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The geological conditions and processes of fine-grained gravity flow sedimentation in continental lacustrine basins in China are analyzed to construct the model of fine-grained gravity flow sedimentation in lacustrine basin, reveal the development laws of fine-grained deposits and source-reservoir, and identify the sweet sections of shale oil. The results show that fine-grained gravity flow is one of the important sedimentary processes in deep lake environment, and it can transport fine-grained clasts and organic matter in shallow water to deep lake, forming sweet sections and high-quality source rocks of shale oil. Fine-grained gravity flow deposits in deep waters of lacustrine basins in China are mainly fine-grained high-density flow, fine-grained turbidity flow (including surge-like turbidity flow and fine-grained hyperpycnal flow), fine-grained viscous flow (including fine-grained debris flow and mud flow), and fine-grained transitional flow deposits. The distribution of fine-grained gravity flow deposits in the warm and humid unbalanced lacustrine basins are controlled by lake-level fluctuation, flooding events, and lakebed paleogeomorphology. During the lake-level rise, fine-grained hyperpycnal flow caused by flooding formed fine-grained channel-levee-lobe system in the flat area of the deep lake. During the lake-level fall, the sublacustrine fan system represented by unconfined channel was developed in the flexural slope breaks and sedimentary slopes of depressed lacustrine basins, and in the steep slopes of faulted lacustrine basins; the sublacustrine fan system with confined or unconfined channel was developed on the gentle slopes and in axial direction of faulted lacustrine basins, with fine-grained gravity flow deposits possibly existing in the lower fan. Within the fourth-order sequences, transgression might lead to organic-rich shale and fine-grained hyperpycnal flow deposits, while regression might cause fine-grained high-density flow, surge-like turbidity flow, fine-grained debris flow, mud flow, and fine-grained transitional flow deposits. Since the Permian, in the shale strata of lacustrine basins in China, multiple transgression-regression cycles of fourth-order sequences have formed multiple source-reservoir assemblages. Diverse fine-grained gravity flow sedimentation processes have created sweet sections of thin siltstone consisting of fine-grained high-density flow, fine-grained hyperpycnal flow and surge-like turbidity flow deposits, sweet sections with interbeds of mudstone and siltstone formed by fine-grained transitional flows, and sweet sections of shale containing silty and muddy clasts and with horizontal bedding formed by fine-grained debris flow and mud flow. The model of fine-grained gravity flow sedimentation in lacustrine basin is significant for the scientific evaluation of sweet shale oil reservoir and organic-rich source rock.
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The geochemical analysis and experimental simulation are comprehensively used to systematically study the hydrocarbon generation material, organic matter enrichment and hydrocarbon generation model of Paleogene source rock in the Western Qaidam Depression, Qaidam Basin, NW China. Three main factors result in low TOC values of saline lacustrine source rock of the Qaidam Basin: relatively poor nutrient supply inhibits the algal bloom, too fast deposition rate causes the dilution of organic matter, and high organic matter conversion efficiency causes the low residual organic carbon. For this type of hydrogen-rich organic matter, due to the reduction of organic carbon during hydrocarbon generation, TOC needs to be restored based on maturity before evaluating organic matter abundance. The hydrocarbon generation of saline lacustrine source rocks of the Qaidam Basin is from two parts: soluble organic matter and insoluble organic matter. The soluble organic matter is inherited from organisms and preserved in saline lacustrine basins. It generates hydrocarbons during low-maturity stage, and the formed hydrocarbons are rich in complex compounds such as NOS, and undergo secondary cracking to form light components in the later stage; the hydrocarbon generation model of insoluble organic matter conforms to the traditional “Tissot” model, with an oil generation peak corresponding to Ro of 1.0%.
