Impact of sedimentology,diagenesis, and solid bitumen on the development of a tight gas grainstone reservoir in the Feixianguan Formation,Jiannan area,China: Implications for gas exploration in tight carbonate reservoirs

Tight gas grainstone reservoirs in the third member of the Feixianguan Formation, Jiannan area, evolved from a paleo-oil accumulation as evidenced from abundant solid reservoir bitumen. Porosity evolution of the grainstones was studied by evaluating relative influences of sedimentology, diagenesis, and solid bitumen formed during cracking of accumulated oils. Grainstones exhibited regional-distinct effectiveness for paleo-oil and present-gas accumulations during oil window and subsequent gas window diagenesis. In the southern zone where grainstones were not subjected to subaerial exposure and meteoric diagenesis in the early diagenetic stage, paleoporosity at the time of oil charge was mainly controlled by sedimentologic factors (e.g., grain size, sorting, and grain type), and paleo-oil reservoirs only occurred in the ooid-dominated grainstones with good sorting and coarse grain size. In contrast, in the northern zone meteoric diagenesis was responsible for paleoporosity preservation due to the early mineral stabilization of grains and meteoric calcite cementation, which caused grainstones greater resistance to compaction. Hence, most of the grainstones in the northern zone, regardless of textural variables, formed effective reservoirs for paleo-oil accumulation. As the oil cracked to gas with increasing depth and temperature during the late oil window and initial gas window, solid bitumen occluded reservoir pores to varying degrees and caused paleo-oil reservoirs to be significantly heterogeneous or completely ineffective for gas accumulation. In contrast, most grainstones that were once ineffective oil reservoirs transformed into effective gas reservoirs due to no or minor influence of solid bitumen precipitation. The model of reservoir transformation development of tight grainstones provides a plausible explanation for key observations concerning the diagenetic and distribution differences between paleo-oil and present-gas reservoirs. It is useful in predicting the distribution of potential reservoirs in carbonate strata in future exploration.     

Quantitative impact of diagenesis on reservoir quality of the Triassic Chang 6 tight oil sandstones,Zhenjing area,Ordos Basin,China

The Upper Triassic Chang 6 sandstone, an important exploration target in the Ordos Basin, is a typical tight oil reservoir. Reservoir quality is a critical factor for tight oil exploration. Based on thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), stable isotopes, and fluid inclusions, the diagenetic processes and their impact on the reservoir quality of the Chang 6 sandstones in the Zhenjing area were quantitatively analysed. The initial porosity of the Chang 6 sandstones is 39.2%, as calculated from point counting and grain size analysis. Mechanical and chemical compaction are the dominant processes for the destruction of pore spaces, leading to a porosity reduction of 14.2%–20.2% during progressive burial. The porosity continually decreased from 4.3% to 12.4% due to carbonate cementation, quartz overgrowth and clay mineral precipitation. Diagenetic processes were influenced by grain size, sorting and mineral compositions. Evaluation of petrographic observations indicates that different extents of compaction and calcite cementation are responsible for the formation of high-porosity and low-porosity reservoirs. Secondary porosity formed due to the burial dissolution of feldspar, rock fragments and laumontite in the Chang 6 sandstones. However, in a relatively closed geochemical system, products of dissolution cannot be transported away over a long distance. As a result, they precipitated in nearby pores and pore throats. In addition, quantitative calculations showed that the dissolution and associated precipitation of products of dissolution were nearly balanced. Consequently, the total porosity of the Chang 6 sandstones increased slightly due to burial dissolution, but the permeability decreased significantly because of the occlusion of pore throats by the dissolution-associated precipitation of authigenic minerals. Therefore, the limited increase in net-porosity from dissolution, combined with intense compaction and cementation, account for the low permeability and strong heterogeneity in the Chang 6 sandstones in the Zhenjing area.     

Influence of natural fractures on gas accumulation in the Upper Triassic tight gas sandstones in the northwestern Sichuan Basin,China

