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Based on analyses of characteristics, hydrocarbon charging history and geological conditions for the formation of Sinian-Cambrian reservoirs in the north slope area of central Sichuan paleo-uplift, the natural gas origin, accumulation evolution, accumulation pattern and formation conditions of large lithologic gas reservoirs have been investigated. Through comprehensive analyses of natural gas composition, carbon and hydrogen isotopic compositions, fluid inclusions, reservoir bitumen, and geological conditions such as lithofacies paleogeography and beach body characterization, it is concluded that: (1) The natural gas in the Sinian-Cambrian of the north slope area is mainly oil cracking gas, and different contribution ratios of multiple sets of source rocks lead to different geochemical characteristics of natural gas in different reservoirs. (2) Although the both Sinian and Cambrian gas reservoirs in this area are lithologic gas reservoirs under monocline background, the former has normal-pressure and the latter has high-pressure. There are three types of source-reservoir-caprock combinations: single source with lower generation and upper reservoir, double sources with lower generation and upper reservoir or with side source and lateral reservoir, double sources with lower generation and upper reservoir or with upper generation and lower reservoir. The Permian-Triassic is the main generation period of oil, Early-Middle Jurassic is the main generation period of oil cracking gas and wet gas, and Late Jurassic-Cretaceous is the main generation period of dry gas. (3) The Sinian-Cambrian system of the north slope area has two favorable conditions for formation of large lithologic gas reservoirs, one is that the large scale beach facies reservoirs are located in the range of ancient oil reservoirs or near the source rocks, which is conducive to the "in-situ" large-scale accumulation of cracked gas in the paleo-oil reservoirs, the other is that the large scale mound-beach complex reservoirs and sealing layers of inter beach tight zones match effectively to form large lithologic traps under the slope background. The research results confirm that the north slope area has large multi-layer lithologic gas reservoirs with more than one trillion cubic meters of natural gas resources and great exploration potential.
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Based on the contemporary strategy of PetroChina and the “Super Basin Thinking” initiative, we analyze the petroleum system, the remaining oil and gas resource distribution, and the Super Basin development scheme in the Sichuan Basin with the aim of unlocking its full resource potential. We conclude that, (1) The three-stage evolution of the Sichuan Basin has resulted in the stereoscopic distribution of hydrocarbon systems dominated by natural gas. The prospecting Nanhua-rift stage gas system is potentially to be found in the ultra-deep part of the basin. The marine-cratonic stage gas system is distributed in the Sinian to Mid-Triassic formations, mainly conventional gas and shale gas resources. The foreland-basin stage tight sand gas and shale oil resources are found in the Upper Triassic-Jurassic formations. Such resource base provides the foundation for the implementation of Super Basin paradigm in the Sichuan Basin. (2) To ensure larger scale hydrocarbon exploration and production, technologies regarding deep to ultra-deep carbonate reservoirs, tight-sand gas, and shale oil are necessarily to be advanced. (3) In order to achieve the full hydrocarbon potential of the Sichuan Basin, pertinent exploration strategies are expected to be proposed with regard to each hydrocarbon system respectively, government and policy supports ought to be strengthened, and new cooperative pattern should be established. Introducing the “Super Basin Thinking” provides references and guidelines for further deployment of hydrocarbon exploration and production in the Sichuan Basin and other developed basins.
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Aiming at the differential distribution of overpressure in vertical and lateral directions in the foreland thrust belt in the southern margin of Junggar Basin, the study on overpressure origin identification and overpressure evolution simulation is carried out. Based on the measured formation pressure, drilling fluid density and well logging data, overpressure origin identification and overpressure evolution simulation techniques are used to analyze the vertical and lateral distribution patterns of overpressure, genetic mechanisms of overpressure in different structural belts and causes of the differential distribution of overpressure, and the controlling effects of overpressure development and evolution on the formation and distribution of oil and gas reservoirs. The research shows that overpressure occurs in multiple formations vertically in the southern Junggar foreland thrust belt, the deeper the formation, the bigger the scale of the overpressure is. Laterally, overpressure is least developed in the mountain front belt, most developed in the fold anticline belt, and relatively developed in the slope belt. The differential distribution of overpressure is mainly controlled by the differences in disequilibrium compaction and tectonic compression strengths of different belts. The vertical overpressure transmission caused by faults connecting the deep overpressured system has an important contribution to the further increase of the overpressure strength in this area. The controlling effect of overpressure development and evolution on hydrocarbon accumulation and distribution shows in the following aspects: When the strong overpressure was formed before reservoir becoming tight overpressure maintains the physical properties of deep reservoirs to some extent, expanding the exploration depth of deep reservoirs; reservoirs below the overpressured mudstone cap rocks of the Paleogene Anjihaihe Formation and Lower Cretaceous Tugulu Group are main sites for oil and gas accumulation; under the background of overall overpressure, both overpressure strength too high or too low are not conducive to hydrocarbon enrichment and preservation, and the pressure coefficient between 1.6 and 2.1 is the best.
