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Abstract:Pore distribution and micro pore-throat structure characteristics are significant for tight oil reservoir evaluation, but their relationship remains unclear. This paper selects the tight sandstone reservoir of the Chang 7 member of the Xin’anbian Block in the Ordos Basin as the research object and analyzes the pore size distribution and micro pore-throat structure using field emission scanning electron microscopy (FE-SEM), high-pressure mercury injection (HPMI), high-pressure mercury injection, and nuclear magnetic resonance (NMR) analyses. The study finds that: (1) Based on the pore size distribution, the tight sandstone reservoir is characterized by three main patterns with different peak amplitudes. The former peak corresponds to the nanopore scale, and the latter peak corresponds to the micropore scale. Then, the tight sandstone reservoir is categorized into three types: type 1 reservoir contains more nanopores with a nanopore-to-micropore volume ratio of 82:18; type 2 reservoir has a nanopore-to-micropore volume ratio of 47:53; and type 3 reservoir contains more micropores with a nanopore-to-micropore volume ratio of 35:65. (2) Affected by the pore size distribution, the throat radius distributions of different reservoir types are notably offset. The type 1 reservoir throat radius distribution curve is weakly unimodal, with a relatively dispersed distribution and peak ranging from 0.01 μm to 0.025 μm. The type 2 reservoir’s throat radius distribution curve is single-peaked with a wide distribution range and peak from 0.1 μm to 0.25 μm. The type 3 reservoir’s throat radius distribution curve is single-peaked with a relatively narrow distribution and peak from 0.1 μm to 0.25 μm. With increasing micropore volume, pore-throat structure characteristics gradually improve. (3) The correlation between micropore permeability and porosity exceeds that of nanopores, indicating that the development of micropores notably influences the seepage capacity. In the type 1 reservoir, only the mean radius and effective porosity have suitable correlations with the nanopore and micropore porosities. The pore-throat structure parameters of the type 2 and 3 reservoirs have reasonable correlations with the nanopore and micropore porosities, indicating that the development of these types of reservoirs is affected by the pore size distribution. This study is of great significance for evaluating lacustrine tight sandstone reservoirs in China. The research results can provide guidance for evaluating tight sandstone reservoirs in other regions based on pore size distribution.

Abstract:Reservoir porosity is a critical parameter for the process of unconventional oil and gas resources assessment. It is difficult to determine the porosity of a gas shale reservoir, and any large deviation will directly reduce the credibility of any shale gas resources evaluation. However, there is no quantitative explanation for the accuracy of porosity measurement. In this paper, measurement uncertainty, an internationally recognized index, was used to evaluate the results of porosity measurement of gas shale plugs, and its impact on the credibility of shale gas resources assessment was determined. The following conclusions are drawn: (1) the measurement uncertainty of porosity of a shale plug is 1.76%–3.12% using current measurement methods, the upper end of which is too large to be acceptable. It is suggested that the measurement uncertainty should be factored into the standard helium gas injection porosity determination experiment, and the uncertainty should be less than 2.00% when using a high-precision pressure gauge; (2) in order to reduce the risk for exploration and decision-making, attention should be paid to the large uncertainty (30% at least) of shale gas resource assessment results, sometimes with corrections being made based on the practical considerations;(3) a pressure gauge with an accuracy of 0.25% of the full scal cannot meet the requirements of porosity measurement, and a high-precision plug cutting method or high-precision bulk volume measurement method such as one using 3D scanning, is recommended to effectively reduce porosity uncertainty; (4) the method and process for evaluating the measurement uncertainty of gas shale porosity could also be referred for assessment of experimental quality by other laboratories.

Abstract:The methods of nuclear magnetic resonance (NMR) spectroscopy, mercury injection porosimetry (MIP), and gas-water relative permeability (GWRP) were used to reveal the pore structure and permeability characteristics of high-rank coal reservoirs in the Bide-Santang basin, western Guizhou, South China, to provide guidance for coalbed methane (CBM) exploration and exploitation and obtain direct insights for the development of CBM wells. The results indicate that the coal reservoirs in the study area are characterized by well-developed adsorption pores and poorly developed seepage pores. The bimodal NMR transverse relaxation time (T2) spectra and the mutation in the fractal characteristic of the MIP pore volume indicate poor connectivity between the adsorption pores and the seepage pores. As a result, the effective porosity is relatively low, with an average of 1.70%. The irreducible water saturation of the coal reservoir is relatively high, with an average of 66%, leading to a low gas relative permeability under irreducible water saturation. This is the main reason for the low recovery of high-rank CBM reservoirs, and effective enhanced CBM recovery technology urgently is needed. As a nondestructive and less time-consuming technique, the NMR is a promising method to quantitatively characterize the pores and fractures of coals.