The Upper Triassic Xujiahe Formation in the northwestern Sichuan Basin, China, is a typical tight gas sandstone reservoir that contains natural fractures and has an average porosity of 1.10% and air permeability less than 0.1 md because of compaction and cementation. According to outcrops, cores and image logs, three types of natural fractures, namely, tectonic, diagenetic and overpressure-related fractures, have developed in the tight gas sandstones. The tectonic fractures include small faults, intraformational shear fractures and horizontal shear fractures, whereas the diagenetic fractures mainly include bed-parallel fractures. According to thin sections, the microfractures also include tectonic, diagenetic and overpressure-related microfractures. The diagenetic microfractures consist of transgranular, intragranular and grain-boundary fractures. Among these fractures, intraformational shear fractures, horizontal shear fractures and small faults are predominant and significant for fluid movement. Based on the Monte Carlo method, these intraformational shear fractures and horizontal shear fractures improve the reservoir porosity and permeability, thus serving as an important storage space and primary fluid-flow channels in the tight sandstones. The small faults may provide seepage channels in adjacent layers by cutting through layers. In addition, these intragranular and grain-boundary fractures increase the connectivity of the tight gas sandstones by linking tiny pores. The tectonic microfractures improve the seepage capability of the tight gas sandstones to some extent. Low-dip angle fractures are more abundant in the T₃X³ member than in the T₃X² and T₃X⁴ members. The fracture intensities of the sandstones in the T₃X³ member are greater than those in the T₃X² and T₃X⁴ members. The fracture intensities do not always decrease with increasing bed thickness for the tight sandstones. When the bed thickness of the tight sandstones is less than 1.0 m, the fracture intensities increase with increasing bed thickness in the T₃X³ member. Fluid inclusion evidence and burial history analysis indicate that the tectonic fractures developed over three periods. The first period was at the end of the Triassic to the Early Jurassic. The tectonic fractures developed during oil generation but before the matrix's porosity and permeability reduced, which suggests that these tectonic fractures could provide seepage channels for oil migration and accumulation. The second period was at the end of the Cretaceous after the matrix's porosity and permeability reduced but during peak gas generation, which indicates that gas mainly migrated and accumulated in the tectonic fractures. The third period was at the end of the Eogene to the Early Neogene. The tectonic fractures could provide seepage channels for secondary gas migration and accumulation from the Upper Triassic Xujiahe Formation into the overlying Jurassic Formation.     

Oolitic shoal complexes characterization of the Lower Triassic Feixianguan Formation in the Yuanba Gas Field,Northeast Sichuan Basin,China

The Yuanba Gas Field is the second largest natural gas reservoir in the Sichuan Basin, southwest China. The vast majority of the natural gas reserve is from the Permian Changhsingian reef complexes and Lower Triassic Feixianguan oolitic shoal complexes. To better understand this reservoir system, this study characterizes geological and geophysical properties, spatial and temporal distribution of the oolitic shoal complexes and factors that control the oolitic shoals character for the Lower Triassic Feixianguan Formation in the Yuanba Gas Field. Facies analysis, well-seismic tie, well logs, seismic character, impedance inversion, and root mean square (RMS) seismic attributes distinguish two oolitic shoal complex facies – FA-A and FA-B that occur in the study area. FA-A, located in the middle of oolitic shoal complex, is composed of well-sorted ooids with rounded shape. This facies is interpreted to have been deposited in shallow water with relatively high energy. In contrast, FA-B is located in flanks of the oolitic shoal complex, and consists of poorly sorted grains with various shape (rounded, subrounded and subangular). The oolitic shoal complexes were mainly deposited along the platform margin. From the early Fei 2 Member period to the late Fei 2 Member period, the oolitic shoals complexes on the platform margin gradually migrated from the southwest to the northeast with an extent ranging from less than 100 km²–150 km² in the Yuanba Gas Field. The migration of oolitic shoals coincided with the development of a series of progradational clinoforms, suggesting that progradational clinoforms caused by sea-level fall maybe are the main reason that lead to the migration of oolitic shoals. Finally, this study provide an integrated method for the researchers to characterize oolitic shoal complexes by using well cores, logs, seismic reflections, impedance inversion, and seismic attribute in other basins of the world.     

Diagenetic history of tight sandstones and gas entrapment in the Yulin Gas Field in the central area of the Ordos Basin,China