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Based on comprehensive analysis of cores, thin sections, logging and seismic data, the sequence stratigraphy and sedimentary evolution of the third and fourth members of Sinian Dengying Formation (Deng 3 and Deng 4 members for short) in the Gaomo area of Sichuan Basin were investigated, and the favorable zones for reservoir development in the Deng 3 Member and Deng 4 Member were predicted. (1) Two Type I and one Type II sequence boundaries are identified in the Deng 3 and Deng 4 members. Based on the identified sequence boundaries, the Deng 3 and Deng 4 members can be divided into two third order sequences SQ3 and SQ4, which are well-developed, isochronal and traceable in this area; the SQ3 thins from west to the east, and the SQ4 thins from northwest to southeast. (2) The sedimentary environment from the depositional period of SQ3 to SQ4 has experienced the evolution from mixed platform to rimmed platform, and the platform rimmed system on the west side is characterized by the development of platform margin microbial mound and grain shoal assemblages. The intraplatform area is a restricted platform facies composed of a variety of dolomites, and there are local micro-geomorphic highlands of different scales and scattered intraplatform mounds and shoals. (3) The Deng 4 Member reservoirs, with obvious facies-controlled characteristic, are mainly distributed in the upper part of high-frequency upward shallow cycle and the high-stand systems tract of the third-order sequence vertically, and are more developed in the platform margin belt than in the intraplatform belt, and more developed in the Gaoshiti platform margin belt than in the west Suining platform margin belt on the plane. (4) Three types of favorable reservoir zones of Deng 4 Member have been finely delineated with 3D seismic data; among them, the mound and shoal facies zones developed in the ancient highlands of the intraplatform are the first choice for the next exploration and development of the Deng 4 Member.
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Based on the latest drilling cores, thin sections, and 3D seismic data, types, features, and evolution processes of Cambrian-Ordovician carbonate platforms in the Gucheng and Xiaotang areas are studied, and favorable exploration zones in this area are also discussed. There are two types of carbonate platforms developed in the Cambrian-Ordovician in the Gucheng-Xiaotang area, namely, carbonate ramp and rimmed platforms, and the evolution process of the platform in the Gucheng area is different from that in Xiaotang area. In the Early Cambrian, the study area was a homoclinal carbonate ramp. During the Middle to Late Cambrian, it evolved into a rimmed platform, with 5 phases of mound shoals developed. In the southern area, mound shoals were in progradational arrangement and the third and fourth stages of mound shoals suffering exposure and further developed abundant karst vugs. In the northern area, the mound shoals appeared in a superposition of aggradation-weak progradation, the third, fourth, and fifth stages of mound shoals suffered exposure and dissolution, and the platform slope developed gravity flow deposits. In the Early to Middle Ordovician, the southern area gradually evolved into a distally steepened carbonate ramp, where retrogradational dolomitic shoal developed; while the northern part experienced an evolution process from a weakly rimmed platform to a distally steepened carbonate ramp, and developed two or three stages of retrogradational mound shoals. The high-frequency oscillation of sea level and local exposure and dissolution were beneficial to the formation of mound or shoal reservoirs in platform margin and ramp, and the configuration of these reservoirs with low energy slope-basin facies source rocks could form good oil-gas enrichment zones. The dolomitic shoal in the Ordovician platform ramp is the practical exploration field for increasing reserve and production in the Gucheng area. The mound shoal at the Cambrian rimmed platform margin is the key exploration object in the Xiaotang area. In addition, the Cambrian slope gravity flow deposits can be taken as the favorable exploration fields in the study area.
