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Through reviewing the development history of tight oil and gas in China, summarizing theoretical understandings in exploration and development, and comparing the geological conditions and development technologies objectively in China and the United States, we clarified the progress and stage of tight oil and gas exploration and development in China, and envisaged the future development orientation of theory and technology, process methods and development policy. In nearly a decade, relying on the exploration and development practice, science and technology research and management innovation, huge breakthroughs have been made. The laws of formation, distribution and accumulation of tight oil and gas have been researched, the development theories such as “multi-stage pressure drop” and “man-made reservoirs” have been established, and several technology series have been innovated and integrated. These technology series include enrichment regions selection, well pattern deployment, single well production and recovery factor enhancement, and low cost development. As a result, both of reserves and production of tight oil and gas increase rapidly. However, limited by the sedimentary environment and tectonic background, compared with North America, China’s tight oil and gas reservoirs are worse in continuity, more difficult to develop and poorer in economic efficiency. Moreover, there are still some gaps in reservoir identification accuracy and stimulating technology between China and North America. In the future, Chinese oil and gas companies should further improve the resource evaluation method, tackle key technologies such as high-precision 3D seismic interpretation, man-made reservoir, and intelligent engineering, innovate theories and technologies to enhance single well production and recovery rate, and actively endeavor to get the finance and tax subsidy on tight oil and gas.
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Through a comprehensive review of PetroChina overseas oil and gas exploration of more than 20 years, we systematically summarize the development history, development status and application results of the overseas oil and gas exploration theory and technology. Overseas oil and gas exploration has experienced four stages, exploratory exploration, progressive exploration, risk exploration and efficient exploration. The overseas exploration theory and technology have also gone through the initially direct borrow of domestic mature technology to the integrated application, and then to the research innovation based on overseas features. A series of overseas oil and gas exploration theories and technologies represented by theories and technologies for passive rift basins, salt basins and foreland basin slopes, and global oil and gas geology and resource evaluation have been established. On the basis of deep analysis of the future overseas exploration development demand for the technology, and combined with the domestic and overseas future development trend of theory and technology, this paper systematically discusses the overseas exploration difficulties, technical requirements and the main development directions and aims of exploration theory and technology in the future: (1) Develop conventional onshore oil and gas exploration techniques continuously for the overseas exploration and keep them at an internationally advanced level. (2) Develop the global oil and gas resources and assets integrated optimization evaluation technology and its information system construction project innovatively to reach the international leading level. (3) Develop the deep water exploration technology integratively and narrow the gap with the world’s advanced level.
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China has made significant progress in the exploration and development of natural gas in the past 70 years, from the gas-poor country to the world's sixth largest gas production country. In 1949, the annual gas output in China was 1 117×10 4m 3, the proved gas reserves were 3.85×10 8m 3, and the average annual gas consumption and available reserves of per person were 0.020 6 m 3 and 0.710 7 m 3, respectively. By 2018, the average domestic annual gas production per person was 114.857 6 m 3 and the reserves were 12 011.08 m 3, and the average domestic annual gas production and reserves per person in the past 70 years increased by 5 575 times and 16 900 times, respectively. The exploration and development of large gas fields is the main way to rapidly develop the natural gas industry. 72 large gas fields have been discovered in China so far, mainly distributed in three basins, Sichuan (25), Ordos (13) and Tarim (10). In 2018, the total gas production of the large gas fields in these three basins was 1 039.26×10 8m 3, accounting for 65% of the total gas production in China. By the end of 2018, the cumulative proved gas reserves of the 72 large gas fields had amounted to 124504×10 8 m 3, accounting for 75% of the total national gas reserves (16.7×10 12m 3). New theories of natural gas have promoted the development of China's natural gas industry faster. Since 1979, the new theory of coal-derived gas has boosted the discovery of gas fields mainly from coal-measure source rocks in China. In 2018, the gas production of large coal-derived gas fields in China accounted for 50.93% and 75.47% of the total national gas production and total gas production of large gas fields, respectively. Guided by shale gas theories, shale gas fields such as Fuling, Changning, Weiyuan and Weirong have been discovered. In 2018, the total proved geological reserves of shale gas were 10 455.67× 10 8m 3, and the annual gas production was 108.8×10 8m 3, demonstrating a good prospect of shale gas in China.