The Ordos Basin is a large cratonic basin with an area of 250,000 km² in central China. Upper Paleozoic coals and shales serve as gas source rocks with peak generation and migration at the end of the early Cretaceous. Recent exploration has verified the huge gas potential in the “basin-centered gas accumulation system” (BCGAS). However, the mechanism for the gas accumulation is controversial. With an integrated approach of thin-section petrography, ultra-violet fluorescence microscopy, fluid inclusion microthermometry, Raman microspectrometry, scanning electron microscopy, and X-ray diffractometry, we identified diagenetic trapping and evaluated the diagenetic history of sandstone reservoirs in the Yulin Gas Field in the central area, where structural, stratigraphic and/or sedimentary lithologic traps have not been found. It was revealed that three phases of diagenesis and hydrocarbon charging occurred, respectively, in the late Triassic, late Jurassic and at the end of the early Cretaceous. In the first two phases, acidic water entered the reservoir and caused dissolution and cementation, resulting in porosity increase. However, further subsidence and diagenesis, including compaction and cementation, markedly reduced the pore space. At the end of the early Cretaceous, the bulk of the gas migrated into the tight reservoirs, and the BCGAS trap was formed. In the updip portion of this system, cementation continued to occur due to low gas saturation and has provided effective seals to retain gas for a longer period of time than water block in the BCGAS. The mechanism for the gas entrapment was changed from water block by capillary pressure in the BCGAS to diagenetic sealing. The diagenetic seals in the updip portion of the sand body were formed after gas charging, which indicates that there is a large hydrocarbon exploration potential at the basin-centered area.     

Impact of diagenesis on reservoir quality and heterogeneity of the Upper Triassic Chang 8 tight oil sandstones in the Zhenjing area,Ordos Basin,China

Reservoir quality and heterogeneity are critical risk factors in tight oil exploration. The integrated, analysis of the petrographic characteristics and the types and distribution of diagenetic alterations in the Chang 8 sandstones from the Zhenjing area using core, log, thin-section, SEM, petrophysical and stable isotopic data provides insight into the factors responsible for variations in porosity and permeability in tight sandstones. The results indicate that the Chang 8 sandstones mainly from subaqueous distributary channel facies are mostly moderately well to well sorted fine-grained feldspathic litharenites and lithic arkose. The sandstones have ultra-low permeabilities that are commonly less than 1 mD, a wide range of porosities from 0.3 to 18.1%, and two distinct porosity-permeability trends with a boundary of approximately 10% porosity. These petrophysical features are closely related to the types and distribution of the diagenetic alterations. Compaction is a regional porosity-reducing process that was responsible for a loss of more than half of the original porosity in nearly all of the samples. The wide range of porosity is attributed to variations in calcite cementation and chlorite coatings. The relatively high-porosity reservoirs formed due to preservation of the primary intergranular pores by chlorite coatings rather than burial dissolution; however, the chlorites also obstruct pore throats, which lead to the development of reservoirs with high porosity but low permeability. In contrast, calcite cementation is the dominant factor in the formation of low-porosity, ultra-low-permeability reservoirs by filling both the primary pores and the pore throats in the sandstones. The eogenetic calcites are commonly concentrated in tightly cemented concretions or layers adjacent to sandstone-mudstone contacts, while the mesogenetic calcites were deposited in all of the intervals and led to further heterogeneity. This study can be used as an analogue to understand the variations in the pathways of diagenetic evolution and their impacts on the reservoir quality and heterogeneity of sandstones and is useful for predicting the distribution of potential high-quality reservoirs in similar geological settings.     

Combining rate-controlled porosimetry and NMR to probe full-range pore throat structures and their evolution features in tight sands: A case study in the Songliao Basin,China

To better understand reservoir quality and to produce accurate petrophysical interpretations, it is necessary to understand complex and heterogeneous pore throat structures in tight sands and to develop a technique to reveal the full range of pore and throat distributions. In this study, in order to characterize the features and evolutions of pore throat structures, nine samples from the Lower Cretaceous tight gas sandstone in the Songliao Basin of China are measured by nuclear magnetic resonance (NMR), rate-controlled porosimetry (RCP) and scanning electron microscopy (SEM). Throats with bifractal structures are found in these tight sands and can be divided into a backbone formation (BF) region and a percolation region using RCP data. Because (i) throats in the percolation region record treelike pore structures and are predominant in small pore spaces and (ii) a good correlation exists between NMR-derived T₂ relaxation times and the RCP-derived radius of throats, the throat distribution obtained via RCP can be used to calibrate the NMR PSD and then to partition the PSD into distributions of pore bodies and throats. These data indicate that (i) throats are more common than pore bodies in pore spaces of tight sands with lower permeability, (ii) pore bodies are connected to throats from both the BF and percolation regions, in which the fluid mobility in pore bodies is mainly controlled by the pore to throat ratio (PTR), which is related to the intersection throat of these two regions, and (iii) compaction, dissolution, clay cementation and sediment properties (e.g., rock compositions) have different impacts on the evolutions of pore bodies and throats, in which larger PTR values in tight sands are mainly produced by compaction and pore-bridging clay cementation, and lower contents of pore bodies are commonly related to abundant plastic compositions and pore-bridging clay cementation.     