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Taking lake basin shales of the Triassic Yanchang Formation in the Ordos Basin, NW China and the Cretaceous Qingshankou Formation in the Songliao Basin, NE China as research objects, the characteristics and origins of different types of silica in the shales have been studied by means of core observation, thin section identification, cathodoluminescence, X-ray diffraction analysis, scanning electron microscope (SEM), electron probe and rock pyrolysis. The results shows that the origins of silica include felsic mineral dissolution, tuffite devitrification, clay mineral transformation and siliceous mineral metasomatism. The silica formed by feldspar dissolution commonly appears as spots and veins, with low degree of crystallization, and is largely aqueous opal mineral, with an average SiO2 content of 67.2%. Silica formed by devitrification of tuffite mainly occurs in two forms, amorphous silica and authigenic quartz with better crystal shape. The authigenic silica formed during the transformation of clay minerals is embedded in the clay minerals in the form of micron-scale plates and small flakes, or mixed with clay minerals in a dispersed state. The authigenic quartz formed by siliceous mineral metasomatism is in better angular crystal shape, and has an average SiO2 content of 87%. The authigenic siliceous mineral content is positively correlated with the content of terrigenous felsic minerals. The pressure solution of felsic minerals is the main source of authigenic siliceous minerals, followed by the transformation of clay minerals, and the organic matter has some boost on the formation of authigenic silica. The authigenic siliceous materials of different origins have different geological characteristics and occurrence states from terrigenous quartz, which would affect the storage performance, seepage capacity and fracturing effect of continental shale. Although the organic-rich shale has high silica content, different from terrigenous quartz, authigenic silica in this kind of shale mostly floats and disperse in clay minerals, which would have negative effect on the formation of complex fractures in fracturing, fracture support ability after fracturing, and formation of effective seepage channels. Calculating the brittleness index of shale intervals only based on the composition of brittle minerals cannot accurately characterize mechanical characteristics of continental shale oil reservoirs, and would affect comprehensive evaluation and selection of continental shale oil “sweet spots”.
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As sandstone layers in thin interbedded section are difficult to identify, conventional model-driven seismic inversion and data-driven seismic prediction methods have low precision in predicting them. To solve this problem, a model-data-driven seismic AVO (amplitude variation with offset) inversion method based on a space-variant objective function has been worked out. In this method, zero delay cross-correlation function and F norm are used to establish objective function. Based on inverse distance weighting theory, change of the objective function is controlled according to the location of the target CDP (common depth point), to change the constraint weights of training samples, initial low-frequency models, and seismic data on the inversion. Hence, the proposed method can get high resolution and high-accuracy velocity and density from inversion of small sample data, and is suitable for identifying thin interbedded sand bodies. Tests with thin interbedded geological models show that the proposed method has high inversion accuracy and resolution for small sample data, and can identify sandstone and mudstone layers of about one-30th of the dominant wavelength thick. Tests on the field data of Lishui sag show that the inversion results of the proposed method have small relative error with well-log data, and can identify thin interbedded sandstone layers of about one-15th of the dominant wavelength thick with small sample data.
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A set of methods for predicting the favorable reservoir of deep shale gas based on machine learning is proposed through research of parameter correlation feature analysis principle, intelligent prediction method based on convolution neural network (CNN), and integrated fusion characterization method based on kernel principal component analysis (KPCA) nonlinear dimension reduction principle. (1) High-dimensional correlation characteristics of core and logging data are analyzed based on the Pearson correlation coefficient. (2) The nonlinear dimension reduction method of KPCA is used to characterize complex high-dimensional data to efficiently and accurately understand the core and logging response laws to favorable reservoirs. (3) CNN and logging data are used to train and verify the model similar to the underground reservoir. (4) CNN and seismic data are used to intelligently predict favorable reservoir parameters such as organic carbon content, gas content, brittleness and in-situ stress to effectively solve the problem of nonlinear and complex feature extraction in reservoir prediction. (5) KPCA is used to eliminate complex redundant information, mine big data characteristics of favorable reservoirs, and integrate and characterize various parameters to comprehensively evaluate reservoirs. This method has been used to predict the spatial distribution of favorable shale reservoirs in the Ordovician Wufeng Formation to the Silurian Longmaxi Formation of the Weirong shale gas field in the Sichuan Basin, SW China. The predicted results are highly consistent with the actual core, logging and productivity data, proving that this method can provide effective support for the exploration and development of deep shale gas.
