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Geological conditions and main controlling factors of gas accumulation in subsalt Ma 4 Member of Ordovician Majiagou Formation are examined based on large amounts of drilling, logging and seismic data. The new understandings on the control of paleo-uplift over facies, reservoirs and accumulations are reached: (1) During the sedimentary period of Majiagou Formation, the central paleo-uplift divided the North China Sea in central-eastern of the basin from the Qinqi Sea at southwest margin of the basin, and controlled the deposition of the thick hummocky grain beach facies dolomite on platform margin of Ma 4 Member. Under the influence of the evolution of the central paleo-uplift, the frame of two uplifts alternate with two sags was formed in the central-eastern part of the basin, dolomite of inner-platform beach facies developed in the underwater low-uplift zones, and marl developed in the low-lying areas between uplifts. (2) From the central paleo-uplift to the east margin of the basin, the dolomite in the Ma 4 Member gradually becomes thinner and turns into limestone. The lateral sealing of the limestone sedimentary facies transition zone gives rise to a large dolomite lithological trap. (3) During the late Caledonian, the basin was uplifted as a whole, and the central paleo-uplift was exposed and denuded to various degrees; high-quality Upper Paleozoic Carboniferous-Permian coal measures source rocks deposited on the paleo-uplift in an area of 60 000 km2, providing large-scale hydrocarbon for the dolomite lithological traps in the underlying Ma 4 Member. (4) During the Indosinian-Yanshanian stage, the basin tilted westwards, and central paleo-uplift depressed into an efficient hydrocarbon supply window. The gas from the Upper Paleozoic source rock migrated through the high porosity and permeability dolomite in the central paleo-uplift to and accumulated in the updip high part; meanwhile, the subsalt marine source rock supplied gas through the Caledonian faults and micro-fractures as a significant supplementary. Under the guidance of the above new understandings, two favorable exploration areas in the Ma 4 Member in the central-eastern basin were sorted out. Two risk exploration wells were deployed, both revealed thick gas-bearing layer in Ma 4 Member, and one of them tapped high production gas flow. The study has brought historic breakthrough in the gas exploration of subsalt Ma 4 Member of Ordovician, and opened up a new frontier of gas exploration in the Ordos Basin.
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Distribution characteristics, organic matter development characteristics, gas-bearing characteristics, reservoir characteristics and preservation conditions of the Shahezi Formation shale of Lower Cretaceous in the Lishu fault depression, Songliao Basin are analyzed using organic geochemical, whole rock, and SEM analysis data, and CO2 and N2 adsorption and high pressure mercury injection experiment data in combination with the tectonic and sedimentation evolution of the region to reveal the geological conditions for enrichment and resource potential of continental shale gas. The organic-rich shale in the Lower Cretaceous of the Lishu fault depression is mainly developed in the lower sub-member of the second member of Shahezi Formation (K1sh21), and is thick and stable in distribution. The shale has high TOC, mainly types II1 and II2 organic matter, and is in mature to over mature stage. The volcanic activity, salinization and reduction water environment are conducive to formation of the organic-rich shale. The shale reservoirs have mainly clay mineral intergranular pores, organic matter pores, carbonate mineral dissolution pores and foliated microfractures as storage space. The pores are in the mesopore range of 10-50 nm, and the microfractures are mostly 5-10 μm wide. Massive argillaceous rocks of lowland and highstand domains are deposited above and below the gas-bearing shale separately in the lower sub-member of the K1sh21 Fm., act as the natural roof and floor in the process of shale gas accumulation and preservation, and control the shale gas enrichment. Based on the above understandings, the first shale gas exploration well in Shahezi Formation was drilled in the Lishu fault depression of Songliao Basin. After fracturing, the well tested a daily gas production of 7.6×104 m3, marking a breakthrough in continental shale gas exploration in Shahezi Formation of Lishu fault depression in Songliao Basin. The exploration practice has reference significance for the exploration of continental shale gas in Lower Cretaceous of Songliao Basin and its periphery.