Abstract:The Cenozoic continental strata of the Bohai Bay Basin are rich in shale oil resources, and they contain various types of reservoir spaces that are controlled by complex factors. Using field emission scanning electron microscopy (FE-SEM), automatic mineral identification and characterization system (AMICS), CO2 and N2 gas adsorption, and focused ion beam scanning electron microscopy (FIB-SEM), the types of shale reservoir spaces in the Bohai Bay Basin are summarized, the spatial distribution and connectivity of the various types of pores are described in detail, the microscopic pore structures are characterized, and the key geological mechanisms affecting the formation and evolution of the reservoir spaces are determined. Three conclusions can be drawn in the present study. First, the shale reservoir spaces in the Bohai Bay Basin can be divided into three broad categories, including mineral matrix pores, organic matter pores, and micro fractures. Those spaces can be subdivided into seven categories and fourteen sub-categories based on the distribution and formation mechanisms of the pores. Second, the complex pore-throat structures of the shale reservoir can be divided into two types based on the shape of the adsorption hysteresis loop. The pore structures mainly include wedge-shaped, flat slit-shaped, and ink bottle-shaped pores. The mesopores and micropores are the main contributors to pore volume and specific surface area, respectively. The macropores provide a portion of the pore volume, but they do not significantly contribute to the specific surface area. Third, the factors controlling the development of microscopic pores in the shale are complex. The sedimentary environment determines the composition and structure of the shale and provides the material basis for pore development. Diagenesis controls the types and characteristics of the pores. In addition, the thermal evolution of the organic matter is closely related to inorganic diagenesis and drives the formation and evolution of the pores.

Abstract:Shale gas is becoming an important component of the global energy supply, with permeability a critical controlling factor for long-term gas production. Obvious deviation may exist between helium permeability determined using small pressure gradient (SPG) methods and methane permeability obtained under actual field production with variable pressure gradients (VPG). In order to more accurately evaluate the matrix permeability of shale, a VPG method using real gas (rather than He) is established to render permeability measurements that are more representative of reservoir conditions and hence response. Dynamic methane production experiments were performed to measure permeability using the annular space in the shale cores. For each production stage, boundary pressure is maintained at a constant and the gas production with time is measured on the basis of volume change history in the measuring pump. A mathematical model explicitly accommodating gas desorption uses pseudo-pressure and pseudo-time to accommodate the effects of variations in pressure-dependent PVT parameters. Analytical and semi-analytical solutions to the model are obtained and discussed. These provide a convenient approach to estimate radial permeability in the core by nonlinear fitting to match the semi-analytical solution with the recorded gas production data. Results indicate that the radial permeability of the shale determined using methane is in the range of 1×10?6 – 1×10?5 mD and decreases with a decrease in average pore pressure. This is contrary to the observed change in permeability estimated using helium. Bedding geometry has a significant influence on shale permeability with permeability in parallel bedding orientation larger than that in perpendicular bedding orientation. The superiority of the VPG method is confirmed by comparing permeability test results obtained from both VPG and SPG methods. Although several assumptions are used, the results obtained from the VPG method with reservoir gas are much closer to reality and may be directly used for actual gas production evaluation and prediction, through accommodating realistic pressure dependent impacts.

Abstract:As the two important components of shale, organic matter (OM) and clay minerals are usually thought to strongly influence the hydrocarbon generation, enrichment and exploitation. The evolution process of OM and clay minerals as well as their interrelationship over a wide range of thermal maturities are not completely clear. Taking Yanchang (T3y), Longmaxi (S1l) and Niutitang (?1n) shales as examples, we have studied the microstructure characteristics of OM and clay minerals in shales with different thermal maturities. The effects of clay minerals and OM on pores were reinforced through sedimentation experiments. Using a combination of field emission scanning electron microscopy (FE-SEM) and low-pressure N2 adsorption, we investigated the microstructure differences among the three shales. The results showed that both OM and clay minerals have strong effects on pores, and small mesopore (2–20 nm) is the dominant pore component for all three samples. However, the differences between the three samples are embodied in the distribution of pore size and the location. For the T3y shale, clay minerals are loosely arranged and develop large amounts of pores, and fine OM grains often fill in intergranular minerals or fractures. Widespread OM pores distribute irregularly in S1l shale, and most of the pores are elliptical and nondirectional. The ?1n shale is characterized by the preferred orientational OM-clay aggregates, and lots of pores in the composites are in the mesopore range, suggesting that over maturity lead to the collapse and compaction of pores under huge pressure of strata. The results of the current research imply that with increasing thermal maturity, OM pores are absent at low maturity (T3y), are maximized at high maturity (S1l) and are destroyed or compacted at over-mature stage (?1n). Meanwhile, clay minerals have gone through mineral transformation and orientational evolution. The interaction of the two processes makes a significant difference to the microstructure evolution of OM and clay minerals in shale, and the findings provide scientific foundation in better understanding diagenetic evolution and hydrocarbon generation of shale.