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The research progress of isotopic fractionation in the process of shale gas/coalbed methane migration has been reviewed from three aspects: characteristics and influencing factors, mechanism and quantitative characterization model, and geological application. It is found that the isotopic fractionation during the complete production of shale gas/coalbed methane shows a four-stage characteristic of “stable-lighter-heavier-lighter again”, which is related to the complex gas migration modes in the pores of shale/coal. The gas migration mechanisms in shale/coal include seepage, diffusion, and adsorption/desorption. Among them, seepage driven by pressure difference does not induce isotopic fractionation, while diffusion and adsorption/desorption lead to significant isotope fractionation. The existing characterization models of isotopic fractionation include diffusion fractionation model, diffusion-adsorption/desorption coupled model, and multi-scale and multi-mechanism coupled model. Results of model calculations show that the isotopic fractionation during natural gas migration is mainly controlled by pore structure, adsorption capacity, and initial/boundary conditions of the reservoir rock. So far, the isotope fractionation model has been successfully used to evaluate critical parameters, such as gas-in-place content and ratio of adsorbed/free gas in shale/coal etc. Furthermore, it has shown promising application potential in production status identification and decline trend prediction of gas well. Future research should focus on: (1) the co-evolution of carbon and hydrogen isotopes of different components during natural gas migration, (2) the characterization of isotopic fractionation during the whole process of gas generation-expulsion-migration-accumulation-dispersion, and (3) quantitative characterization of isotopic fractionation during natural gas migration in complex pore-fracture systems and its application.
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This study combines large volume three-dimensional reconstruction via focused ion beam scanning electron microscopy (FIB-SEM) with conventional scanning electron microscope (SEM) observation, automatic mineral identification and characterization system (AMICS) and large-area splicing of SEM images to characterize and classify the microscopic storage space distribution patterns and 3D pore structures of shales in the second member of the Paleogene Kongdian Formation (Kong 2) in the Cangdong Sag of the Bohai Bay Basin. It is shown that: (1) The Kong 2 Member can be divided into seven types according to the distribution patterns of reservoir spaces: felsic shale with intergranular micron pores, felsic shale with intergranular fissures, felsic shale with intergranular pores, hybrid shale with intergranular pores and fissures, hybrid shale with intergranular pores, clay-bearing dolomitic shale with intergranular pores, and clay-free dolomitic shale with intergranular pores. (2) The reservoir of the intergranular fracture type has better storage capacity than that of intergranular pore type. For reservoirs with storage space of intergranular pore type, the dolomitic shale reservoir has the best storage capacity, the hybrid shale comes second, followed by the felsic shale. (3) The felsic shale with intergranular fissures has the best storage capacity and percolation structure, making it the first target in shale oil exploration. (4) The large volume FIB-SEM 3D reconstruction method is able to characterize a large shale volume while maintaining relatively high spatial resolution, and has been demonstrated an effective method in characterizing the 3D storage space in strongly heterogeneous continental shales.
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This paper analyzes the differences in geological and development characteristics between continental shale oil in China and marine shale oil in North America, reviews the evaluation methods and technological progress of the continental shale oil development in China, and points out the existing problems and development directions of the continental shale oil development. The research progress of development evaluation technologies such as favorable lithofacies identification, reservoir characterization, mobility evaluation, fracability evaluation, productivity evaluation and geological-mathematical modeling integration are introduced. The efficient exploration and development of continental shale oil in China are faced with many problems, such as weak basic theoretical research, imperfect exploration and development technology system, big gap in engineering technology between China and other countries, and high development cost. Three key research issues must be studied in the future: (1) forming differentiated development technologies of continental shale oil through geological and engineering integrated research; (2) strengthening the application of big data and artificial intelligence to improve the accuracy of development evaluation; (3) tackling enhanced shale oil recovery technology and research effective development method, so as to improve the development effect and benefit.