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Through the study of organic matter enrichment, hydrocarbon generation and accumulation process of black shale of the Cretaceous Qingshankou Formation in the Songliao Basin, the enrichment mechanism of Gulong shale oil and the distribution of conventional-unconventional oil are revealed. The Songliao Basin is a huge interior lake basin formed in the Early Cretaceous under the control of the subduction and retreat of the western Pacific plate and the massive horizontal displacement of the Tanlu Fault Zone in Northeast China. During the deposition of the Qingshankou Formation, strong terrestrial hydrological cycle led to the lake level rise of the ancient Songliao Basin and the input of a large amount of nutrients, resulting in planktonic bacteria and algae flourish. Intermittent seawater intrusion events promoted the formation of salinization stratification and anoxic environment in the lake, which were beneficial to the enrichment of organic matters. Biomarkers analysis confirms that the biogenic organic matter of planktonic bacteria and algae modified by microorganisms plays an important role in the formation of high-quality source rocks with high oil generation capability. There are four favorable conditions for the enrichment of light shale oil in the Qingshankou Formation of the Gulong Sag, Songliao Basin: the moderate organic matter abundance and high oil potential provide sufficient material basis for oil enrichment; high degree of thermal evolution makes shale oil have high GOR and good mobility; low hydrocarbon expulsion efficiency leads to a high content of retained hydrocarbons in the source rock; and the confinement effect of intra-layer cement in the high maturity stage induces the efficient accumulation of light shale oil. The restoration of hydrocarbon accumulation process suggests that liquid hydrocarbons generated in the early (low-medium maturity) stage of the Qingshankou Formation source rocks accumulated in placanticline and slope after long-distance secondary migration, forming high-quality conventional and tight oil reservoirs. Light oil generated in the late (medium-high maturity) stage accumulated in situ, forming about 15 billion tons of Gulong shale oil resources, which finally enabled the orderly distribution of conventional-unconventional oils that are contiguous horizontally and superposed vertically within the basin, showing a complete pattern of “whole petroleum system” with conventional oil, tight oil and shale oil in sequence.
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The global trends in deepwater oil and gas exploration, characteristics of deepwater oil and gas discovery, and layout of deepwater oil and gas exploration business by seven major international oil companies are systematically analyzed using commercial databases (e.g. S&P Global and Rystad) and public information of oil companies. The deepwater area is currently the most important domain for global oil and gas exploration and discovery, with the most discoveries and reserves in passive continental margin basins. The deepwater discoveries have the greatest contribution to the total newly discovered oil and gas reserves in the sea areas, with an increasing number of lithological reservoirs discovered, and oil and gas discoveries mainly distributed in the Mesozoic-Cenozoic. The seven major international oil companies are widely active in various aspects of deepwater oil and gas exploration and development, and play a leading role. Based on years of theoretical understanding of global oil and gas geology and resource evaluation, it is proposed that favorable deepwater exploration areas in the future will mainly focus on three major areas: the Atlantic coast, the Indian Ocean periphery, and the Arctic Ocean periphery. Six suggestions are put forward for expanding overseas deepwater oil and gas exploration business: first, expand the sources for obtaining multi-user seismic data and improve the scientific selection of deepwater exploration areas; second, increase efforts to obtain deepwater exploration projects in key areas; third, adopt various methods to access into/exit from resource licenses flexibly; fourth, acquire licenses with large equity and operate in “dual-exploration” model; fifth, strengthen cooperation with leading international oil companies in deepwater technology; and sixth, improve business operation capabilities and gradually transform from “non-operators” to “operators”.