Abstract:Tight sandstone, with severe diagenesis and complex pore structure, differs greatly from conventional sandstone in terms of rock electrical parameters. In subsurface rock electrical experiments, various electrical parameters are confounded and can only be analyzed qualitatively. The lack of quantitative analysis for each individual electrical parameter presents a challenge for the evaluation of oil and gas saturation in tight sandstone. Based on the 2D pore-throat model and the features of pore structure in the tight sandstone of the Penglaizhen and Shaximiao Formations in the upper and middle Jurassic of the Western Sichuan Depression, this paper presents 3D micro pore-throat models for three types of tight sandstone. It proposes a finite element-based rock electrical simulation method to analyze the influence of pore structure parameters, such as throat radius and throat tortuosity, on electrical parameters such as resistivity, formation factor, and cementation index quantitatively. The research revealed the following results: (1) Throats of tight sandstone usually have lamellar or curved lamellar shapes that are slender and narrow. The lamellar throat used in the proposed pore-throat model is more consistent with the features of tight sandstone than the tubular throat used in the original model. (2) The throat determines the conductivity of tight sandstone. The throat parallel to the electric potential has the greatest influence on conductivity, and the throat perpendicular to the potential has the least influence. (3) In tight sandstone grades I to III, as the porosity decreases, the formation factor increases and the cementation index decreases. (4) The results of the rock electrical simulation are consistent with the results of the rock electrical experiment, which indicates that the proposed rock electrical simulation method of tight sandstone is effective and accurate.

Abstract:Cast thin section observation, scanning electron microscopy (SEM), high-pressure mercury injection (HPMI), and nuclear magnetic resonance (NMR) were used to examine the microstructure of tight carbonate reservoirs in the Lower Jurassic Da'anzhai Member, the central Sichuan Basin. The pore space in the Da'anzhai Member is classified into 2 types and 17 subtypes, with nano-scale pore throats of ‘O’, ‘S’, ‘Z’, and ‘I’ shapes. Poorly sorted pore throats vary greatly in diameter; thus, it is difficult for fluid flow to pass through these pore throats. There are three classes of pore throats in carbonate reservoirs, i.e. isolated pores, pores coexisting with fractures, and large pores and fractures. Isolated pores may provide some pore space, but the permeability is low. Pores and fractures coexisting in the reservoir may have a great impact on porosity and permeability; they are the major pore space in the reservoir. Large pores and fractures have a great impact on reservoir properties, but they only account for a limited proportion of total pore space. The microstructure of Da'anzhai reservoirs, which dominates fluid mobility, is dependent on sedimentary environment, diagenesis, and tectonic process. Pore structure is related to sedimentary environment. The occurrence of microfractures, which may improve reservoir properties, is dependent on tectonic process. Diageneses are of utmost importance to pore evolution, cementation and growth of minerals have played an important role in destroying reservoir microstructure.

Abstract:In this study, the types of micropores in a reservoir are analyzed using casting thin section (CTS) observation and scanning electron microscopy (SEM) experiments. The high-pressure mercury injection (HPMI) and constant-rate mercury injection (CRMI) experiments are performed to study the micropore structure of the reservoir. Nuclear magnetic resonance (NMR), gas-water relative seepage, and gas-water two-phase displacement studies are performed to examine the seepage ability and parameters of the reservoir, and further analyses are done to confirm the controlling effects of reservoir micropore structures on seepage ability. The experimental results show that Benxi, Taiyuan, Shanxi, and Shihezi formations in the study area are typical ultra-low porosity and ultra-low permeability reservoirs. Owing to compaction and later diagenetic transformation, they contain few primary pores. Secondary pores are the main pore types of reservoirs in the study area. Six main types of secondary pores are: intergranular dissolved pores, intragranular dissolved pores, lithic dissolved pores, intercrystalline dissolved pores, micropores, and microfracture. The results show that reservoirs with small pore-throat radius, medium displacement pressure, and large differences in pore-throat structures are present in the study area. The four types of micropore structures observed are: lower displacement pressure and fine pores with medium-fine throats, low displacement pressure and fine micropores with fine throats, medium displacement pressure and micropores with micro-fine throats, and high displacement pressure and micropores with micro throats. The micropore structure is complex, and the reservoir seepage ability is poor in the study areas. The movable fluid saturation, range of the gas-water two-phase seepage zone, and displacement types are the three parameters that well represent the reservoir seepage ability. According to the characteristic parameters of microscopic pore structure and seepage characteristics, the reservoirs in the study area are classified into four types (I–IV), and types I, II, and III are the main types observed. From type I to type IV, the displacement pressure increases, and the movable fluid saturation and gas-water two-phase seepage zone decrease, and the displacement type changes from the reticulation-uniform displacement to dendritic and snake like.