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To get a deeper understanding on the formation mechanisms and distribution laws of remaining oil during water flooding, and enhanced oil recovery (EOR) mechanisms by reversing water injection after water flooding, 3D visualization models of fractured-vuggy reservoir were constructed based on the elements and configuration of fractures and vugs, and typical fracture-vug structures by using advanced CT scanning and 3D printing technologies. Then, water flooding and reversing water injection experiments were conducted. The formation mechanisms of remaining oil during water flooding include inadequate injection-production well control, gravity difference between oil and water, interference between different flow channels, isolation by low connectivity channel, weak hydrodynamic force at the far end. Under the above effects, 7 kinds of remaining oil may come about, imperfect well-control oil, blind side oil, attic oil at the reservoir top, by-pass residual oil under gravity, by-pass residual oil in secondary channel, isolated oil in low connectivity channel, and remaining oil at far and weakly connected end. Some remaining oil can be recovered by reversing water injection after water flooding, but its EOR is related to the remaining oil type, fracture-cavity structure and reversing injection-production structure. Five of the above seven kinds of remaining oil can be produced by six EOR mechanisms of reversing water injection: gravity displacement, opening new flow channel, rising the outflow point, hydrodynamic force enhancement, vertically equilibrium displacement, and synergistic effect of hydrodynamic force and gravity.
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Efficient detection of coalbed methane (CBM) co-production interference is the key to timely adjusting the development plan and improving the co-production efficiency. Based on production data of six typical CBM co-production wells in the Zhijin block of western Guizhou Province, China, the production characteristic curves, including production indication curve, curve of daily water production per unit drawdown of producing fluid level with time, and curve of water production per unit differential pressure with time have been analyzed to explore the response characteristics of co-production interference on the production characteristic curves. Based on the unit water inflow data of pumping test in coal measures, the critical value of in-situ water production of the CBM wells is 2 m3/(d·m). The form and the slope of the initial linear section of the production indication curves have clear responses to the interference, which can be used to discriminate internal water source from external water source based on the critical slope value of 200 m3/MPa in the initial linear section of the production indication curve. The time variation curves of water production per unit differential pressure can be divided into two morphological types: up-concave curve and down-concave curve. The former is represented by producing internal water with average daily gas production greater than 800 m3/d, and the latter produces external water with average daily gas production smaller than 400 m3/d. The method and critical indexes for recognition of CBM co-production interference based on the production characteristic curve are constructed. A template for discriminating interference of CBM co-production was constructed combined with the gas production efficiency analysis, which can provide reference for optimizing co-production engineering design and exploring economic and efficient co-production mode.
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This paper investigates the deposition of asphaltenes in the porous medium of the studied field in Russia and predicts production profiles based on uncertainty evaluation. This problem can be solved by dynamic modeling, during which production profiles are estimated in two scenarios: with and without the activation of the asphaltene option. Calculations are carried out for two development scenarios: field operation under natural depletion and water injection into the aquifer as a reservoir pressure maintenance system. A full-scale compositional reservoir simulation model of the Russian oilfield was created. Within a dynamic simulation, the asphaltene option was activated and the asphaltene behavior in oil and porous medium was tuned according to our own special laboratory experiments. The model was also matched to production historical data, and a pattern model was prepared using the full-scale simulation model. Technological and the asphaltene option parameters were used in sensitivity and an uncertainty evaluation. Furthermore, probable production profiles within a forecast period were estimated. The sensitivity analysis of the pattern model to input parameters of the asphaltene option allowed determining the following heavy-hitters on the objective function: the molar weight of dissolved asphaltenes as a function of pressure, the asphaltene dissociation rate, the asphaltene adsorption coefficient and the critical velocity of oil movement in the reservoir. Under the natural depletion scenario, our simulations show a significant decrease in reservoir pressure and the formation of drawdown cones leading to asphaltene deposition in the bottom-hole area of production wells, decreasing their productivity. Water injection generally allows us to significantly reduce the volume of asphaltene phase transitions and has a positive effect on cumulative oil production. Injecting water into aquifer can keep the formation pressure long above the pressure for asphaltene precipitation, preventing the asphaltene deposition resulted from interaction of oil and water, so this way has higher oil production.