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After 50 years of oil and gas exploration in Longdong area of southwest Ordos Basin, NW China, a deep coal-formed gas field was discovered for the first time in Qingyang area. Through observation of field outcrops and core, analysis of common, cast and cathode thin sections, Ro and other geochemistry indexes, carbon isotope, electron microscope and other supporting tests and analyses, the hydrocarbon generation, reserves formation and reservoir formation characteristics of gas reservoirs at different buried depths in Yishaan slope were examined and compared. The deep gas reservoir has an average buried depth of more than 4 200 m, and the main gas-bearing formation is the Member 1 of Lower Permian Shanxi Formation, which is characterized by low porosity, low permeability, low pressure and low abundance. It is believed that hydrocarbon generation in thin seam coal source rocks with high thermal evolution can form large gas fields, high-quality sandstone reservoirs with dissolved pores, intergranular pores and intercrystalline pores can still develop in late diagenetic stage under deep burial depth and high thermal evolution, and fractures improve the permeability of reservoirs. High drying coefficient of natural gas and negative carbon isotope series are typical geochemical characteristics of deep coal-formed gas. The integrated exploration and development method has been innovated, and the economic and effective development mode of gas fields of “dissecting sand body by framework vertical wells, centralized development by horizontal wells” has been formed. The discovery and successful exploration of the large gas field has provided geological basis and technical support for the construction of natural gas fields of 100 billion cubic meter scale in the southwest of the basin, and has important guidance for exploration of coal-derived gas with deep buried depth and high thermal evolution widely distributed in China.
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Through the development and calibration of a reference material which is 209.8 Ma old using a newly-developed Laser Ablation (LA) Multi-Collector Inductively Coupled Plasma Mass Spectrometry (MC-ICP-MS) technique, we successfully overcome the difficulty in sampling and dating ultra-low U-Pb ancient marine carbonates, which was previously untenable by isotope dilution (ID) methods. We developed the LA-MC-ICP-MS in situ U-Pb dating technique for ancient marine carbonates for the study of diagenesis-porosity evolution history in Sinian Dengying Formation, Sichuan Basin. By systematically dating of dolomitic cements from vugs, matrix pores and fractures, we found that the burial and diagenetic process of dolomite reservoirs in Sinian Dengying Formation was characterized by progressive filling-up of primary pores and epigenic dissolution vugs. The filling of vugs happened in three stages, early Caledonian, late Hercynian-Indosinian and Yanshanian-Himalayan, while the filling of matrix pores mainly took place in early Caledonian. The unfilled residual vugs, pores and fractures constitute the main reservoir sapce. Based on the above knowledge, we established the diagenesis-porosity evolution history of the dolomite reservoir in Sinian Dengying Formation, Sichuan Basin. These findings are highly consistent with the tectonic-burial and basin thermal histories of the study area. Our study confirmed the reliability of this in situ U-Pb dating technique, which provides an effective way for the investigation of diagenesis-porosity evolution history and evaluation of porosity in ancient marine carbonate reservoirs before hydrocarbon migration.