Abstract:The Songliao Basin is one of the most important petroliferous basins in northern China. With a recent gradual decline in conventional oil production in the basin, the exploration and development of unconventional resources are becoming increasingly urgent. The Qingshankou Formation consists of typical Upper Cretaceous continental strata, and represents a promising and practical replacement resource for shale oil in the Songliao Basin. Previous studies have shown that low-mature to mature Qingshankou shale mainly preserves type I and type II1 organic matter, with relatively high total organic carbon (TOC) content. It is estimated that there is a great potential to explore for shale oil resources in the Qingshankou Formation in this basin. However, not enough systematic research has been conducted on pore characteristics and their main controlling factors in this lacustrine shale reservoir. In this study, 19 Qingshankou shales from two wells drilled in the study area were tested and analyzed for mineral composition, pore distribution and feature evolution using X-ray diffraction (XRD), scanning electron microscopy (SEM), low-pressure nitrogen gas adsorption (N2-GA), and thermal simulation experiments. The XRD results show that clay, quartz, and feldspar are the dominant mineral constituents of Qingshankou shale. The clay minerals are mostly illite/smectite mixed layers with a mean content of 83.5%, followed by illite, chlorite, and kaolinite. There are abundant deposits of clay-rich shale in the Qingshankou Formation in the study area, within which many mineral and organic matter pores were observed using SEM. Mineral pores contribute the most to shale porosity; specifically, clay mineral pores and carbonate pores comprise most of the mineral pores in the shale. Among the three types of organic matter pores, type B is more dominant the other two. Pores with diameters greater than 10 nm supply the main pore volume; most are half-open slits and wedge-shaped pores. The total pore volume had no obvious linear relationship with TOC content, but had some degree of positive correlation with the content of quartz + feldspar and clay minerals respectively. However, it was negatively correlated with carbonate mineral content. The specific surface area of the pores is negatively related to TOC content, average pore diameter, and carbonate mineral content. Moreover, it had a somewhat positive correlation with clay mineral content and no clear linear relationship with the content of quartz + feldspar. With increases in maturity, there was also an increase in the number of carbonate mineral dissolution pores and organic matter pores, average pore diameter, and pore volume, whereas there was a decrease in specific surface area of the pores. Generally, the Qingshankou shale is at a low-mature to mature stage with a TOC content of more than 1.0%, and could be as thick as 250 m in the study area. Pores with diameters of more than 10 nm are well-developed in the shale. This research illustrates that there are favorable conditions for shale oil occurrence and enrichment in the Qingshankou shale in the study area.

Abstract:To reveal the effect of shale reservoir characteristics on the movability of shale oil and its action mechanism in the lower third member of the Shahejie Formation (Es3l), samples with different features were selected and analyzed using N2 adsorption, high-pressure mercury injection capillary pressure (MICP), nuclear magnetic resonance (NMR), high-speed centrifugation, and displacement image techniques. The results show that shale pore structure characteristics control shale oil movability directly. Movable oil saturation has a positive relationship with pore volume for radius > 2 μm, as larger pores often have higher movable oil saturation, indicating that movable oil is present in relatively larger pores. The main reasons for this are as follows. The relatively smaller pores often have oil-wetting properties because of organic matter, which has an unfavorable effect on the flow of oil, while the relatively larger pores are often wetted by water, which is helpful to shale oil movability. The rich surface provided by the relatively smaller pores is beneficial to the adsorption of immovable oil. Meanwhile, the relatively larger pores create significant pore volume for movable oil. Moreover, the larger pores often have good pore connectivity. Pores and fractures are interconnected to form a complex fracture network, which provides a good permeability channel for shale oil flow. The smaller pores are mostly distributed separately; thus, they are not conducive to the flow of shale oil. The mineral composition and fabric macroscopically affect the movability of shale oil. Calcite plays an active role in shale oil movability by increasing the brittleness of shale and is more likely to form micro-cracks under the same stress background. Clay does not utilize shale oil flow because of its large specific surface area and its block effect. The bedding structure increases the large-scale storage space and improves the connectivity of pores at different scales, which is conducive to the movability of shale oil.

Abstract:Coal measure source rocks, located in the Xihu Sag of the East China Sea Shelf Basin, were analyzed to define the hydrocarbon generation potential, organic geochemistry/petrology characteristics, and coal preservation conditions. The Pinghu source rocks in the Xihu Sag are mainly gas-prone accompany with condensate oil generation. The coals and shales of the Pinghu Formation are classified from “fair” to “excellent” source rocks with total organic carbon (TOC) contents ranging from 25.2% to 77.2% and 1.29% to 20.9%, respectively. The coals are richer in TOC and S1+S2 than the shales, indicating that the coals have more generation potential per unit mass. Moreover, the kerogen type of the organic matter consists of types Ⅱ-Ⅲ and Ⅲ, which the maturity Ro ranges from 0.59% to 0.83%. Petrographically, the coals and shales are dominated by vitrinite macerals (69.1%–96.8%) with minor proportions of liptinite (2.5%–17.55%) and inertinite (0.2%–6.2%). The correlation between maceral composition and S1+S2 indicates that the main contributor to the generation potential is vitrinite. Therefore, the coals and shales of the Pinghu Formation has good hydrocarbon generation potential, which provided a good foundation for coal measure gas accumulation. Furthermore, coal facies models indicates that the Pinghu coal was deposited in limno-telmatic environment under high water levels, with low tree density (mainly herbaceous) and with low-moderate nutrient supply. Fluctuating water levels and intermittent flooding during the deposition of peat resulted in the inter-layering of coal, shale and sandstone, which potentially providing favorable preservation conditions for coal measure gas.

