is revealed by numerical simulations. The micro-fractures/micro-coal lines are favorable for natural gas accumulation in tight formation. Unlike the conventional formation, in tight formation, micro-fractures/micro-coal lines tend to be the main migration carrier systems during the gas accumulation process.

Key structural periods and Permian tight gas accumulation response in Hangjinqi area, Ordos Basin

Critical tectonic period is a critical time point that characterizes the genetic connection and causal relation (accumulation response) between tectonic effect and oil/gas accumulation in large superposition basins, it is also an important window for analyzing accumulation evolution and accumulation regularity of oil/gas. Based on the systematic review of the tectonic evolution history of the Ordos Basin, the tectonic evolution and deformation sequence since the Mesozoic in Hangjinqi area in the northern part of Ordos Basin were studied through the constraints of apatite fission tracks and other thermal chronological indicators. Two key structural periods including J3-K1 and K2-E1 were proposed. It was believed by combining with the understanding of the Carboniferous-Permian hydrocarbon-generating and reservoir-forming histories that the J3-K1 was the period of design finalization in the Hangjinqi area which formed a currant NE-trending structural framework high in the northeast and low in the southwest during which, lithologic gas reservoirs including the Carboniferous Taiyuan and the Permian Shanxi formations, first member of the Permian Shihezi Formation to the north of the Sanyanjing-Wulan Jilin Temple-Bo'erjiang Haizi fault were formed and corresponding to the period of great amount of hydrocarbon generated and expulsed from source rocks as well as the densification of sandstones. On the other hand, the K2-E1 period was the major stage for fault reactivation and the formation of NE-trending tectonic trap and NW-trending fault that led to the adjustment of early lithologic gas reser-voirs in the south and the formation of structural or structural-lithologic gas reservoirs in the north. The difference of accumulation on each sides of the main fault is obvious. The southern part was formed earlier than the northern part, and was dominated by lithologic gas reservoirs yet the northern part was dominated by structural-lithological gas reservoirs. The southern gas-bearing strata are dominated by deep strata, while those in the north are both shallow and deep ones. In Paleogene, lifting in the north caused loss of gas. The key accumulation and transformation periods transformed with space and time, which transformed accumulation factors differentially and finally constrained the enrichment and depletion of natural gas.

Możliwości występowania gazu zamkniętego w piaskowcach środkowego kambru zachodniej części obniżenia bałtyckiego (wyniesienie Łeby) – wstępna analiza na podstawie danych petrofizycznych i geofizyki otworowej

Prospects of tight gas occurrence in the Middle Cambrian sandstones in the western part of the Baltic Depression (Łeba Elevation) – introductory analysis based on petrophysical and well logging data. A b s t r a c t. The main purpose of this article is an approximation of petrophysical parameters in selected borehole sections in the Łeba Elevation. The parameters are among the most important factors affecting the possibility of unconventional gas accumulation. The other factors explaining the possibility of tight gas accumulations in the Middle Cambrian sandstones of the Łeba Elevation are hydrocarbon shows in cores and drilling mud and the presence of conventional hydrocarbon fields. The potential hydrocarbon resources are related to the Debki and Bialogora Formations. They are composed of fine-grained sandstones. The thickness of the Debki Formation ranges up to 100 m. The tickness of the Bialogora Formation does not exceed 10 m. The analysis of petrophysical parameters of these formations indicates that their tight gas saturation has a layered character. The Debki Formation shows a better potential for tight gas accumulation.

Tectonic controls on Permian tight gas accumulation: Constrains from fluid inclusion and paleo-structure reconstruction in the Hangjinqi area, northern Ordos Basin, China