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Using field geological survey, drilling and seismic data, combined with the study of regional tectonic evolution and structural deformation, as well as lithological and sedimentary analysis, we reconstructed the basin filling process and paleo-geography of north Tarim Basin in Early Cambrian, aiming to analyze the factors controlling the distribution and spatial architecture of the subsalt reservoir and source units and to define the favorable exploration direction. The Late Sinian tectonic activities in the northern Tarim Basin were characterized by different patterns in different areas, which controlled the sedimentary pattern in the Early Cambrian. The boundary faults of Nanhuaian rift basin in the south slope of Tabei uplift and the north slope of Tazhong uplift became reactivated in the Early Cambrian, forming two NEE and EW striking subsidence centers and depocenters, where the predicted thickness of the Yurtusi Formation could reach 250 meters. In the Xiaoerbulake period, the weak rimmed platform was developed in the hanging wall of syndepositional fault. Whereas the Nanhuaian rift system in the Tadong and Manxi areas were uplifted and destroyed in the Late Sinian, and appeared as gently slope transiting toward the subsidence center in the Early Cambrian. The former had the sedimentary features of hybrid facies platform and the latter had the sedimentary features of ramp platform. The black shale of the Yurtus Formation in the footwall of syndepositional fault and the reef bank of Xiaoerbulake Formation platform margin in the hanging wall in Early Cambrian constitute a predicable source-reservoir combination. The activity intensity of syndepositional fault controlled the thickness of black shale and the scale of the reef bank. It is suggested carrying out high accuracy seismic exploration to determine the location of Early Cambrian syndepositional faults, on this basis, to search the reef bank of Xiaoerbulake Formation along the faults westward, and then drill risk exploration wells at sites where traps are shallow in buried depth.
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The characteristics and formation of the pre-salt dolomite reservoirs in the fifth member of Ordovician Majiagou Formation in the mid-east Ordos Basin are investigated through observation of cores and thin sections, and geochemical analysis. (1) The pre-salt dolomites can be divided into dolomicrite, grain dolomite and dolarenite, in which the main reservoir space consists of intercrystalline pores and various dissolved pores. (2) The diagenesis in the study area is complex and mainly includes dolomitization, dissolution, filling, and recrystallization. (3) Multi-stages of dolomitization, including penecontemporaneous capillary concentration dolomitization, seepage- reflux dolomitization during penecontemporaneous and shallow burial stage, and burial dolomitization in later stage, are conducive to the preservation of primary pores and development of secondary pores. (4) Multi-stages of dissolution also have strong influence on the development of secondary pores; the secondary transgression and regression cycles during the contemporaneous-penecontemporaneous stage led to exposure and dissolution of soluble minerals and thus the generation of secondary pores. (5) In the burial stage, reservoir pores were further improved due to organic acid dissolution and the dissolution by hydrosulphuric acid from thermochemical sulfate reduction (TSR) and its product H2S. (6) High H2S concentration area in pre-salt reservoirs can thus be considered as targets for future exploration.
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Lower Paleozoic carbonate rocks are an important exploration area in craton area of the Tarim Basin, with the proven oil and gas reserves of more than 2.2×10 8 t, but no large-scale discovery has been made in the Gucheng area so far. The key issues restricting exploration are that the source rock, reservoir scale and law of oil and gas enrichment are unclear. By systematically examining the petroleum geological conditions of Lower Paleozoic carbonate rocks, the following findings are reached: (1) Source rocks of slope-basin facies developed in Cambrian-Lower Ordovician in the Gucheng area. (2) The dolomitized beach in the lower part of Ordovician Yingshan Formation has large-scale reservoirs, good reservoir-cap assemblage and developed gas source faults, and is an important field for increasing reserves and production in the near future; hydrocarbon enrichment is controlled by reservoir and gas source faults, and the central dolomitized beach zone is the main exploration area. (3) The Cambrian platform margin reef beach, large in scale, good in physical properties and close to source rocks, has the possibility to form monolithic gas field; the caprock and preservation conditions are the key factors for hydrocarbon enrichment; the northern part of the phases I and II platform margin reefs has better sealing conditions, and is the main direction of next exploration. (4) Limestone fault solution reservoirs in the upper part of Ordovician Yingshan Formation, controlled by faults and small in scale, but good in reservoir-cap combination, worth exploring. (5) The granular limestone beach of Ordovician Yijianfang Formation is well developed and gas-bearing, but short in exposure dissolution time, and the reservoirs are strongly heterogeneous, and are a potential exploration field.