Abstract:A scientific exploration well (CK1) was drilled to expand the oil/gas production in the western Sichuan depression, SW, China. Seventy-three core samples and four natural gas samples from the Middle–Late Triassic strata were analyzed to determine the paleo-depositional setting and the abundance of organic matter (OM) and to evaluate the hydrocarbon-generation process and potential. This information was then used to identify the origin of the natural gas. The OM is characterized by medium n-alkanes (nC15–nC19), low pristane/phytane and terrigenous aquatic ratios (TAR), a carbon preference index (CPI) of ~1, regular steranes with C29 > C27 > C28, gammacerane/C30hopane ratios of 0.15–0.32, and δDorg of ?132‰ to ?58‰, suggesting a marine algal/phytoplankton source with terrestrial input deposited in a reducing–transitional saline/marine sedimentary environment. Based on the TOC, HI index, and chloroform bitumen “A,” the algal-rich dolomites of the Leikoupo Formation are fair–good source rocks; the grey limestones of the Maantang Formation are fair source rocks; and the shales of the Xiaotangzi Formation are moderately good source rocks. In addition, maceral and carbon isotopes indicate that the kerogen of the Leikoupo and Maantang formations is type II and that of the Xiaotangzi Formation is type II–III. The maturity parameters and the hopane and sterane isomerization suggest that the OM was advanced mature and produced wet–dry gases. One-dimensional modeling of the thermal-burial history suggests that hydrocarbon-generation occurred at 220–60 Ma. The gas components and C–H–He–Ar–Ne isotopes indicate that the oil-associated gases were generated in the Leikoupo and Maantang formations, and then, they mixed with gases from the Xiaotangzi Formation, which were probably contributed by the underlying Permian marine source rocks. Therefore, the deeply-buried Middle–Late Triassic marine source rocks in the western Sichuan depression and in similar basins have a great significant hydrocarbon potential.

Abstract:The majority of coalbed methane (CBM) in coal reservoirs is in adsorption states in coal matrix pores. To reveal the adsorption behavior of bituminous coal under high-temperature and high-pressure conditions and to discuss the microscopic control mechanism affecting the adsorption characteristics, isothermal adsorption experiments under high-temperature and high-pressure conditions, low-temperature liquid nitrogen adsorption-desorption experiments and CO2 adsorption experiments were performed on coal samples. Results show that the adsorption capacity of coal is comprehensively controlled by the maximum vitrinite reflectance (Ro, max), as well as temperature and pressure conditions. As the vitrinite reflectance increases, the adsorption capacity of coal increases. At low pressures, the pressure has a significant effect on the positive effect of adsorption, but the effect of temperature is relatively weak. As the pressure increases, the effect of temperature on the negative effect of adsorption gradually becomes apparent, and the influence of pressure gradually decreases. Considering pore volumes of pores with diameters of 1.7?100 nm, the peak volume of pores with diameters 10?100 nm is higher than that from pores with diameters 1.7?10 nm, especially for pores with diameters of 40?60 nm, indicating that pores with diameters of 10?100 nm are the main contributors to the pore volume. The pore specific surface area shows multiple peaks, and the peak value appears for pore diameters of 2?3 nm, indicating that this pore diameter is the main contributor to the specific surface area. For pore diameters of 0.489?1.083 nm, the pore size distribution is bimodal, with peak values at 0.56?0.62 nm and 0.82?0.88 nm. The adsorption capability of the coal reservoir depends on the development degree of the supermicroporous speci?c surface area, because the supermicroporous pores are the main contributors to the specific pore area. Additionally, the adsorption space increases as the adsorption equilibrium pressure increases. Under the same pressure, as the maximum vitrinite reflectance increases, the adsorption space increases. In addition, the cumulative reduction in the surface free energy increases as the maximum vitrinite reflectance increases. Furthermore, as the pressure increases, the surface free energy of each pressure point gradually decreases, indicating that as the pressure increases, it is increasingly difficult to adsorb methane molecules.

Abstract:Coal-bearing strata are widespread in the western Great Khingan Mountains. Abundant coal resources have been found in the Jurassic Alatanheli Groups, the Cretaceous Bayanhua Groups, the Damoguaihe Formation and the Yimin Formation. The organic geochemical characteristics were analyzed in combination with hydrocarbon source rock evaluation and molecular organic geochemistry experiments, and the coal gas potential of coal seams was evaluated. The source rock evaluation results indicated that the Mesozoic coal samples have the characteristics of high organic matter abundance (TOC>30%), low maturity (Ro values of approximately 0.6%), and type III composition. The hydrocarbon generation potentials of the Alatanheli Groups and Bayanhua Groups are high, while the generation potentials of the Damoguaihe Formation and the Yimin Formation are low. The results of geochemistry show that the depositional environment of the coal seam was a lacustrine, oxidizing environment with a low salinity, and the source of the organic matter was mainly higher plants. Affected by weak degradation, the coal seams mainly formed low-maturity gas of thermal catalytic origin. The Cretaceous coal seams contain a large amount of phytoplankton groups deposited in a low-stability environment affected by a transgression event, and the potential range varied widely. For the Jurassic coal seams, the depositional environment was more stable, and the coal seams feature a higher coal-forming gas potential.