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Based on core observation, thin section examination, fluid inclusions analysis, carbon and oxygen isotopic composition analysis, and other approaches, the structural and burial evolution histories were investigated, and the diagenetic evolution process and genetic/development models were systematically discussed of the Upper Paleozoic Permian clastic rock reservoirs in the Bohai Bay Basin, East China. The Bohai Bay Basin underwent three stages of burial and two stages of uplifting in the Upper Paleozoic. Consequently, three stages of acid dissolution generated by the thermal evolution of kerogen, and two stages of meteoric freshwater leaching occurred. Dissolution in deeply buried, nearly closed diagenetic system was associated with the precipitation of authigenic clay and quartz, leading to a limited increase in storage space. Different structural uplifting-subsidence processes of tectonic zones resulted in varying diagenetic-reservoir-forming processes of the Permian clastic reservoirs. Three genetic models of reservoirs are recognized. The Model I reservoirs with pores formed in shallow strata and buried in shallow to medium strata underwent two stages of exposure to long-term open environment and two stages of meteoric freshwater leaching to enhance pores near the surface, and were shallowly buried in the late stage, exhibiting the dominance of secondary pores and the best physical properties. The Model II reservoirs with pores formed in shallow strata and preserved due to modification after deep burial experienced an early exposure-open to late burial-closed environment, where pore types were modified due to dissolution, exhibiting the dominance of numerous secondary solution pores in feldspar and the physical properties inferior to Model I. The Model III reservoirs with pores formed after being regulated after multiple periods of burial and dissolution experienced a dissolution of acidic fluids of organic origin under a near-closed to closed environment, exhibiting the dominance of intercrystalline micropores in kaolinite and the poorest physical properties. The target reservoirs lied in the waterflood area in the geological period of meteoric freshwater leaching, and are now the Model II deep reservoirs in the slope zone-depression zone. They are determined as favorable options for subsequent exploration.
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In 2022, the risk exploration well Chongtan1 (CT1) in the Sichuan Basin revealed commercial oil and gas flow during test in a new zone - the marl of the second submember of the third member of Leikoupo Formation (Lei-32) of Middle Triassic, recording a significant discovery. However, the hydrocarbon accumulation in marl remains unclear, which restricts the selection and deployment of exploration area. Focusing on Well CT1, the hydrocarbon accumulation characteristics of Lei-32 marl are analyzed to clarify the potential zones for exploration. The following findings are obtained. First, according to the geochemical analysis of petroleum and source rocks, oil and gas in the Lei-32 marl of Well CT1 are originated from the same marl. The marl acts as both source rock and reservoir rock. Second, the Lei-32 marl in central Sichuan Basin is of lagoonal facies, with a thickness of 40-130 m, an area of about 40 000 km2, a hydrocarbon generation intensity of (4-12)×108 m3/km2, and an estimated quantity of generated hydrocarbons of 25×1012 m3. Third, the lagoonal marl reservoirs are widely distributed in central Sichuan Basin. Typically, in Xichong-Yilong, Ziyang-Jianyang and Moxi South, the reservoirs are 20-60 m thick and cover an area of 7500 km2. Fourth, hydrocarbons in the lagoonal marl are generated and stored in the Lei-32 marl, which means that marl serves as both source rock and reservoir rock. They represent a new type of unconventional resource, which is worthy of exploring. Fifth, based on the interpretation of 2D and 3D seismic data from central Sichuan Basin, Xichong and Suining are defined as favorable prospects with estimated resources of (2000-3000)×108 m3.