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Temperature-triaxial permeability testing at the axial pressure of 8 MPa and confining pressure of 10 MPa, closed shale system pyrolysis experiment by electrical heating and scanning electron microscopy analysis are used to study the evolution mechanism of in-situ permeability in the direction parallel to bedding of low mature shale from Member 2 (K2n2) of Cretaceous Nenjiang Formation in northern Songliao Basin with mainly Type I kerogen under the effect of temperature. With the increasing temperature, the in-situ permeability presents a peak-valley-peak tendency. The lowest value of in-situ permeability occurs at 375 ℃. Under the same temperature, the in-situ permeability decreases with the increase of pore pressure. The in-situ permeability evolution of low mature shale can be divided into 5 stages: (1) From 25 ℃ to 300 ℃, thermal cracking and dehydration of clay minerals improve the permeability. However, the value of permeability is less than 0.01×10-3 μm2; (2) From 300 ℃ to 350 ℃, organic matter pyrolysis and hydrocarbon expulsion result in mineral intergranular pores and micron pore-fractures, these pores and fractures form an interconnected pore network at limited scale, improving the permeability. But the liquid hydrocarbon, with high content of viscous asphaltene, is more difficult to move under stress and more likely to retain in pores, causing slow rise of the permeability. (3) From 350 ℃ to 375 ℃, pores are formed by organic matter pyrolysis, but the adsorption swelling of liquid hydrocarbon and additional expansion thermal stress constrained by surrounding stress compress the pore-fracture space, making liquid hydrocarbon difficult to expel and permeability reduce rapidly. (4) From 375 ℃ to 450 ℃, the interconnected pore network between different mineral particles after organic matter conversion, enlarged pores and transformation of clay minerals promote the permeability to increase constantly even under stress constraints. (5) From 450 ℃ to 500 ℃, the stable pore system and crossed fracture system in different bedding directions significantly enhance the permeability. The organic matter pyrolysis, pore-fracture structure and surrounding stress in the different stages are the key factors affecting the evolution of in-situ permeability.
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By examining structures, sediments, reservoirs and accumulation assemblages in the Deyang-Anyue rift and its surrounding area, four new understandings are obtained. First, during the initiation period of Deyang-Anyue rift, multiple groups of faults developed in the rift due to the effect of tensile force, bringing about multiple mound and shoal belts controlled by horsts in the second member of Dengying Formation; in the development stage of the rift, the boundary faults of the rift controlled the development of mound and shoal belts at the platform margin in the fourth member of Dengying Formation; during the shrinkage period of the rift, platform margin grain shoals of Canglangpu Formation developed in the rift margin. Second, four sets of large-scale mound and shoal reservoirs in the second member of Dengying Formation, the fourth member of Dengying Formation, Canglangpu Formation and Longwangmiao Formation overlap with several sets of source rocks such as Qiongzhusi Formation source rocks and Dengying Formation argillaceous limestone or dolomite developed inside and outside the rift, forming good source-reservoir-cap rock combinations; the sealing of tight rock layers in the lateral and updip direction results in the formation model of large lithologic gas reservoirs of oil pool before gas, continuous charging and independent preservation of each gas reservoir. Third, six favorable exploration zones of large-scale lithologic gas reservoirs have been sorted out through comprehensive evaluation, namely, mound and shoal complex controlled by horsts in the northern part of the rift in the second member of Dengying Formation, isolated karst mound and shoal complex of the fourth member of Dengying Formation in the south of the rift, the superimposed area of multi-stage platform margin mounds and shoals of the second and fourth members of Dengying Formation and Canglangpu Formation in the north slope area, the platform margin mounds and shoals of the second and fourth members of Dengying Formation in the west side of the rift, the platform margin mound and shoal bodies of the fourth member of Dengying Formation in the south slope area, etc. Fourth, Well Pengtan-1 drilled on the mound and shoal complex controlled by horsts of the second member of Dengying Formation in the rift and Well Jiaotan-1 drilled on the platform margin mound and shoal complex of the North Slope have obtained high-yield gas flows in multiple target layers, marking the discovery of a new gas province with reserves of (2-3)×1012 m3. This has proved the huge exploration potential of large lithologic gas reservoir group related to intracratonic rift.