Abstract:Based on core observation, cast and fluorescent thin sections, FESEM and ESEM, coquina in Da'anzhai Member of Jurassic in Sichuan Basin were examined systematically. Together with production data and logging evaluation, a method for lacustrine coquina evaluation based on geological theory was established up. In the article, two aspects of the study were elaborated, characteristics of favorable reservoirs, and a “five-step” evaluation method for favorable coquina reservoir. According to the correlation between porosity and production data, porosity is not effective in finding high quality coquina reservoir of this area. Whereas micro research of reservoir samples from a high productivity well revealed that sparry coquina is the best lithofacies, with the most developed micro storage space of various kinds. After the favorable reservoir was sorted out, a five-step method evaluating the coquina reservoir was worked out. Correlation of GR value and rock types suggests that GR<30 API is an effective evaluation parameter in identifying profitable reservoir lithofacies. Meanwhile, the combination of profitable reservoir rock thickness and production data revealed that the reservoirs with the highest potentiality are those with thickness of 3–18 m. Fractures are more developed in faults, folds and structural noses in the study area. Organic acid is discharged massively before the peak of hydrocarbon generation, leading to the formation of dissolution pores in the reservoir. The evaluation of organic acid was made by using the source rock indexes. After evaluating the four factors, and compiling their distribution maps, the maps were overlapped to predict favorable reservoir zones, and 7 first class and 9 second class favorable zones of coquina were picked out.

Abstract:Tight sandstone gas in the Linxing Block, eastern Ordos Basin, has been successfully exploited. The high performance is mainly a result of the special geological conditions. The key geological controls for high production have been discussed on the basis of seismic data, field observation, sample features, mercury porosimetry, mechanical properties, and basin modeling. Firstly, the coal measures have good gas generation potential, not only because of the existence of coalbeds and organic-rich shales, but also because coal laminae and microbial mats in the shales significantly increase their total organic carbon (TOC) contents. Secondly, except for the uplifted zone of the Zijinshan complex and the eastern fault zone, rare large faults develop in the Carboniferous–Permian sequence, ensuing the sealing capacity of cap rock. Small fractures generally concentrated in the sandstones rather than the mudstones. Thirdly, gas accumulation in the Linxing Block was controlled by the tectonic, burial and thermal histories. Gas accumulation in the Linxing Block started in the Late Triassic, followed by three short pauses of thermal maturation caused by relatively small uplifts; the maximum hydrocarbon generation period is the Early Cetaceous as a combined result of regional and magmatic thermal metamorphisms. Field profiles show abundant fractures in sandstone beds but rare fractures in mudstone beds. Mechanical properties, determined by lithostratigraphy, confine the fractures in the sandstones, increasing the permeability of sandstone reservoirs and retaining the sealing capacity of the mudstone cap rocks. The modern ground stress conditions favor the opening of predominant natural fractures in the NNW?SSE and N?S directions. These conclusions are useful for exploring the potential tight sandstone gas field.

Abstract:Multiple coal seams and interbedded rock assemblages formed in vertical progression due to the influence of multiple stages of sea level transgressions. Based on mercury injection experiment, low temperature liquid nitrogen experiment, porosity and permeability experiment and breakthrough pressure experiment, the vertical variation characteristics of coal-bearing strata in Gujiao block are explained in detail. The results of the mercury injection and low temperature liquid nitrogen experiments show that the pore structure characteristics fluctuate with increasing depth in the strata, with fewer micropores followed by transition pores. The BET specific surface area and average pore diameter of the Shanxi Formation are generally larger than those of the Taiyuan Formation. Due to the continuous cyclic sequence stratigraphy changes, the porosity, permeability, breakthrough pressure and breakthrough time of the samples show a certain cyclicity. Within the same sequence, the porosity is larger, and the permeability is smaller near the maximum flooding surface. Although the permeability of the sandstone samples is higher, the porosity is lower, and the breakthrough pressure and breakthrough times are greater. The strata in the study area formed in an oxidized environment that was affected by freshwater, and the pore structure of different lithologies is quite different. After the formation of sandstone, the intergranular pores generally underwent filling with secondary quartz, clay minerals and organic matter, resulting in low porosity and permeability.

Abstract:The description of pores and fracture structures is a consistently important issue and certainly a difficult problem, especially for shale or tight rocks. However, the exploitation of so-called unconventional energy, such as shale methane and tight-oil, has become more and more dependent on an understanding of the inner structure of these unconventional reservoirs. The inner structure of porous rocks is very difficult to describe quantitatively using normal mathematics, but fractal geometry, which is a powerful mathematical tool for describing irregularly-shaped objects, can be applied to these rocks. To some degree, the cementation index and tortuosity can be used to describe the complexity of these structures. The cementation index can be acquired through electro-lithology experiments, but, until now, tortuosity could not be quantitatively depicted. This research used the well-logging curves of a gas shale formation to reflect the characteristics of the rock formations, and the changes in the curves to indicate the changes of the rock matrix, the pores, the connections among the pores, the permeability, and the fluid type. The curves that are affected most by the rock lithology, such as gamma ray, acoustic logging, and deep resistivity curves, can provide significant information about the micro- or nano-structure of the rocks. If the rock structures have fractal characteristics, the logging curves will also have fractal properties. Based on the definition of a fractal dimension and the Hausdorff dimension, this paper presents a new methodology for calculating the fractal dimensions of logging curves. This paper also reveals the deep meaning of the rock cementation index, m, through the Hausdorff dimension, and provides a new equation to calculate this parameter through the resistivity and porosity of the formation. Although it represents a very important relationship between the saturation of hydrocarbons with pores and resistivity, the Archie formula was not available for shale and tight rock. The major reason for this was an incorrect understanding of the cementation index, and the calculation of saturation used a single m value from the bottom to the top of the well. Unfortunately, this processing method is clearly inappropriate for the intensely heterogeneous material that is shale and tight rock. This paper proposes a method of calculating m through well-logging curves based on a fractal geometry that can change with different lithologies, so that it would have more agreement with in situ scenarios than traditional methods.