Impact of sedimentology and diagenesis on the petrophysical properties of a tight oolitic carbonate reservoir. The case of the Oolithe Blanche Formation (Bathonian,Paris Basin,France)

The Oolithe Blanche Formation was studied in three quarries, located at the south-eastern edge of the Paris Basin (France). Heterogeneities in reservoir properties were assessed through a sedimentological, diagenetic and petrophysical study. The relationships between depositional settings, diagenesis and petrophysical properties were analysed using detailed petrographic studies, image analysis, Nano CT-scans and petrophysical measurements.The carbonate reservoir pore network is mainly controlled by intraparticle microporosity which ensures the connectivity with interparticle meso- and macroporosity.Early cementation vs. early compaction processes (mainly grain interpenetration) may have considerable influence on fluid-flow properties and parameters such as permeability, acoustic velocities and tortuosity. Better reservoir properties are found when compaction processes begin before cementation.From statistical analyses, e.g. Principal Component Analysis and Linear Discriminant Analysis, a sedimentological/diagenetic and petrophysical model is proposed that is in a good agreement with the geological model developed from field work.     

Influence of detrital composition on the diagenetic history of tight sandstones with implications for reservoir quality: Examples from the Permian Xiashihezi Formation and Carboniferous Taiyuan Formation,Daniudi gas field,Ordos Basin,China

Tight-gas reservoirs, characterized by low porosity and low permeability, are widely considered to be the product of post-depositional, diagenetic processes associated with progressive burial. This study utilizes a combination of thin section petrography, scanning electron microscopy, microprobe and back scatter electron analysis, stable isotope geochemistry and fluid inclusion analysis to compare the diagenetic history, including porosity formation, within sandstones of the second member of Carboniferous Taiyuan Formation (C₃t₂) and the first member of Permian Xiashihezi Formation (P₁x₁) in the Ordos Basin in central China.In the P₁x₁ member, relatively high abundances of metamorphic rock fragments coupled with a braided river and lacustrine delta environment of deposition, produced more smectite for transformation to illite (50–120 °C). This reaction was driven by dissolution of unstable minerals (K-feldspar and rock fragments) during the early to middle stages of mesodiagenesis and consumed all K-feldspar. Abundant intragranular porosity (average values of 2.8%) and microporosity in kaolinite (average values of 1.5%) formed at these burial depths with chlorite and calcite developed as by-products.In the C₃t₂ member, relatively low abundances of metamorphic rock fragments coupled with an incised valley-coastal plain environment of deposition resulted in less smectite for transformation to illite. High K⁺/H⁺ ratios in the early pore waters related to a marine sedimentary environment of deposition promoted this reaction. Under these conditions, K-feldspar was partially preserved. During the middle to late stages of mesodiagenesis, K-feldspar breakdown produced secondary intragranular (average values of 1.4%) and intergranular pores (average values of 1.2%). Release of K⁺ ions promoted illitization of kaolinite with quartz overgrowths and ferrous carbonates developed as by-products.This study has demonstrated that whereas both members are typical tight-gas sandstones, they are characterized by quite different diagenetic histories controlled by the primary detrital composition, especially during mesodiagenesis. Types of secondary porosity vary between the two members and developed at different stages of progressive burial. The content of unstable detrital components, notably feldspar, was the key factor that determined the abundance of secondary porosity.     

Geochemical characteristics of tight gas and gas-source correlation in the Daniudi gas field,the Ordos Basin,China

The molecular composition, stable carbon and hydrogen isotopes and light hydrocarbons of the Upper Paleozoic tight gas in the Daniudi gas field in the Ordos Basin were investigated to study the geochemical characteristics. Tight gas in the Daniudi gas field displays a dryness coefficient (C₁/C_1–5) of 0.845–0.977 with generally positive carbon and hydrogen isotopic series, and the C₇ and C_5–7 light hydrocarbons of tight gas are dominated by methylcyclohexane and iso-alkanes, respectively. The identification of gas origin and gas-source correlation indicate that tight gas is coal-type gas, and the gases reservoired in the Lower Permian Shanxi Fm. (P₁s) and Lower Shihezi Fm. (P₁x) had a good affinity and were derived from the P₁s coal-measure source rocks, whereas the gas reservoired in the Upper Carboniferous Taiyuan Fm. (C₃t) was derived from the C₃t coal-measure source rocks. The molecular and methane carbon isotopic fractionations of natural gas support that the P₁x gas was derived from the P₁s source rocks. The differences of geochemical characteristics of the C₃t gas from different areas in the field suggest the effect of maturity difference of the source rocks rather than the diffusive migration, and the large-scale lateral migration of the C₃t gas seems unlikely. Comparative study indicates that the differences of the geochemical characteristics of the P₁s gases from the Yulin and Daniudi gas fields originated likely from the maturity difference of the in-situ source rocks, rather than the effect of large-scale lateral migration of the P₁s gases.     