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The origin of grain dolomite in M5 5 Member of Ordovician Majiagou Formation in northwestern Ordos Basin was studied by geochemical and petrological tests on core samples. Observation of cores, thin sections and casting thin sections, analysis of cathodoluminescence, X-ray diffraction, microscopic sampling of trace elements, laser sampling δ 18O and δ 13C, and fluid inclusion homogenization temperature were conducted. The results show that the dolomite is the product of recrystallization of micritic to crystal powder dolomite rather than the product of dolomitization of grain limestone. In the spherical grains are residual gypsum and halite pseudo crystals identical with those in the host micritic dolomite. The spherical particles of dolomite has similar trace elements and δ 18O and δ 13C characteristics to micritic dolomite. Furthermore, Mn/Sr ratio of the fine-medium dolomite between the dolomite grains is about 5-8, while Mn/Sr ratios of calcite in limestone, micritic dolostone in micritic dolomite, and micritic and powdery dolomite are about 0-2, indicating that the dolomite experienced strong diagenesis. Homogenization temperature of inclusions of fine-medium dolomite is about 148. 19 °C, higher than that of inclusions in micritic to crystal powder dolomite (about 122.60 °C), which also supports the conclusion that the grain dolomite experienced burial diagenesis and negative shift of δ 18O and δ 13C. The δ 18O, δ 13C values of micritic to crystal powder dolomite match with the negative migration, but those of calcite in limestone don’t. It is of great significance to elucidate the genesis of “dolomite recrystallization” for the prediction of such dolomite reservoirs.
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In order to quantify coal pore structure heterogeneity and anisotropy, synchrotron radiation SAXS (Small Angle X-ray Scattering) was applied to obtain the SAXS images of two different rank coal samples. The surface fractal dimension (D1) and pore fractal dimension (D2) were obtained by processing the image data. The pore structure heterogeneity of two coal samples was quantified by pore fractal dimension (D2). Pore fractal dimension of Xinzhouyao coal is 2.74 and pore fractal dimension of Tangshan coal is 1.69. As a result, the pore structure heterogeneity of Xinzhouyao coal is stronger than that of Tangshan coal. 3D pore structure imaging was achieved by synchrotron radiation nano-CT. The selected Region of Interest (ROI) of coal sample was divided into a certain number of subvolumes. Pore structure heterogeneity was quantified by calculating the limit of the relative standard deviation of each subvolume's porosity. The heterogeneity value of Xinzhouyao coal pore structure is 3.21 and the heterogeneity value of Tangshan coal pore structure is 2.71. As a result, the pore structure heterogeneity of Xinzhouyao coal is also stronger than that of Tangshan coal, namely, pore structure heterogeneity from synchrotron radiation SAXS and synchrotron radiation nano-CT is consistent. Considering the corresponding relationship between the pore structure anisotropy and the permeability anisotropy, the quantification of pore structure anisotropy was realized by computing the permeability tensor of pore structure using the Lattice Boltzmann method (LBM), and the pore structure anisotropy was characterized by the eigenvalues and eigenvectors of the permeability tensor. The pore structure anisotropy obtained by the method proposed in this paper was validated by the pore structure geometrical morphology.
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Experiments on surface-active polymer flooding for enhanced oil recovery were carried out by detection analysis and modern physical simulation technique based on reservoirs and fluids in Daqing placanticline oilfield. The experimental results show that the surface-active polymer is different from other common polymers and polymer-surfactant systems in molecular aggregation, viscosity and flow capacity, and it has larger molecular coil size, higher viscosity and viscosifying capacity, and poorer mobility. The surface-active polymer solution has good performance of viscosity-increasing and viscosity retention, and has good performance of viscoelasticity and deformability to exert positive effects of viscosifying and viscoelastic properties. Surface-active polymer can change the chemical property of interface and reduce interfacial tension, making the reservoir rock turn water-wet, also it can emulsify the oil into relatively stable oil-in-water emulsion, and emulsification capacity is an important property to enhance oil washing efficiency under non-ultralow interfacial tension. The surface-active polymer flooding enlarges swept volume in two ways: Microscopically, the surface-active polymer has mobility control effect and can enter oil-bearing pores not swept by water to drive residual oil, and its mobility control effect has more contribution than oil washing capacity in enhancing oil recovery. Macroscopically, it has plugging capacity, and can emulsify and plug the dominant channels in layers with high permeability, forcing the injected fluid to enter the layer with medium or low permeability and low flow resistance, and thus enlarging swept volume.