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Mesozoic marine shale oil was found in the Qiangtang Basin by a large number of hydrocarbon geological surveys and shallow drilling sampling. Based on systematic observation and experimental analysis of outcrop and core samples, the deposition and development conditions and characteristics of marine shale are revealed, the geochemical and reservoir characteristics of marine shale are evaluated, and the layers of marine shale oil in the Mesozoic are determined. The following geological understandings are obtained. First, there are two sets of marine organic-rich shales, the Lower Jurassic Quse Formation and the Upper Triassic Bagong Formation, in the Qiangtang Basin. They are mainly composed of laminated shale with massive mudstone. The laminated organic-rich shale of the Quse Formation is located in the lower part of the stratum, with a thickness of 50-75 m, and mainly distributed in southern Qiangtang Basin and the central-west of northern Qiangtang Basin. The laminated organic-rich shale of the Bagong Formation is located in the middle of the stratum, with a thickness of 250-350 m, and distributed in both northern and southern Qiangtang Basin. Second, the two sets of laminated organic-rich shales develop foliation, and various types of micropores and microfractures. The average content of brittle minerals is 70%, implying a high fracturability. The average porosity is 5.89%, indicating good reservoir physical properties to the level of moderate-good shale oil reservoirs. Third, the organic-rich shale of the Quse Formation contains organic matters of types II1 and II2, with the average TOC of 8.34%, the average content of chloroform bitumen 'A' of 0.66%, the average residual hydrocarbon generation potential (S1+S2) of 29.93 mg/g, and the Ro value of 0.9%-1.3%, meeting the standard of high-quality source rock. The organic-rich shale of the Bagong Formation contains mixed organic matters, with the TOC of 0.65%-3.10% and the Ro value of 1.17%-1.59%, meeting the standard of moderate source rock. Fourth, four shallow wells (depth of 50-250 m) with oil shows have been found in the organic shales at 50-90 m in the lower part of the Bagong Formation and 30-75 m in the middle part of the Quse Formation. The crude oil contains a high content of saturated hydrocarbon. Analysis and testing of outcrop and shallow well samples confirm the presence of marine shale oil in the Bagong Formation and the Quse Formation. Good shale oil intervals in the Bagong Formation are observed in layers 18-20 in the lower part of the section, where the shales with (S0+S1) higher than 1 mg/g are 206.7 m thick, with the maximum and average (S0+S1) of 1.92 mg/g and 1.81 mg/g, respectively. Good shale oil intervals in the Quse Formation are found in layers 4-8 in the lower part of the section, where the shales with (S0+S1) higher than 1 mg/g are 58.8 m thick, with the maximum and average (S0+S1) of 6.46 mg/g and 2.23 mg/g, respectively.
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The Tongnan secondary negative structure in central Sichuan Basin has controls and influences on the structural framework and petroleum geological conditions in the Gaoshiti-Moxi area. To clarify the controls and influences, the deformation characteristics, structural attributes and evolution process of the Tongnan negative structure were investigated through a series of qualitative and quantitative methods such as balanced profile restoration, area-depth-strain (ADS) analysis, and structural geometric forward numerical simulation, after comprehensive structural interpretation of high-precision 3D seismic data. The results are obtained in three aspects. First, above and below the P/AnP (Permian/pre-Permian) unconformity, the Tongnan negative structure demonstrates vertical differential structural deformation. It experiences two stages of structural stacking and reworking: extensional depression (from the Sinian Dengying Formation to the Permian), and compressional syncline deformation (after the Jurassic). The multi-phase trishear deformation of the preexisting deep normal faults dominated the extensional depression. The primary depression episodes occurred in the periods from the end of Late Proterozoic to the deposition of the 1st-2nd members of the Dengying Formation, and from the deposition of Lower Cambrian Longwangmiao Formation-Middle-Upper Cambrian until the Ordovician. Second, the multi-stage evolution process of the Tongnan negative structure controlled the oil and gas migration and adjustment and present-day differential gas and water distribution between the Tongnan negative structure and the Gaoshiti and Moxi-Longnüsi structural highs. Third, the Ordovician, which is limitedly distributed in the Tongnan negative structure and is truncated by the P/AnP unconformity on the top, has basic geological conditions for the formation of weathering karst carbonate reservoirs. It is a new petroleum target deserving attention.
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A quantitative evaluation model that integrates kerogen adsorption and clay pore adsorption of shale oil was proposed, and the evaluation charts of adsorption-swelling capacity of kerogen (Mk) and adsorbed oil capacity of clay minerals (Mc) were established, taking the 1st member of Cretaceous Qingshankou Formation in the northern Songliao Basin as an example. The model and charts were derived from swelling oil experiments performed on naturally evolved kerogens and adsorbed oil experiments on clays (separated from shale core samples). They were constructed on the basis of clarifying the control law of kerogen maturity evolution on its adsorption-swelling capacity, and considering the effect of both the clay pore surface area that occupied by adsorbed oil and formation temperature. The results are obtained in four aspects: (1) For the Qing 1 Member shale, with the increase of maturity, Mk decreases. Given Ro of 0.83%-1.65%, Mk is about 50-250 mg/g. (2) The clay in shale adsorbs asphaltene. Mc is 0.63 mg/m2, and about 15% of the clay pore surface is occupied by adsorbed oil. (3) In the low to medium maturity stages, the shale oil adsorption is controlled by organic matter. When Ro>1.3%, the shale oil adsorption capacity is contributed by clay pores. (4) The oil adsorption capacity evaluated on the surface at room temperature is 8%-22% (avg. 15%) higher than that is held in the formations. The proposed evaluation model reveals the occurrence mechanisms of shale oils with different maturities, and provides a new insight for estimating the reserves of shale oil under formation temperature conditions.