Controls on reservoir quality of Lower Cretaceous tight sandstones in the Laiyang Sag,Jiaolai Basin,Eastern China: Integrated sedimentologic,diagenetic and microfracturing data

The Jiaolai Basin (Fig. 1) is an under-explored rift basin that has produced minor oil from Lower Cretaceous lacustrine deltaic sandstones. The reservoir quality is highly heterogeneous and is an important exploratory unknown in the basin. This study investigates how reservoir porosity and permeability vary with diagenetic minerals and burial history, particularly the effects of fracturing on the diagenesis and reservoir deliverability. The Laiyang sandstones are tight reservoirs with low porosity and permeability (Φ < 10% and K < 1 mD). Spatial variations in detrital supply and burial history significantly affected the diagenetic alterations during burial. In the western Laiyang Sag, the rocks are primarily feldspathic litharenites that underwent progressive burial, and thus, the primary porosity was partially to completely eliminated as a result of significant mechanical compaction of ductile grains. In contrast, in the eastern Laiyang Sag, the rocks are lithic arkoses that were uplifted to the surface and extensively eroded, which resulted in less porosity reduction by compaction. The tectonic uplift could promote leaching by meteoric water and the dissolution of remaining feldspars and calcite cement. Relatively high-quality reservoirs are preferentially developed in distributary channel and mouth-bar sandstones with chlorite rims on detrital quartz grains, which are also the locations of aqueous fluid flow that produced secondary porosity. The fold-related fractures are primarily developed in the silt–sandstones of Longwangzhuang and Shuinan members in the eastern Laiyang Sag. Quartz is the most prevalent fracture filling mineral in the Laiyang sandstones, and most of the small-aperture fractures are completely sealed, whereas the large-aperture fractures in a given set may be only partially sealed. The greatest fracture density is in the silt–sandstones containing more brittle minerals such as calcite and quartz cement. The wide apertures are crucial to preservation of the fracture porosity, and the great variation in the distribution of fracture-filling cements presents an opportunity for targeting fractures that contribute to fluid flow.     

In situ stress field evaluation of deep marine tight sandstone oil reservoir: A case study of Silurian strata in northern Tazhong area,Tarim Basin,NW China

Deep marine tight sandstone oil reservoirs are the subject of considerable research around the world. This type of reservoir is difficult to develop due to its low porosity, low permeability, strong heterogeneity and anisotropy. A marine tight sandstone oil reservoir is present in the Silurian strata in the northern Tazhong area of the Tarim Basin, NW China, at a depth of more than 5000 m. The porosity is between 6% and 8%, and the gas permeability is between 0.1 and 1 × 10⁻³ μm². The features of this type of reservoir include the poor effects of conventional fracturing modifications and horizontal wells, which can lead to stable and low levels of production after staged fracturing. Here, we conduct a comprehensive evaluation of the mechanical properties of the rock and the in situ stress of the target tight sandstones by using numerous mechanical and acoustic property tests, conducing crustal stress analysis and using data from thin section observations. The dispersion correction technique is used to transform velocity at the experimental high frequency (1 MHz) to velocity at the logging frequency (20 kHz). The logging interpretation models of the transverse wave offset time, mechanical parameters and in situ stress are calculated, and each model represents a high precision prediction. Simulating the in situ stress field of the Silurian strata using a three-dimensional finite element method demonstrates that the average error between the simulation result and the measured value is less than 6%. The planar distribution of each principal stress is mainly controlled by the burial depth and fault distribution. By conducting in situ stress orientation analysis for the target layer via the analysis of paleomagnetism, borehole enlargement, fast shear wave orientation and stress field simulation, we show that the direction of the maximum horizontal stress is N45E. In this paper, a typical and successful comprehensive evaluation of the stress field of the deep tight sandstone oil reservoir is provided.     