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The global mobility theory was used to evaluate the experimental results of oil displacement with water of different salinities. The results of scanning electron microscopy, X diffraction of clay minerals, nonlinear seepage and nuclear magnetic resonance experiments and particle migration inhibition experiments before and after water flooding were compared to determine the mechanisms of water sensitive damage and enhanced water flooding mechanism of low permeability sandy conglomerate reservoirs in Wushi region of Beibuwan Basin, China. A production equation of the oil-water two phase flow well considering low-speed non-Darcy seepage and reservoir stress sensitivity was established to evaluate the effect of changes in reservoir properties and oil-water two-phase seepage capacity on reservoir productivity quantitatively, and injection water source suitable for the low permeability sandy conglomerate reservoirs in Wushi region was selected according to dynamic compatibility experimental results of different types of injected water. The seepage capacity of reservoir is the strongest when the injected water is formation water of 2 times salinity. The water-sensitive damage mechanisms of the reservoirs in Wushi region include hydration of clay minerals and particle migration. By increasing the content of cations (especially K+ and Mg2+) in the injected water, the water-sensitive damage of the reservoir can be effectively inhibited. The formation water of Weizhou Formation can be used as the injection water source of low permeability sandy conglomerate reservoirs in the Wushi region.
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Based on systematically summarizing the achievements of previous ion-matched waterflooding researches, the diversity and synergy of oil recovery enhancement mechanisms and the interaction between mechanisms are examined according to two classification standards, and the influence of behaviors of different ions on different mechanisms and oil displacement efficiency are investigated. Ionic strength is proposed to characterize the behavior differences of univalent and divalent ions, the relationships between ionic strength, effective concentration, and mechanisms are established to characterize the ion behavior behind various mechanisms, and evaluate the performance of ion-matched injection water. The mechanisms of enhancing oil recovery by ion-matched waterflooding include: (1) The ion-matched water can reduce the ion strength and match the ion composition of formation water, thereby reducing the difference between the effective concentration of univalent ions and divalent ions on the surface of carbonate rocks, and improving the effective concentration of potential determining ions (especially SO4 2-). (2) It can improve wettability, oil-water interface properties, pore structure and physical properties of the reservoir, and finally enable the establishment of a new ionic equilibrium conducive to waterflooding while breaking the original equilibrium. In this study, experiments such as relative permeability curve, interfacial tension, and core-flooding were carried out on carbonate core samples from the Cretaceous Mishrif Formation reservoirs in Halfaya Oilfield, Middle East, a method for injection water evaluation was established and the injection water suitable for these reservoirs was selected: 6 times diluted seawater. Compared with ordinary seawater, oil displacement efficiency can be increased by more than 4.60% and compared with the optimum dilution of formation water, oil displacement efficiency can be increased by 3.14%.
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To improve the oil recovery and economic efficiency in heavy oil reservoirs in late steam flooding, taking J6 Block of Xinjiang Oilfield as the research object, 3D physical modeling experiments of steam flooding, CO2-foam assisted steam flooding, and CO2 assisted steam flooding under different perforation conditions are conducted, and CO2-assisted steam flooding is proposed for reservoirs in the late stage of steam flooding. The experimental results show that after adjusting the perforation in late steam flooding, the CO2 assisted steam flooding formed a lateral expansion of the steam chamber in the middle and lower parts of the injection well and a development mode for the production of overriding gravity oil drainage in the top chamber of the production well; high temperature water, oil, and CO2 formed stable low-viscosity quasi-single-phase emulsified fluid; and CO2 acted as a thermal insulation in the steam chamber at the top, reduced the steam partial pressure inside the steam chamber, and effectively improved the heat efficiency of injected steam. Based on the three-dimensional physical experiments and the developed situation of the J6 block in Xinjiang Oilfield, the CO2 assisted steam flooding for the J6 block was designed. The application showed that the CO2 assisted steam flooding made the oil vapor ratio increase from 0.12 to 0.16 by 34.0%, the oil recovery increase from 16.1% to 21.5%, and the final oil recovery goes up to 66.5% compared to steam flooding after perforation adjustment.