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By integrating surface geology, seismic data, resistivity profiles, and drilling data, the structural deformation characteristics of the frontier fault of thrust nappes were delineated in detail. The frontier fault of thrust nappes in northwest Scihuan Basin is a buried thrust fault with partial exposure in the Xiangshuichang-Jiangyou area, forming fault propagation folds in the hanging-wall and without presenting large-scale basin-ward displacement along the gypsum-salt layer of the Jialingjiang Formation to the Leikoupo Formation. The southwestern portion of the frontier fault of thrust nappes (southwest of Houba) forms fault bend folds with multiple ramps and flats, giving rise to the Zhongba anticline due to hanging-wall slip along the upper flat of the Jialingjiang Formation. In contrast, the northeastern portion of the frontier fault of thrust nappes (northeast of Houba) presents upward steepening geometry, leading to surface exposure of Cambrian in its hanging-wall. With the frontier fault of thrust nappes as the boundary between the Longmenshan Mountain and the Sichuan Basin, the imbricated structural belt in the hanging-wall thrusted strongly in the Indosinian orogeny and was reactivated in the Himalayan orogeny, while the piedmont buried structural belt in the footwall was formed in the Himalayan orogeny. In the footwall of the frontier fault of thrust nappes, the piedmont buried structural belt has good configuration of source rocks, reservoir rocks and cap rocks, presenting good potential to form large gas reservoirs. In comparison, the hanging-wall of the frontier fault of thrust nappes north of Chonghua has poor condition of oil/gas preservation due to the surface exposure of Triassic and deeper strata, while the fault blocks in the hanging-wall from Chonghua to Wudu, with Jurassic cover and thicker gypsum-salt layer of the Jialingjiang formation, has relative better oil/gas preservation conditions and thus potential of oil/gas accumulation. The frontier fault of thrust nappes is not only the boundary between the Longmenshan Mountain and the Sichuan Basin, but also the boundary of the oil/gas accumulation system in northwestern Sichuan Basin.
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The mechanisms causing quality variations and key control factors of submarine-fan reservoirs in the gas field X of the Rovuma Basin, East Africa are analyzed based on core and well-log data in this paper. Depositional fabric, lithofacies difference and characteristics of genetic units are the fundamental reasons of reservoir quality variations. In the case of weak cementation, porosity and permeability of submarine-fan reservoirs are controlled by grain sorting and clay content, respectively. Reservoir quality variations for 5 main lithofacies are related to variable depositional fabrics and calcite cementation. Among them, massive medium-coarse sandstones with weak cementation have the highest porosity and permeability, and coarser or finer sandstones have poorer reservoir quality. The existence of bottom current can develop laminated sandstones, improving the pore structure and physical properties greatly. Lithofacies vary among different types, locations and stages of genetic units, and they control the distribution patterns of submarine-fan reservoir quality: the physical properties of channel shaft or lobe main body are better than those of the channel or lobe edge. The sandstone sorting and physical properties are gradually improved from near-source to far-source. When multi-stage sand bodies are superimposed, the sand-mud ratio in the later stage is higher than that in the earlier stage, making the physical properties get better in the later stage.
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Based on the logging knowledge graph of hydrocarbon-bearing formation (HBF), a Knowledge-Powered Neural Network Formation Evaluation model (KPNFE) has been proposed. It has the following functions: (1) extracting characteristic parameters describing HBF in multiple dimensions and multiple scales; (2) showing the characteristic parameter-related entities, relationships, and attributes as vectors via graph embedding technique; (3) intelligently identifying HBF; (4) seamlessly integrating expertise into the intelligent computing to establish the appraising system and ranking algorithm for potential reservoir recommendation. Taking 547 wells encountered the lower porosity and lower permeability Chang 6 Member in Jiyuan Block of Ordos Basin as objects, 80% of the wells were randomly selected as the training dataset and the remainder as the validation dataset. The KPNFE prediction results on the validation dataset had a coincidence rate of 94.43% with the expert interpretations and a coincidence rate of 84.38% for all the tested layers, which is 13 percentage points higher in accuracy and over 100 times faster than the primary conventional interpretation. In addition, a number of potential reservoirs likely to produce industrial oil were recommended. The KPNFE model effectively inherits, carries forward and improves the expert knowledge, nicely solving the robustness problem in HBF identification. The KPNFE, with good interpretability and high accuracy of computation results, is a powerful technical means for efficient and high-quality well logging re-evaluation of old wells in mature oilfields.
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Reflected wave seismology has the following defects: the acquisition design is based on the assumption of layered media, the signal processing suppresses weak signals such as diffracted wave and scattered wave, and the seismic wave band after the image processing is narrow. They limit the full utilization of broadband raw data. The concept of full wave seismic exploration is redefined based on the idea of balanced utilization of reflected wave, diffracted wave and scattered wave information, its characteristics and adaptive conditions are clarified. A set of key technologies suitable for full wave seismic exploration are put forward. During seismic acquisition period, it is necessary to adopt multi geometry, i.e. embed small bin, small offset and small channel interval data in conventional geometry. By discretizing of common midpoint (CMP) gathers, small offset with high coverage, the weak signals such as diffracted wave and scattered wave in the raw seismic data can be enhanced. During seismic processing, the signal and noise in the original seismic data need to be redefined at first. The effective signals of seismic data are enhanced through merging of multi-geometry data merging. By means of differential application of data with different bin sizes and different arrangement modes, different regimes of seismic waves can be effectively decomposed and imaged separately. During seismic interpretation stage, making the most of the full wave seismic data, and adopting well-seismic calibration on multi-scale and multi-dimension, the seismic attributes in multi-regimes and multi-domains are interpreted to reveal interior information of complex lithology bodies and improve the lateral resolution of non-layered reservoirs.