Numerical simulation of hydrocarbon migration in tight reservoir based on Artificial Immune Ant Colony Algorithm: A case of the Chang 81 reservoir of the Triassic Yanchang Formation in the Huaqing area,Ordos Basin,China

The hydrocarbon migration in tight reservoirs is a complex process, the fluid flow patterns of which are notably different from those of conventional reservoirs. Therefore, specific mathematical models are needed to simulate the secondary hydrocarbon migrations. This study presents a numerical simulation method based on Artificial Immune Ant Colony Algorithm (AIACA) to simulate the secondary hydrocarbon migrations in tight reservoirs. It consists of three core parts: (1) the release modes of artificial ants based on the intensity of hydrocarbon generation; (2) the wandering patterns of artificial ants under the control of the dynamic field and the distribution of pheromones; (3) the updating modes of pheromones based on the changes in reservoir wettability. The simulation of secondary migration can be realized by the observing the dynamic movements and accumulations of the artificial ants. The method has been tested in the Chang 8₁ tight sandstone reservoir, which is part of the Triassic Yanchang Formation in the Huaqing Area, Ordos Basin in China, and proved to be successful in matching the current data in exploration and development.     

Diagenetic and sedimentary controls on porosity in Lower Carboniferous fine-grained lithologies,Krechba field,Algeria: A petrological study of a caprock to a carbon capture site

Fine-grained siliciclastic lithologies commonly act as sealing caprocks to both petroleum fields and host reservoirs for carbon capture (CO₂ sequestration) projects. Fine-grained lithologies are thus of great importance in controlling fluid flow and storage in the subsurface. However, fine-grained rocks are rarely characterised in terms of primary sedimentary characteristics, diagenesis and how these relate to their flow properties (i.e. sealing or caprock quality). Seventeen samples from Lower Carboniferous estuarine caprock to a gas field (also to be used as a carbon capture site), have been analysed using a range of petrological and petrophysical techniques. The rock unit that represents the caprock to this gas field was found to be predominantly silt grade with porosity values as low as 1.8%. In these rocks, caprock quality (porosity) is controlled by intrinsic and extrinsic factors linked to primary mineralogy and diagenetic processes. Depositional mineralogy was dominated by quartz, detrital mica, detrital clay (likely Fe-rich 7Å clay and illite–smectite) with minor feldspar and oxide phases. Diagenetic processes included compaction, minor feldspar dissolution and kaolinite growth and the more important processes of chlorite, siderite and quartz cementation, as well as the likely transformation of smectite into illite. Caprock quality is controlled by the primary quantity of illite-muscovite in the sediment and also by the localised extent of chlorite and quartz cementation. Deposition in an estuarine environment led to highly heterogeneous distribution of primary and diagenetic minerals, and thus caprock quality, between and within the samples.     

Geochemical characteristics of gases from the largest tight sand gas field (Sulige) and shale gas field (Fuling) in China

This study performed a detailed geochemical analyses of the components, stable carbon isotopes of alkane gas and CO₂, stable hydrogen isotopes of alkane gas and helium isotopes of reproducing gas from the largest tight gas field (Sulige) and shale gas (Fuling) field in China. The comparative study shows that tight gas from the Sulige gas field in the Ordos Basin is of coal-derived origin, which is characterized by a positive carbon and hydrogen isotopic distribution pattern (δ¹³C₁ > δ¹³C₂ > δ¹³C₃ > δ¹³C₄; δ²H₁ > δ²H₂ > δ²H₃), i.e., the carbon and hydrogen isotopes increase with increasing carbon numbers. Carbon dioxide from this field are of biogenic origin and the helium is crust-derived. Shale gas from the Fuling shale gas field belongs to oil-derived gas which has complete carbon and hydrogen isotopic reversal of secondary alteration origin (δ¹³C₁ < δ¹³C₂ < δ¹³C₃; δ²H₁ < δ²H₂ < δ²H₃), i.e., the carbon and hydrogen isotopes decrease with increasing carbon numbers. Such complete isotopic reversal distribution pattern is due to the secondary alteration like oil or gas cracking, diffusion and so on under high temperature. In that case, positive carbon or hydrogen isotopic distribution pattern will change into complete isotopic reversal as the temperature increases. Carbon dioxide is of abiogenic origin resulting from the thermal metamorphism of carbonates and helium is crust-derived.     