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Series of experiments were performed to simulate the invasion of formation sand into and the plugging process of gravel-pack at different viscosities and flowing rates of fluid. Two types of formation sands with the medium size of 0.10 mm and 0.16 mm and the quartz sand and ceramsite of 0.6-1.2 mm were used in the experiments. A new viscosity-velocity index (the product of fluid viscosity and velocity) was put forward to characterize the influencing mechanism and law of physical property and flow condition of formation fluid on gravel-pack plugging, and a new method to optimize the production rate of wells controlling sand production with gravel-packing was proposed. The results show that the permeability of formation sand invaded zone and final permeability of plugged gravel-pack have negative correlations with viscosity and flow velocity of fluid, the higher the flow velocity and viscosity, the lower the permeability of formation sand invaded zone and final permeability of plugged gravel-pack will be. The flow velocity and viscosity of fluid are key factors affecting plugging degree of the gravel zone. The viscosity-velocity index (v-v index) can reflect the flow characteristics of fluid very well and make it easier to analyze the plugging mechanism of gravel zone. For different combinations of fluid viscosity and flow velocity, if the v-v index is the same or close, their impact on the final gravel permeability would be the same or close. With the increase of the v-v index, the permeability of plugged gravel zone decreases first, then the reduction rate slows down till the permeability stabilizes. By optimizing production and increasing production step by step, the optimal working scheme for sand-control well can reduce the damage to gravel-pack zone permeability caused by sand-carrying fluid effectively, and increase well productivity and extend the sand control life.
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An innovative perforation method of interlaced fixed perforation was put forward based on the analysis of the characteristics of fractures in various periods of perforation and conventional perforation modes. By conducting a large-scale perforation shooting experiments, we investigated the morphology, propagation mechanism and propagation law of the near-wellbore fractures generated during perforating processes under different fixed angle and interlaced angle combinations, and discussed the control method of near-wellbore fractures in different types of unconventional oil and gas reservoirs. The experimental results show that: (1) The interlaced fixed perforation strengthens the connectivity between the perforation tunnels not only in the same fixed plane but also in adjacent fixed planes, making it likely to form near-wellbore connected fractures which propagate in order. (2) Three kinds of micro-fractures will come up around the perforation tunnel during perforation, namely type I radial micro-fracture, type II oblique micro-fracture and type III divergent micro-fracture at the perforation tip, which are interconnected into complex near-wellbore fracture system. (3) Different types of perforation bullets under different combinations of fixed angles and interlaced angles result in different shapes of near-wellbore fractures propagating in different patterns. (4) By using the interlaced perforation on fixed planes, arranging fixed planes according to the spiral mode or the continuous “zigzag” shape, the desired near-wellbore fractures can be obtained, which is conducive to the manual control of main fractures in the fracturing of unconventional or complex conventional reservoirs.