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Key parameters and evaluation methods of shale gas show that it is not possible to guarantee the commercial and economic development of shale gas by sorting out geological sweet spots only according to technical indicators. A research method combining technical indicators including total organic carbon content and vitrinite reflectance with economic indicators including internal rate of return and investment payback period is proposed to screen the best technological and economic development sweet spots in undeveloped areas. This method was used to evaluate the best technological and economic development sweet spots in Cretaceous shale gas reservoirs S1 and S2 of Luresan area, Iran. First, 21 geologic sweet spots were picked out based on effective reservoir thickness, vitrinite reflectance and gas content. Then, based on analogy method, the pressure gradient, clay mineral content, buried depth and other parameters were taken as comparative indicators, the Eagle Ford shale as comparison object, recovery factor and production curve were extracted to estimate the technologically recoverable reserves of the study area. On this basis, the economic indexes such as internal rate of return and investment payback period were used to evaluate the economy of the geological sweet spots. In the case of P10 distribution, the total technologically recoverable reserves and economically recoverable reserves are 7875×108 m3 and 4306×108 m3 respectively, 11 geological sweet spots have commercial development value, among which, No. 1 sweet spot has the highest value, with a net present value of 35×108 USD.
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A novel type curve is presented for oil recovery factor prediction suitable for gas flooding by innovatively introducing the equivalent water-gas cut to replace the water cut, comprehensively considering the impact of three-phase flow (oil, gas, water), and deriving the theoretical equations of gas flooding type curve based on Tong’s type curve. The equivalent water-gas cut is the ratio of the cumulative underground volume of gas and water production to the total underground volume of produced fluids. Field production data and the numerical simulation results are used to demonstrate the feasibility of the new type curve and verify the accuracy of the prediction results with field cases. The new type curve is suitable for oil recovery factor prediction of both water flooding and gas flooding. When a reservoir has no gas injected or produced, the gas phase can be ignored and only the oil and water phases need to be considered, in this case, this gas flooding type curve returns to the Tong’s type curve, which can evaluate the oil recovery factor of water flooding. For reservoirs with equivalent water-gas cuts of 60%-80%, the regression method of the new type curve works well in predicting the oil recovery factor. For reservoirs with equivalent water-gas cuts higher than 80%, both the regression and assignment methods of the new type curve can accurately predict the oil recovery factor of gas flooding.
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Low-speed flow experiments in which ultra-fine copper tubes are used to simulate micro-fractures in carbonate strata are conducted to analyze the variations of gas flow state in fractures of different fracture heights, determine flow state transition limit and transition interval, and establish the calculation method of flow state transition limit. The results show that the ideal Hagen-Poiseuille flow is the main form of gas flow in large fractures. Due to the decrease of fracture height, the gas flow in the fracture changes from Hagen-Poiseuille flow with ideal smooth seam surface to non-Hagen-Poiseuille flow, and the critical point of the transition is the boundary of flow state transition. After the fracture height continues to decrease to a certain extent below the boundary of the flow state transition fracture height, the form of gas flow gradually changes to the ideal Darcy flow, thus the transition interval of the gas flow state in the closing process of fracture can be determined. Based on the three-dimensional microconvex body scanning of the fracture surface, the material properties of fracture and properties of fluid in the fracture, a method for calculating the boundary of flow state transition is established. The experimental test and theoretical calculation show that the limit of the fracture height for the transition from pipe flow to Darcy flow is about twice the sum of the maximum height of the microconvex bodies on the upper and lower sides of the fracture.