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Since the oil production of single well in water flooding reservoir varies greatly and is hard to predict, an oil production prediction method of single well based on temporal convolutional network (TCN) is proposed and verified. This method is started from data processing, the correspondence between water injectors and oil producers is determined according to the influence radius of the water injectors, the influence degree of a water injector on an oil producer in the month concerned is added as a model feature, and a Random Forest (RF) model is built to fill the dynamic data of water flooding. The single well history is divided into 4 stages according to its water cut, that is, low water cut, middle water cut, high water cut and extra-high water cut stages. In each stage, a TCN based prediction model is established, hyperparameters of the model are optimized by the Sparrow Search Algorithm (SSA). Finally, the models of the 4 stages are integrated into one whole-life model of the well for production prediction. The application of this method in Daqing Oilfield, NE China shows that: (1) Compared with conventional data processing methods, the data obtained by this processing method are more close to the actual production, and the data set obtained is more authentic and complete. (2) The TCN model has higher prediction accuracy than other 11 models such as Long Short Term Memory (LSTM). (3) Compared with the conventional full-life-cycle models, the model of integrated stages can significantly reduce the error of production prediction.
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By combing the characteristics of drilling in Antarctic region, performance requirements on drilling fluid for Antarctic low temperature conditions, and research progress of low temperature drilling fluid, current problems of the drilling fluid have been sorted out, and the development direction of the drilling fluid has been pointed out. Drilling in the Antarctic region mainly includes drilling in snow, ice and subglacial rock formations, and drilling in Antarctic low temperature conditions will face problems in four aspects: (1) low temperature and large temperature changes in the drilling area; (2) likely well leakage and drillstring-sticking in the snow layer, creep in the ice layer, ice chip gathering jamming in the warm ice layer, well wall collapse in the subglacial rock formations; (3) lack of infrastructure and difficulty in logistical support; (4) fragile environment and low carrying capacity. After years of development, progresses have been made on low-temperature drilling fluids for the Antarctic region. Low-temperature petroleum-based drilling fluid, ethanol/ethylene glycol-based drilling fluid, ester-based drilling fluid and silicone oil-based drilling fluid have been developed. However, these drilling fluids have problems such as insufficient low-temperature tolerance, low environmental performance and weak wellbore stability, etc. In order to meet the performance requirements of drilling fluid under low-temperature conditions in Antarctic region, the working mechanisms of low-temperature drilling fluid must be examined in depth; environment-friendly low-temperature base fluid of drilling fluid and related additives must be developed to prepare environmentally friendly low temperature drilling fluid systems; multi-functional integrated adjustment method for drilling fluid must be worked out to ensure well wall stability and improve cutting-carry capacity when drilling ice formations and ice-rock interlayers; and on-site support operation codes must be established to provide technical support for Antarctic drilling.
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Based on analysis of the reasons for low efficiency and low production after fracturing of some wells in the ultra-deep fractured tight reservoirs of the Kuqa piedmont zone, Tarim Basin and the matching relationship between the in-situ stress field and natural fractures, technological methods for creating complex fracture networks are proposed. Through theoretical study and large-scale physical simulation experiments, the mechanical conditions for forming complex fracture network in the Kuqa piedmont ultra-deep reservoirs are determined. The effectiveness of temporary plugging and diversion, and multi-stage fracturing to activate natural fractures and consequently realize multi-stage diversion is verified. The coupling effect of hydraulic fractures and natural fractures activating each other and resulting in "fracture swarms" is observed. These insights provide theoretical support for improving fracture-controlled stimulated reservoir volume (FSRV) in ultra-deep tight reservoirs. In addition, following the concept of volume fracturing technology and based on the results of fracture conductivity experiments of different processes, fracturing technologies such as multi-stage fracture-network acid fracturing, "multi-stage temporary plugging + secondary fracturing", fracturing of multiple small layers by vertically softness-and-hardness-oriented subdivision, and weighted-fluid refracturing are proposed to increase the FSRV. New environment-friendly weighted-fluid with low cost and new fracturing fluid system with low viscosity and high proppant-carrying capacity are also developed. These techniques have achieved remarkable results in field application.