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The features of the unconformity, fault and tectonic inversion in the eastern Doseo Basin, Chad, were analyzed, and the genetic mechanisms and basin evolution were discussed using seismic and drilling data. The following results are obtained. First, four stratigraphic unconformities, i.e. basement (Tg), Mangara Group (T10), lower Upper Cretaceous (T5) and Cretaceous (T4), four faulting stages, i.e. Barremian extensional faults, Aptian-Coniacian strike-slip faults, Campanian strike-slip faults, and Eocene strike-slip faults, and two tectonic inversions, i.e. Santonian and end of Cretaceous, were developed in the Doseo Basin. Second, the Doseo Basin was an early failed intracontinental passive rift basin transformed by the strike-slip movement and tectonic inversion. The initial rifting between the African and South American plates induced the nearly N-S stretching of the Doseo Basin, giving rise to the formation of the embryonic Doseo rift basin. The nearly E-W strike-slip movement of Borogop (F1) in the western section of the Central African Shear Zone resulted in the gradual cease of the near north-south rifting and long-term strike-slip transformation, forming a dextral transtension fault system with inherited activity but gradually weakened in intensity (interrupted by two tectonic inversions). This fault system was composed of the main shear (F1), R-type shear (F2-F3) and P-type shear (F4-F5) faults, with the strike-slip associated faults as branches. The strike-slip movements of F1 in Cretaceous and Eocene were controlled by the dextral shear opening of the equatorial south Atlantic and rapid expanding of the Indian Ocean, respectively. The combined function of the strike-slip movement of F1 and the convergence between Africa and Eurasia made the Doseo Basin underwent the Santonian dextral transpressional inversion characterized by intensive folding deformation leading to the echelon NE-SW and NNE-SSW nose-shaped uplifts and unconformity (T5) on high parts of the uplifts. The convergence between Africa and Eurasia caused the intensive tectonic inversion of Doseo Basin at the end of Cretaceous manifesting as intensive uplift, denudation and folding deformation, forming the regional unconformity (T4) and superposing a nearly E-W structural configuration on the Santonian structures. Third, the Doseo Basin experienced four evolutional stages with the features of short rifting and long depression, i.e. Barremian rifting, Aptian rifting-depression transition, Albian-Late Cretaceous depression, and Cenozoic extinction, under the control of the tectonic movements between Africa and its peripheral plates.
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Through analysis of four aspects, including the distribution and production of global oil and gas fields, the distribution and changes of remaining recoverable reserves, the differences in oil and gas production between regions/countries, and the development potential of oil and gas fields with production capacity not built and to be built, this paper presents the situation and trends of global oil and gas development in 2022. It is found that, in 2022, oil and gas fields are widely distributed worldwide, and upstream production activities continue to recover; the oil and gas reserves decrease slightly year on year, and the oil and gas reserves in sea areas increase significantly; the oil and gas production increases continuously, and the key resource countries make a significant contribution in oil and gas production growth; the oil and gas fields with production capacity not built and to be built hold abundant reserves, and their development potential will be gradually released with the economic benefits increase. Further analysis is conducted from the perspectives of global oil and gas resources continuity, geopolitical risks, potential of international cooperation, and upgrade of unconventional oil and gas technology. Finally, in view of core business domains and strategies under the new situation, the Chinese oil companies are recommended to: (1) keep a foothold in onshore conventional oil and gas development by virtue of their comparative advantages and learning from other’s experience in cooperation; (2) carry out pilot tests on development adjustment, and deepen the international cooperation in enhanced oil/gas recovery; (3) improve the oil and gas operation capabilities in sea areas to transform from follower as minority shareholder to joint venture and then to independent operations; and (4) seek appropriate ways for shale oil/gas development to reduce the dependence on foreign oil and gas.