The development of tight gas reservoirs within the Ordos basin is closely related to the tectonic evolution. In this study, homogenization temperature of aqueous inclusions and the burial and thermal history of single well were combined to determine the tight gas charging time in the Permian Lower Shihezi sandstones in the Hangjinqi area, northern Ordos Basin. The paleo-structural characteristics and tectonic evolution, and their controls on source rock, gas migration and accumulation were discussed based on detailed 3D seismic interpretation. Results show that the natural gas was charged during the Middle Jurassic to the Early Cretaceous (170-140 Ma) in the southern part of the Porjianghaizi fault, while in the northern part, the gas charging time was the Early Oligocene to the Late Miocene (31-8 Ma). Paleo-topography in the Late Paleozoic controlled the coal beds thickness with generally decreasing trend to northward. Different burial depths led to the variation of thermal evolution, hydrocarbon generation time and intensity of source rocks between the northern and southern part. The results of this study indicate that the Hangjinqi area was evolved into a tectonic pattern with higher elevation in the south than the north in the Late Jurassic. The gas reservoirs in the southern part were mainly distributed in the paleo-slopes and paleo-highs, where were favorable areas for the gas accumulating in the Late Jurassic. Afterwards, the study area began to uplift since the late Early Cretaceous and made the Hangjinqi area a southwest inclined monocline. The rapid tectonic uplift event since the Early Oligocene in the northern Ordos Basin destroyed and reallocated the primary gas reservoirs in the southern part and prompted the gas migrating and accumulating into the structural traps in the northern part. The variation of natural gas compositions in both northern and southern parts verified the gas migration process.

Application of paleoporosity and bitumen saturation concepts to tight-gas accumulations containing solid bitumen

Solid bitumen significantly influences reservoir quality in many unconventional tight and shale hydrocarbon accumulations. In the siltstone-dominated Montney Formation of northeast British Columbia and northwest Alberta organic matter is mostly in the form of solid bitumen and represents an original pore-filling oil phase that was later thermally cracked. Here, we show that the influence of solid bitumen on reservoir quality can be further understood by applying the concepts of paleoporosity and bitumen saturation. Paleoporosity is defined as the sum of present-day porosity and total organic carbon (TOC) volume, and conceptualized as the porosity available at the time of oil charging. Bitumen saturation is defined as TOC volume divided by paleoporosity, and conceptualized as the fraction of paleoporosity filled with oil/bitumen. We introduce the paleoporosity-bitumen saturation cross-plot and use it, together with organic petrography and scanning electron microscopy observations, to investigate how different combinations of paleoporosity and bitumen saturation impact rock properties. Solid bitumen in the Montney Formation influences pore throat size, porosity, permeability and wettability. Understanding such key rock properties benefits from recognizing paleoporosity and bitumen saturation as inherent rock attributes with wide-ranging combinations. The concepts of paleoporosity and bitumen saturation elucidated here can likely be applied to other tight hydrocarbon accumulations that contain organic matter dominantly in the form of solid bitumen.

Cementation and porosity evolution of tight sandstone reservoirs in the Permian Sulige gas field, Ordos Basin (central China)

Abstract Tight sandstone gas reservoirs constitute an important type of unconventional gas resources and may be of crucial significance as environment-friendly source of energy in the world. However, the dynamics of densification and evolution of the low-porosity and low-permeability sandstone reservoirs are intensively debated in literature. Recently, the question of sequence of reservoir densification and hydrocarbon accumulation has arisen. A typical tight sandstone reservoir (the first member of the Shanxi Formation and the eighth member of Shihezi Formation) in the Permian Sulige gas field in Central China provides an excellent case study to probe these questions. By using a variety of different methodologies such as scanning electron microscopy (SEM), X-ray diffraction (XRD), cathodoluminescence, fluid inclusion analysis and confocal Raman spectrometer analysis, we identified different authigenic minerals such as illite, kaolinite, dickite, chlorite and smectite illitization coexisting with siliceous and calcitic cements. These authigenic minerals precipitated at different diagenetic stages, related to the changing conditions during compaction and lithification, and therefore, changed the porosities of the host rocks during each of these stages. The types of pores in the Sulige gas field are dominated by illite and kaolinite intercrystalline pores, matrix solution pores, and primary intergranular pores. The results of this study suggest that compaction and cementation are the reasons for the most distinct loss in porosity. On the other hand, kaolinite and illite preserve their intercrystalline pores, which could be identified as the main reserve space of the tight gas reservoirs. Therefore, the secondary porosity of the sandstone reservoirs forms the most important contributor to the gas reservoir potential in the Sulige gas field. In addition, it could be inferred that the tight gas accumulation took place during the densification of the reservoirs. The implications of the presented results may also help to understand the formation of other tight reservoirs world-wide.