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Based on the oil, gas and water distribution characteristics of Khasib reservoir in Halfaya oilfield, Iraq, a core displacement experiment is designed to evaluate the influence of different displacement methods and displacement parameters on oil displacement efficiency. The research shows that, in the displacement method with water injected from the edge of the reservoir, early depletion production is conducive to the elastic expansion of the gas cap, forming the three-dimensional displacement of "upper pressure and lower pushing", and the oil displacement effect is good. When gas injection at the top and water injection at the edge are used for synergistic displacement, the injection timing has different influences on the oil displacement effects of high and low parts. Considering the overall oil displacement efficiency, the injection pressure should be greater than the bubble point pressure of crude oil. Two displacement methods are recommended with the reasonable injection time at 20-25 MPa. The injection speed has the same influence on different injection media. Appropriately reducing the injection speed is conducive to the stability of the displacement front, delaying the breakthrough of injection media and improving the oil displacement effect. The reasonable injection rate of water flooding is 0.075 mL/min, the reasonable injection rates of water and gas are 0.15 mL/min and 0.10 mL/min, respectively in gas-water synergistic displacement. Gas-water synergistic displacement is conducive to the production of crude oil at high position, and has crude oil recovery 5.0%-14.8% higher than water flooding from the edge, so it is recommended as the development mode of Khasib reservoir at the middle and late stages.
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The parameters such as pore size distribution, specific surface area and pore volume of shale rock samples are analyzed by low-temperature nitrogen adsorption experiment, and then the conversion coefficient between relaxation time (T2) and pore size is calibrated. Nuclear magnetic resonance experiments of CO2 huff and puff in shale samples are carried out to study the effects of gas injection pressure, soaking time and fractures on the oil production characteristics of shale pores from the micro scale. The the recovery degrees of small pores (less than or equal to 50 nm) and large pores (greater than 50 nm) are quantitatively evaluated. The experimental results show that the recovery degree of crude oil in large pores increases rapidly with the increase of injection pressure under non-miscible conditions, and the effect of injection pressure rise on recovery degree of large pores decreases under miscible conditions; whether miscible or not, the recovery degree of crude oil in small pores basically maintains a linear increase with the increase of injection pressure, and the lower size limit of pores in which oil can be recovered by CO2 decreases with the increase of gas injection pressure; with the increase of soaking time, the recovery degree of crude oil in large pores increases slowly gradually, while the recovery degree of crude oil in small pores increases faster first and then decelerates, and the best soaking time in the experiments is about 10 h; the existence of fractures can enhance the recovery degrees of crude oil in small pores and large pores noticeably.
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This paper summarizes the important progress in the field of oil and gas production engineering during the "Thirteenth Five-Year Plan" period, analyzes the challenges faced by the current oil and gas production engineering in terms of technological adaptability, digital construction, energy-saving and emission reduction, and points out the future development direction. During the "Thirteenth Five-Year Plan" period, major progress has been made in five major technologies, separated-layer injection, artificial lift, reservoir stimulation, gas well de-watering, and workover, which provide key technical support for continuous potential tapping of mature oilfields and profitable production of new oilfields. Under the current complex international political and economic situation, oil and gas production engineering is facing severe challenges in three aspects: technical difficulty increase in oil and gas production, insignificant improvements in digital transformation, and lack of core technical support for energy-saving and emission reduction. This paper establishes three major strategic directions and implementation paths, including oil stabilization and gas enhancement, digital transformation, and green and low-carbon development. Five key research areas are listed including fine separated-layer injection, high efficiency artificial lift, fine reservoir stimulation, long term gas well de-watering and intelligent workover, so as to provide engineering technical support for the transformation, upgrading and high-quality development of China's oil and gas industry.
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By reviewing the current status of drilling fluid technologies with primary intelligence features at home and abroad, the development background and intelligent response mechanisms of drilling fluid technologies such as variable density, salt response, reversible emulsification, constant rheology, shape memory loss prevention and plugging, intelligent reservoir protection and in-situ rheology control are elaborated, current issues and future challenges are analyzed, and it is pointed out that intelligent material science, nanoscience and artificial intelligence theory are important methods for future research of intelligent drilling fluid technology of horizontal wells with more advanced intelligent features of "self-identification, self-tuning and self-adaptation". Based on the aforementioned outline and integrated with the demands from the drilling fluid technology and intelligent drilling fluid theory, three development suggestions are put forward: (1) research and develop intelligent drilling fluids responding to variable formation pressure, variable formation lithology and fluid, variable reservoir characteristics, high temperature formation and complex ground environmental protection needs; (2) establish an expert system for intelligent drilling fluid design and management; and (3) establish a real-time intelligent check and maintenance processing network.