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Small-scale true triaxial sand fracturing experiments are conducted on thin interbedded shale samples made from cores of Permian Lucaogou Formation shale oil reservoir in Jimsar sag, Junggar Basin, NW China. Combined with high-precision CT scanning digital core model reconstruction technology, hydraulic fracture geometry and proppant distribution in thin interbedded shale oil reservoirs are studied. The research shows that: In thin interbedded shale oil reservoir, the interlayer difference of rock mechanics and the interlayer interface near the wellbore cannot restrain the growth of fracture height effectively, but has a significant impact on the fracture width distribution in the fracture height direction. Hydraulic fractures in these reservoirs tend to penetrate into the adjacent layer in “step-like” form, but have a smaller width at the interface deflection, which hinders the transport of proppant in vertical direction, resulting in a poor effect of layer-crossing growth. In shale layers with dense laminae, hydraulic fractures tend to form “丰” or “井” shapes. If the perforated interval is large in rock strength and high in breakdown pressure, the main fracture is fully developed initially, large in width, and supported by enough sand. In contrast, if the perforated interval is low in strength and rich in laminae, the fracturing fluid filtration loss is large, the breakdown pressure is low, the main fracture will not open wide initially, and likely to have sand plugging. Proppant is mainly concentrated in the main hydraulic fractures with large width near the perforated layer, activated laminae, branch fractures and fractures in adjacent layers contain only a small amount of (or zero) proppant. The proppant is placed in a limited range on the whole. The limit width of fracture that proppant can enter is about 2.7 times the proppant particle size.
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The global exploration investment, new oil and gas discoveries, exploration business adjustment strategies of oil companies in 2021, and future favorable exploration domains are systematically analyzed using commercial databases such as IHS and public information of oil companies. It has been found that the world oil and gas exploration situation in 2021 has continued the downturn since the outbreak of COVID-19. The investment and drilling workload decreased slightly, but the success rate of exploration wells, especially deepwater exploration wells, increased significantly, and the newly discovered reserves increased slightly compared with last year. Deep waters of the passive continental margin basins are still the leading sites for discovering conventional large and medium-sized oil and gas fields. The conventional oil and gas exploration in deep formations of onshore petroliferous basins has been keeping a good state, with tight/shale oil and gas discoveries made in Saudi Arabia, Russia, and other countries. While strengthening the exploration and development of local resources, national, international, and independent oil companies have been focusing on major overseas frontiers using their advantages, including risk exploration in deep waters and natural gas. Future favorable exploration directions in the three major frontiers, the global deep waters, deep onshore formations, and unconventional resources, have been clarified. Four suggestions are put forward for the global exploration business of Chinese oil companies: first, a farm in global deepwater frontier basins in advance through bidding at a low cost and adopt the “dual exploration model” after making large-scale discoveries; second, enter new blocks of emerging hot basins in the world through farm-in and other ways, to find large oil and gas fields quickly; third, cooperate with national oil companies of the resource host countries in the form of joint research and actively participate exploration of deep onshore formations of petroliferous basins; fourth, track tight/shale oil and gas cooperation opportunities in a few countries such as Saudi Arabia and Russia, and take advantage of mature domestic theories and technologies to farm in at an appropriate time.
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By analyzing the distribution of global oil and gas fields and the reasons why some oil and gas fields are not in production, the distribution characteristics of oil and gas remaining recoverable reserves and their year-on-year changes, the distribution characteristics of oil and gas production and their year-on-year changes, and the development potential of oil and gas to be tapped in 2021, this paper sorts out systematically the current status and characteristics of global oil and gas development, summaries the major trends of global oil and gas development, puts forward enlightenment for international oil and gas cooperation. In 2021, oil and gas fields were widely distributed, the number of non-producing oil and gas fields was large; the whole oil and gas remaining recoverable reserves declined slightly, unconventional oil and gas remaining recoverable reserves dropped significantly; the overall oil and gas production continuously increased, the outputs of key resource-host countries kept year-on-year growth; undeveloped oilfields had abundant reserves and great development potential. Combined with global oil and gas geopolitics, oil and gas industry development trends, oil and gas investment intensity, and the tracking and judgment of hotspot fields, the major trends of global oil and gas development in 2021 are summarized. On this basis, the four aspects of enlightenment and suggestions for international oil and gas cooperation and development strategies are put forward: attach great importance to the obligation of marine abandonment to ensure high-quality and long-term benefit development of offshore oil and gas; adhere to the principle of not going to dangerous and chaotic places, strengthen the concentration of oil and gas assets, and establish multi stable supply bases; based on the multi-scenario demand of natural gas, realize the transformation from integrated collaboration to full oil and gas industry chain development; increase the acquisition of high-quality large-scale assets, and pay attention to the continuous optimization of the shareholding ratio of projects at different stages.