Fractures in the low porosity and ultra-low permeability glutenite reservoirs: A case study of the late Eocene Hetaoyuan formation in the Anpeng Oilfield,Nanxiang Basin,China

The Naxiang Basin, located within the Qin-and-Dabie Mountains orogenic belt in central China, is a small intermountain faulted basin, in which the late Eocene Hetaoyuan Formation in the Anpeng Oilfield is the low porosity and ultra-low permeability glutenite reservoirs. The large-scale fractures are mainly developed in the thick-bedded conglomerates and gravel-bearing gritstones, the small-scale jointed-fractures bounded by layer are mainly developed in the medium-granular and fine sandstones between the conglomerates or gravel-bearing gritstones. There also developed three kinds of micro-fractures, namely intergranular fractures, intragranular fractures and transgranular fractures, in the tight glutenites. The fractures in the glutenite reservoirs are of chiefly high dip-angles. They assume chiefly the E-W strikes, next are the NE-SW and NW-SE strikes. On the log curve, fractures usually show such responses as a decrease of the deep and shallow lateral resistivities, an increase of the acoustic time difference, a reduction of the density, an increase of the compensation neutrons, an occurrence of middle and high gamma ray and an expansion of the calipers. Fractures make contributions to the low porosity and ultra-low permeability glutenite reservoirs by improving the permeability and then porosity. Micro-fractures are the important channels connecting intergranular and intragranular solution pores, thereby making better the connectivity within the tight glutenite reservoirs. The small- and medium-scale fractures serve as the flow channels within the layers of fine and medium-granular sandstones, while the large-scale fractures serve as the main flow channels for the whole reservoir. Under the impact of the present-day stress, the NE-SW fractures perpendicular to the minimum principal stress assume a tensile state and have good connectivity, large apertures and high permeability, and are the major direction for fluid flow, thereby providing a major basis for a further development.     

Pore structure of Cambrian shales from the Sichuan Basin in China and implications to gas storage

The microstructure of black siliceous shale from the lower Cambrian Niutitang Formation, Sichuan Basin in China was investigated by the combination of field emission scanning electron microscope (FE-SEM) and argon ion beam milling. The nanometer-to micrometer-scale pore systems of shales are an important control on gas storage and fluid migration. In this paper, the organic porosity in shale samples within oil and gas window has been investigated, and the formation mechanism and diagenetic evolution of nanopores have been researched.FE-SEM reveals five pore types that are classified as follows: organic nanopores, pores in clay minerals, nanopores of framework minerals, intragranular pores in microfossils, and microfractures. Numerous organic nanopores are observed in shales in the gas window, whereas microfractures can be seen within the organic matter of shales in the oil window. Microfractures in oil window shales could be attributed to pressure buildup in the organic matter when incompressible liquid hydrocarbon are generated, and the orientation of microfractures is probably parallel to the bedding and strength anisotropy of the formation. Pores in clay minerals are always associated with the framework of clay flakes, and develop around rigid mineral grains because the pressure shadows of mineral grains protect pores from collapse, and the increasing of silt content would lead to an increase in pressure shadows and improve porosity. Nanopores of rock framework are probably related to dissolution by acidic fluids from hydrocarbon generation, and the dissolution-related pores promote permeability of shales. Porosity in the low-TOC, low-thermal-maturity shales contrast greatly with those of high-TOC, high-thermal-maturity shales. While the high-TOC shales contain abundant organic microporosity, the inorganic pores can contribute a lot to the porosity of the low-TOC shales.     

Pore structure characteristics of tight sandstones in the northern Songliao Basin,China

Understanding the pore structure characteristics of tight gas sandstones is the primary purpose of reservoir evaluation and efforts to characterize tight gas transport and storage mechanisms and their controls. Due to the various pore types and multi-scale pore sizes in tight reservoirs, it is essential to combine several techniques to characterize pore structure. Scanning electron microscopy (SEM), nitrogen gas adsorption (N₂GA), mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR) were conducted on tight sandstones from the Lower Cretaceous Shahezi Formation in the northern Songliao Basin to investigate pore structure characteristics systematically (e.g., type and size distribution of pores) and to establish how significant porosity and permeability are for different pore types. The studied tight sandstones are composed of intergranular pores, dissolution pores and intercrystalline pores. The integration of N₂GA and NMR can be used as an efficient method to uncover full pore size distribution (PSD) of tight sandstones, with pore sizes ranging from 2 nm to dozens of microns. The full PSDs indicate that the pore sizes of tight sandstones are primarily distributed within 1.0 μm. With an increase in porosity and permeability, pores with larger sizes contribute more to porosity. Intercrystalline pores and intergranular/dissolution pores can be clearly distinguished on the basis of mercury intrusion and surface fractal. The relative contribution of intercrystalline pores to porosity ranges from 58.43% to 91.74% with an average of 79.74%. The intercrystalline pores are the primary contributor to pore space, whereas intergranular/dissolution pores make a considerably greater contribution to permeability. A specific quantity of intergranular/dissolution pores is the key to producing high porosity and permeability in tight sandstone reservoirs. The new two permeability estimation models show an applicable estimation of permeability with R² values of 0.955 and 0.962 for models using D_max (pore diameter corresponding to displacement pressure) and D_f (pore diameter at inflection point), respectively. These results indicate that both D_max and D_f are key factors in determining permeability.     