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It is difficult to define safe drilling mud density window for shale sections. To solve this problem, the general Biot effective stress principle developed by Heidug and Wong was modified. The Weibull statistical model was used to characterize the hydration strain- related strength damage. Considering drilling fluid sealing barrier on shale, a calculation method of safe drilling mud density has been established for shale formation under drilling fluid sealing-inhibition-reverse osmosis effect, combined with a flow-diffusion coupling model. The influence of drilling fluid sealing and inhibiting parameters on safe drilling mud density window was analyzed. The study shows that enhancing drilling fluid sealing performance can reduce the pore pressure transmission and solute diffusion; the inhibiting performance of drilling fluid, especially inhibition to strength damage, is crucial for the wellbore collapse pressure of shale section with significant hydration property. The improvement of drilling fluid sealing and inhibition performance can lower collapse pressure and enhance fracturing pressure, and thus making the safe drilling fluid density window wider and the collapse period of wellbore longer. If there is osmosis flow in shale, induced osmosis flow can make the gap between collapse pressure and fracturing pressure wider, and the stronger the sealing ability of drilling fluid, the wider the gap will be. The safe drilling mud density window calculation method can analyze the relationships between collapse pressure, fracturing pressure and drilling fluid anti collapse performance, and can be used to optimize drilling fluid performance.
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To solve the problems such as high denstiy, foam instability, low compressive strength, high porosity and poor durability associated with conventional foam cements, a novel colloidal gas aphron (CGA) based foam cement system was investigated and tested for properties. CGA is used in a base slurry as the foam component and the recipe was optimized with hollow sphere and micro-silica in terms of particle size distribution (PSD). Porosity, permeability, strength, brittleness, elasticity, free water content, foam stability and density tests on the CGA based foam cement system were carried out to evaluate the performance of the system. According to the experiment results, at the foam proportion of 10%, the cement density was reduced to 1 040 kg/m 3, and stable microfoam net structure not significantly affected by high temperature and high pressure was formed in the cement system. The optimal CGA based foam cement has a free water content of 0%, porosity of 24%, permeability of 0.7×10 -3 μm 2, low elasticity modulus, high Poisson’s ratio, and reasonable compressive strength, and is more elastic and flexible with capability to tolerate regional stresses.
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The kinetic parameters of hydrocarbon generation are determined through experimental simulation and mathematical calculation using four typical samples selected from the Cretaceous Nenjiang Formation in the northwest of Songliao Basin, Chang 7 Member of Triassic Yanchang Formation in the southwest of Ordos Basin, Paleogene in the southwest of Qaidam Basin, and Lucaogou Formation of Jimusar Sag in the east of Junggar Basin. The results show that activation energy of hydrocarbon generation of organic matter is closely related to maturity and mainly ranges between 197 kJ/mol and 227 kJ/mol. On this basis, the temperature required for organic matter in shale to convert into oil was calculated. The ideal heating temperature is between 270 ℃ and 300 ℃, and the conversation rate can reach 90% after 50-300 days of heating at constant temperature. When the temperature rises at a constant rate, the temperature corresponding to the major hydrocarbon generation period ranges from 225 to 350 ℃ at the temperature rise rate of 1-150 ℃/month. In order to obtain higher economic benefits, it is suggested to adopt higher temperature rise rate (60-150 ℃/month). The more reliable kinetic parameters obtained can provide a basis for designing more reasonable scheme of in-situ heating conversion.
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The pore structure and its influence on physical properties and oil saturation of the Triassic Chang 7 sandstones, Ordos Basin were discussed using thin sections, physical properties, oil saturation and mercury intrusion data. The results show that the tight sandstone has a binary pore structure: when the pore throat radius is larger than the peak radius, the pore radius is significantly larger than throat size, the pore structure is similar to the bead-string model with no fractal feature, and the pore throat volume is determined by the pore volume. When the pore throat radius is smaller than the peak radius, the pore structure is close to the capillary model and shows fractal features, the pore size is close to the throat size, and the pore throat volume is determined by the throat radius. The development of pore throats larger than the peak radius provides most of the oil storage space and is the major controlling factor for the porosity and permeability variation of tight sandstone. The pore throat smaller than the peak radius (including throats with no mercury invaded) contributes major reservoir space, it shows limited variation and has little effect on the change of physical properties which is lack of correlation with oil saturation. The pore throat larger than the peak radius is mainly composed of secondary and intergranular pores. Therefore genesis and main controlling factors of large pores such as intergranular and dissolved pores should be emphasized when predicting the tight sandstones quality.