Abstract:The sedimentary, paleogeomorphological and reservoir characteristics of the Jurassic Yan’an Formation in the southwestern Ordos Basin, northwestern China, were studied by means of casting thin sections, scanning electron microscopy, inclusion analysis and identification of low-amplitude structures. A model for reservoir formation is established, and the controlling effects of sedimentary facies, paleotopography, low-amplitude structures and formation water on oil reservoirs are revealed. There are significant differences in the sedimentary characteristics, structural morphology and paleowater characteristics between the reservoirs above the Yan 10 Member and those in the Yan 9 to Yan 7 Members. The Yan 10 Member contains fluvial sediments, whereas the Yan 9 to Yan 7 members contain delta-plain anastomosing-river deposits. The distribution of high-permeability reservoir is controlled by pre-Jurassic paleogeomorphology and sedimentary facies. Some of these facies exhibit high porosity and high permeability in a low-permeability background. The main hydrocarbon accumulation period was the late Early Cretaceous, filling was continuous, and the charging strength altered from weak to strong and then from strong to weak. The Yan 10 reservoir is mainly controlled by the paleogeomorphology: hydrocarbons migrated upward at a high speed through the unconformity surface, and accumulated in the favorable traps formed by paleogeomorphic structural units, such as gentle slopes or channel island. Furthermore, groundwater alternation in these areas was relatively stagnant, providing good reservoir preservation conditions. The reservoirs in the Yan 9 and higher members are controlled by the sedimentary facies, low-amplitude structure and paleowater characteristics. Hydrocarbons migrated through the three-dimensional delivery system, influenced by favorable sedimentary facies and high-salinity groundwater, then accumulated in the favorable low-amplitude structural traps that formed during the hydrocarbon production period.

Abstract:There are abundant coal and coalbed methane (CBM) resources in the Xishanyao Formation in the western region of the southern Junggar Basin, and the prospects for CBM exploration and development are promising. To promote the exploration and development of the CBM resources of the Xishanyao Formation in this area, we studied previous coalfield survey data and CBM geological exploration data. Then, we analyzed the relationships between the gas content and methane concentration vs. coal seam thickness, burial depth, coal reservoir physical characteristics, hydrogeological conditions, and roof and floor lithology. In addition, we briefly discuss the main factors influencing CBM accumulation. First, we found that the coal strata of the Xishanyao Formation in the study area are relatively simple in structure, and the coal seam has a large thickness and burial depth, as well as moderately good roof and floor conditions. The hydrogeological conditions and coal reservoir physical characteristics are also conducive to the enrichment and a high yield of CBM. We believe that the preservation of CBM resources in the study area is mainly controlled by the structure, burial depth, and hydrogeological conditions. Furthermore, on the basis of the above results, the coal seam of the Xishanyao Formation in the synclinal shaft and buried at depths of 700–1000 m should be the first considered for development.

Abstract:On the basis of reprocessing 34 new two-dimensional spliced long sections (20,191 km) in the Tarim Basin, the deep structure features of the Tarim Basin were analyzed through interpreting 30,451 km of two-dimensional seismic data and compiling basic maps. Seismic interpretation and geological analysis conclude that the Nanhua-Sinian strata are a set of rift-depression depositional systems according to their tectonic and depositional features. The rift valley formed in the Nanhua Period, and the transformation became weaker during the late Sinian Period, which eventually turned into depression. From bottom to top, the deposited strata include mafic igneous, tillite, mudstone, and dolomite. Three major depocenters developed inside this basin during the rift stage and are distributed in the eastern Tarim Basin, the Awati area, and the southwestern Tarim Basin. Among them, the rift in the eastern Tarim Basin strikes in the near east-west direction on the plane and coincides with the aeromagnetic anomaly belt. This represents a strong magnetic zone formed by upwelling basic volcanic rock along high, steep normal faults of the Nanhua Period. Controlled by the tectonic background, two types of sedimentary systems were developed in the rift stage and depression stage, showing two types of sequence features in the Sinian depositional stage. The Nanhua System appears as a wedge-shaped formation, with its bottom in unconformable contact with the base. The rifting event has a strong influence on the current tectonic units in the Tarim Basin, and affects the distribution of source rock in the Yuertus Formation and reservoir beds in the Xiaoerbulake Formation in Lower Cambrian, as well as the gypseous cap rock in Middle Cambrian. The distribution features of the rifts have important and realistic significance for determining the direction of oil and gas exploration in the deep strata of the Tarim Basin. Comprehensive analysis suggests that the Tazhong region is the most favorable zone, and the Kalpin-Bachu region is the optimal potential zone for exploring sub-salt oil and gas in deep Cambrian strata.