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A multi-process (fracturing, shut-in and production) multi-phase flow model was derived considering the osmotic pressure, membrane effect, elastic energy and capillary force, to determine the optimal shut-in time after multi-cluster staged hydraulic fracturing in shale reservoirs for the maximum production. The accuracy of the model was verified by using production data and commercial software. Based on this model and method, a physical model was made based on the inversion of fracture parameters from fracturing pressure data, to simulate the dynamic changes of pore pressure and oil saturation during fracturing, soaking and production, examine effects of 7 factors on the optimal shut-in time, and find out the main factors affecting the optimal shut-in time through orthogonal experiments. With the increase of shut-in time, the increment of cumulative production increases rapidly first and then tended to a stable value, and the shut-in time corresponding to the inflection point of the change was the optimal shut-in time. The optimal shut-in time has a nonlinear negative correlation with matrix permeability, porosity, capillary pressure multiple and fracture length, a nonlinear positive correlation with the membrane efficiency and total volume of injected fluid, and a nearly linear positive correlation with displacement. The seven factors in descending order of influence degree on optimal shut-in time are total volume of injected fluid, capillary force multiple, matrix permeability, porosity, membrane efficiency, salinity of fracturing fluid, fracturing fluid displacement.
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As formation mechanisms of plugging zone and criteria for fracture plugging remain unclear, plugging experiments and methods testing granular material mechanical properties are used to study the formation process of the plugging zone in fractured formations, analyze composition and ratios of different sizes of particles in the plugging zone, and reveal the essence and driving energy of the formation and damage of the plugging zone. New criteria for selecting lost circulation materials are proposed. The research results show that the formation of the plugging zone has undergone a process from inertial flow, elastic flow, to quasi-static flow. The plugging zone is composed of fracture mouth plugging particles, bridging particles and filling particles, and the proportion of the three types of particles is an important basis for designing drilling fluid loss control formula. The essence of the construction of the plugging zone is non-equilibrium Jamming phase transition. The response of the plugging zone particle system to pressure is driven by entropy force; the greater the entropy, the more stable the plugging zone. Lost circulation control formula optimized according to the new criteria has better plugging effect than the formula made according to conventional plugging rules and effectively improves the pressure-bearing capacity of the plugging zone. The research results provide a theoretical and technical basis for the lost circulation control of fractured formations.
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Aiming at the simulation of multi-phase flow in the wellbore during the processes of gas kick and well killing of complex-structure wells (e.g., directional wells, extended reach wells, etc.), a database including 3561 groups of experimental data from 32 different data sources is established. Considering the effects of fluid viscosity, pipe size, interfacial tension, fluid density, pipe inclination and other factors on multi-phase flow parameters, a new gas-liquid two-phase drift flow relation suitable for the full flow pattern and full dip range is established. The distribution coefficient and gas drift velocity models with a pipe inclination range of -90°-90° are established by means of theoretical analysis and data-driven. Compared with three existing models, the proposed models have the highest prediction accuracy and most stable performance. Using a well killing case with the backpressure method in the field, the applicability of the proposed model under the flow conditions with a pipe inclination range of -90°-80° is verified. The errors of the calculated shut in casing pressure, initial back casing pressure, casing pressure when adjusting the displacement are 2.58%, 3.43%, 5.35%, respectively. The calculated results of the model are in good agreement with the field backpressure data.
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As the main factors affecting stable and high production and the production regularity of lacustrine shale oil are unclear, the theoretical understandings, key exploration and development technologies, development effect and production regularity of lacustrine shale oil have been analyzed and summarized based on 700 m cores taken systematically from Paleogene Kong 2 Member of 4 wells in Cangdong sag, over 100 000 analysis data and formation testing data. Three theoretical understandings on shale oil enrichment and high production have been reached: (1) High-quality shale with “three highs and one low” is the material base for shale oil enrichment. (2) Medium-slightly high thermal evolution degree is the favorable condition for shale oil enrichment. (3) Laminar felsic shale is the optimal shale layer for oil enrichment in semi-deep lake facies. Key exploration and development technologies such as shale oil enrichment layer and area evaluation and prediction, horizontal well pattern layout, shale oil reservoir fracturing, optimization of shale oil production regime have been established to support high and stable shale oil production. Under the guidance of these theoretical understandings and technologies, shale oil in Cangdong sag has achieved high and stable production, and 4 of them had the highest production of over 100 tons a day during formation testing. In particular, Well GY5-1-1L had a daily oil production of 208 m3. By April, 2022, the 28 wells combined have a stable oil production of 300-350 tons a day, and have produced 17.8×104 t of oil cumulatively. It is found that the shale oil production of horizontal well declines exponentially in natural flow stage, and declines in step pattern and then tends stable in the artificial lift stage. Proportion of light hydrocarbons in produced shale oil is in positive correlation with daily oil production and decreases regularly during production test.