Quantitative modelling of hydrocarbon expulsion and quality grading of tight oil lacustrine source rocks: Case study of Qingshankou 1 member,central depression,Southern Songliao Basin,China

The quality of source rocks plays an important role in the distribution of tight and conventional oil and gas resources. Despite voluminous studies on source rock hydrocarbon generation, expulsion and overpressure, a quality grading system based on hydrocarbon expulsion capacity is yet to be explored. Such a grading system is expected to be instrumental for tight oil and gas exploration and sweet spot prediction. This study tackles the problem by examining Late Cretaceous, lacustrine source rocks of the Qingshankou 1 Member in the southern Songliao Basin, China. By evaluating generated and residual hydrocarbon amounts of the source rock, the extent of hydrocarbon expulsion is modelled through a mass balance method. The overpressure is estimated using Petromod software. Through correlation between the hydrocarbon expulsion and source rock evaluation parameters [total organic carbon (TOC), kerogen type, vitrinite reflectance (R_o) and overpressure], three classes of high-quality, effective and ineffective source rocks are established. High-quality class contains TOC >2%, type-I kerogen, R_o >1.0%, overpressure >7Mpa, sharp increase of hydrocarbon expulsion along with increasing TOC and overpressure, and high expulsion value at R_o >1%. Source rocks with TOC and R_o <0.8%, type-II₂ & III kerogen, overpressure <3Mpa, and low hydrocarbon expulsion volume are considered ineffective. Rocks with parameters between the two are considered effective. The high-quality class shows a strong empirical control on the distribution of tight oil in the Songliao Basin. This is followed by the effective source rock class. The ineffective class has no measurable contribution to the tight oil reserves. Because the hydrocarbon expulsion efficiency of source rocks is controlled by many factors, the lower limits of the evaluation parameters in different basins may vary. However, the classification method of tight source rocks proposed in this paper should be widely applicable.     

Methane-dominated thermochemical sulphate reduction in the Triassic Feixianguan Formation East Sichuan Basin, China: towards prediction of fatal H2S concentrations

New sour pools have recently found in the Lower Triassic Feixianguan Fm carbonate reservoirs in the East Sichuan Basin in China with H₂S up to 17.4% by volume. A recent blowout from a well drilled into this formation killed hundreds of people as a result of the percentage concentrations of H₂S. In order to assess the origin of fatal H₂S as well as the cause of petroleum alteration, H₂S concentrations and the isotopes, δ³⁴S and δ¹³C have been collected and measured in gas samples from reservoirs. Anhydrite, pyrite and elemental sulphur δ³⁴S values have been measured for comparison. The high concentrations of H₂S gas are found to occur at depths >3000 m (temperature now at 100 °C) in evaporated platform facies oolitic dolomite or limestone that contains anhydrite nodule occurrence within the reservoirs. Where H₂S concentrations are greater than 10% its δ³⁴S values lie between +12.0 and +13.2‰ CDT. This is within the range of anhydrite δ³⁴S values found within the Feixianguan Fm (+11.0 to +21.7‰; average 15.5±3.5‰ CDT). Thus H₂S must have been generated by thermochemical sulphate reduction (TSR) locally within the reservoirs. Burial history analysis and fluid inclusion data reveal that the temperature at which TSR occurred was greater than about 130–140 °C, suggesting that the present depth-temperature minimum is an artifact of post-TSR uplift. Both methane and ethane were actively involved in TSR since the petroleum became almost totally dry (no alkanes except methane) and methane δ¹³C values become significantly heavier as TSR proceeded. Methane δ¹³C difference thus reflects the extent of TSR. While it is tempting to use a present-day depth control (>3000 m) to predict the distribution of H₂S in the Feixianguan Fm, this is an invalid approach since TSR occurred when the formation was buried some 1000–2000 m deeper than it is at present. The likelihood of differential uplift across the basin means that it is important to develop a basinal understanding of the thermal history of the Feixianguan Fm so that it is possible to determine which parts of the basin have been hotter than 130–140 °C.