Abstract:The detailed characteristics of the Paleozoic strike-slip fault zones developed in the northern slope of Tazhong uplift are closely related to hydrocarbon explorations. In this study, five major strike-slip fault zones that cut through the Cambrian-Middle Devonian units are identified, by using 3D seismic data. Each of the strike-slip fault zones is characterized by two styles of deformation, namely deeper strike-slip faults and shallower en-echelon faults. By counting the reverse separation of the horizon along the deeper faults, activity intensity on the deeper strike-slip faults in the south is stronger than that on the northern ones. The angle between the strike of the shallower en-echelon normal faults and the principal displacement zone (PDZ) below them is likely to have a tendency to decrease slightly from the south to the north, which may indicate that activity intensity on the shallower southern en-echelon faults is stronger than that on the northern ones. Comparing the reverse separation along the deeper faults and the fault throw of the shallower faults, activity intensity of the Fault zone S1 is similar across different layers, while the activity intensity of the southern faults is larger than that of the northern ones. It is obvious that both the activity intensity of the same layer in different fault zones and different layers in the same fault zone have a macro characteristic in that the southern faults show stronger activity intensity than the northern ones. The Late Ordovician décollement layer developed in the Tazhong area and the peripheral tectonic events of the Tarim Basin have been considered two main factors in the differential deformation characteristics of the strike-slip fault zones in the northern slope of Tazhong uplift. They controlled the differences in the multi-level and multi-stage deformations of the strike-slip faults, respectively. In particular, peripheral tectonic events of the Tarim Basin were the dynamic source of the formatting and evolution of the strike-slip fault zones, and good candidates to accommodate the differential activity intensity of these faults.

Abstract:Higher-precision determinations of hydrate reservoirs, hydrate saturation levels and storage estimations are important for guaranteeing the ability to continuously research, develop and utilize natural gas hydrate resources in China. With seismic stereoscopic detection technology, which fully combines the advantages of different seismic detection models, hydrate formation layers can be observed with multiangle, wide-azimuth, wide-band data with a high precision. This technique provides more reliable data for analyzing the distribution characteristics of gas hydrate reservoirs, establishing velocity models, and studying the hydrate-sensitive properties of petrophysical parameters; these data are of great significance for the exploration and development of natural gas hydrate resources. Based on a velocity model obtained from the analysis of horizontal streamer velocity data in the hydrate-bearing area of the Shenhu Sea, this paper uses three VCs (longitudinal spacing of 25 m) and four OBSs (transverse spacing of 200 m) to jointly detect seismic datasets consisting of wave points based on an inversion of traveltime imaging sections. Accordingly, by comparing the differences between the seismic phases in the original data and the forward-modeled seismic phases, multiangle coverage constraint corrections are applied to the initial velocity model, and the initial model is further optimized, thereby improving the imaging quality of the streamer data. Petrophysical elastic parameters are the physical parameters that are most directly and closely related to rock formations and reservoir physical properties. Based on the optimized velocity model, the rock elastic hydrate-sensitive parameters of the hydrate reservoirs in the study area are inverted, and the sensitivities of the petrophysical parameters to natural gas hydrates are investigated. According to an analysis of the inversion results obtained from these sensitive parameters, λρ, Vp and λμ are simultaneously controlled by the bulk modulus and shear modulus, while Vs and μρ are controlled only by the shear modulus, and the latter two parameters are less sensitive to hydrate-bearing layers. The bulk modulus is speculated to be more sensitive than the shear modulus to hydrates. In other words, estimating the specific gravity of the shear modulus among the combined parameters can affect the results from the combined elastic parameters regarding hydrate reservoirs.

Abstract:Accurately identifying and quantitatively describing abandoned channels in meandering rivers are of great significance for improving hydrocarbon recovery. By using modern deposition analogy, field outcrop analysis, a dense well spacing, core observations and a review of the literature, this paper studied the formation process and space–time amalgamation of abandoned channels in meandering river. The results reveal that formation mechanisms of abandoned channels include chute cutoff patterns (shoal-cutting, ditch-scouring and embayment-eroding patterns) and neck cutoff patterns. The chute cutoff pattern forms a gradually abandoned channel, while the neck cutoff pattern forms a suddenly abandoned channel. From upstream to downstream, the sedimentary pattern of the abandoned channel transforms from a chute cutoff pattern to a neck cutoff pattern, where the main controlling factors transition from the grain size and gradient to the flow and vegetation. An abandoned channel formed by a chute cutoff pattern consists mainly of siltstone, fine sandstone and thin gravel layers, which form a lithological-physical barrier. The abandoned channel formed by a neck cutoff pattern consists mainly of mudstone and argillaceous siltstone, forming a lithological barrier. Based on the amalgamation and structure of the reservoir architectural elements, the abandoned channel can be divided into three planar sedimentary patterns (crescent, semilune and horseshoe) for a single channel and five vertical sedimentary patterns for composite channels.

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