Hydrocarbon prospectivity of the Cooper Basin, Australia

The Pennsylvanian-Middle Triassic Cooper Basin is Australia's premier conventional onshore hydrocarbon-producing province. The basin also hosts a range of unconventional gas play types, including basin-centered gas and tight gas accumulations, deep dry coal gas associated with the Patchawarra and Toolachee Formations, and the Murteree and Roseneath shale gas plays. This study used petroleum systems analysis to investigate the maturity and generation potential of 10 Permian source rocks in the Cooper Basin. A deterministic petroleum systems model was used to quantify the volume of expelled and retained hydrocarbons, estimated at 1272 billion BOE (512 billion bbl and 760 billion BOE) and 977 billion BOE (362 billion bbl and 615 billion BOE), respectively. Monte Carlo simulations were used to quantify the uncertainty in volumes generated and to demonstrate the sensitivity of these results to variations in source-rock characteristics. The large total generation potential of the Cooper Basin and the broad distribution of the Permian source kitchen highlight the basin's significance as a world-class hydrocarbon province. The large disparity between the calculated volume of hydrocarbons generated and the volume so far found in reservoirs indicates the potential for large volumes to remain within the basin, despite significant losses from leakage and water washing. The hydrocarbons expelled have provided abundant charge to both conventional accumulations and to the tight and basin-centered gas plays, and the broad spatial distribution of hydrocarbons remaining within the source rocks, especially those within the Toolachee and Patchawarra Formations, suggests the potential for widespread shale and deep dry coal plays.

Geochemical evidence for in situ accumulation of tight gas in the Xujiahe Formation coal measures in the central Sichuan Basin, China

The study of accumulation mechanisms of tight gas has attracted much attention in recent years. One of the focuses is whether natural gas can migrate on a large scale in tight reservoirs. In this work, geochemical parameters (such as C1/C1+, C1/(C2+ C3), C1+, δ13C1, δ13C2, iC4/nC4, iC5/nC5) of the tight gas reservoirs in the central Sichuan Basin, China have been studied to characterize the accumulation mechanisms in these fields. Results show that the tight gas accumulation in the Xujiahe Formation in the central Sichuan is in situ, and natural gas has not experienced large-scale migration. In gases from the central Sichuan Basin, δ13C1 ranges from −44.1‰ to −37.1‰ with an average of −40.1‰, and C1/C1+ ranges from 0.80 to 0.97 with an average of 0.91. While in the gases from the western Sichuan Basin, δ13C1 is between −35.5‰ and − 30‰ with an average of −32.2‰, and C1/C1+ ranges from 0.95to 0.99with an average of 0.98. Based on geochemical indicators of natural gas, the gases of Xujiahe Formation in the Central Sichuan Basin originated from the local coal measures of the Xujiahe Formation in horizontal direction with little contribution from the western Sichuan. In central Sichuan Basin, there is also no horizontal migration of natural gas in the same formation between adjacent gas fields. Vertically, the Xujiahe Formation is an independent gas generating system and has no relationship with the underlying Mid-Lower Triassic formations and the Jurassic natural gas formation above it. The δ13C2of Xujiahe Formation in central Sichuan ranges from −28.3‰ to −25.9‰, with an average of −27.5‰. However, the δ13C2 of Lower Jurassic above Xujiahe Formation ranges from −36.8‰ to −30.5‰, with an average of −33.0‰. Under the Xujiahe Formation, the δ13C2 in Leikoupo Formation ranges from −35.5‰ to −32.1‰, with an average of −33.1‰, and in Jialingjiang Formation ranges from −34.6‰ to −33.2‰, with an average of −33.8‰. There is also a clear distinction in the geochemical characteristics of natural gas between the upper and lower gas reservoirs in the Xujiahe Formation, indicating that there is no obvious vertical migration of natural gas. Geochemical evidence shows that there is no large-scale gas migration in the Xujiahe Formation. The tight gas is generated in situ and accumulated in the formation in the central Sichuan Basin.