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A self-designed full-diameter core experimental facility was used to evaluate the flow heterogeneity of bedding fractures at four radial directions under different closure pressures and injection rates, using full-diameter cores retaining original natural bedding fractures. The distribution morphology of bedding surface affects the conductivity of bedding fractures, and the flow capacity of bedding fractures in four radial directions varies greatly with the closure pressure and injection rate. The rougher the fracture surface, the greater the flow capacity varies with the closure pressure. For unsupported bedding fractures, the mean percentage error (MPE) of the conductivity in four radial directions increase gradually with the increase of the closure pressure. This phenomenon is especially prominent in deep rock samples. It is indicated that the flow heterogeneity of bedding fractures tends to increase with the closure pressure. When proppant is placed in the fracture, at a low closure pressure, due to the combined effects of self-support of rough fracture surface, proppant instability and uneven proppant placement, the flow heterogeneity is greater than that when proppant is not placed at the same closure pressure; however, with the increase of the closure pressure, the proppant becomes compact and stable, and the flow heterogeneity is mitigated gradually.
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Considering the characteristics of carbonate reservoirs in the Middle East, a low-viscosity microemulsion acid that can be prepared on site and has an appropriate retardation ability was developed. It was compared with four conventional acid systems (hydrochloric acid, gelled acid, emulsified acid and surfactant acid) through experiments of rotating disk, multistage acid fracturing and core flooding with CT scanning. The micro-etching characteristics and conductivity of fracture surfaces were clarified, and the variation of saturation field during water invasion and flowback of spent acid and the recovery of oil phase relative permeability were quantitatively evaluated. The study shows that the addition of negatively charged agent to the oil core of microemulsion acid can enhance its adsorption capacity on the limestone surface and significantly reduce the H+ mass transfer rate. Moreover, the negatively charged oil core is immiscible with the Ca2 + salt, so that the microemulsion acid can keep an overall structure not be damaged by Ca2 + salt generated during reaction, with adjustable adsorption capacity and stable microemulsion structure. With high vertical permeability along the fracture walls, the microemulsion acid can penetrate into deep fracture wall to form network etching, which helps greatly improve the permeability of reservoirs around the fractures and keep a high conductivity under a high closure pressure. The spent microemulsion acid is miscible with crude oil to form microemulsion. The microemulsion, oil and water are in a nearly miscible state, with basically no water block and low flowback resistance, the flowback of spent acid and the relative permeability of oil are recovered to a high degree.
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Considering the pore deformation and permeability changes during dilation-recompaction in cyclic steam stimulation (CSS), an existing geomechanical model is improved and thermo-mechanically coupled with the flow equations to form a coupled flow-geomechanical model. The impacts of dilation-recompaction parameters can be quantified through sensitivity analysis and uncertainty assessment utilizing the synergy between Latin hypercube designs and response surface methodology. The improved coupled flow-geomechanical model allows a more reasonable history-matching of steam injection pressure and volume and oil/water production volume. In both the linear and quadratic models, the rise in recompaction pressure has the most significant effect on the rise in the volumes of steam injection and water production, both rock compressibility and recompaction pressure are positively correlated with steam injectivity and oil/water production, and the dilation pressure is negatively correlated with steam injectivity and oil/water production. In the linear model, dilation pressure has the most significant negative impact on the cumulative oil production, and compressibility and recompaction pressure are positively correlated with oil production. In the quadratic model, the rise in recompaction pressure has the most significant effect on the rise in the cumulative volumes of oil/water production and steam injection. The interactions between the dilation/recompaction pressures and spongy-rock compressibility negatively affect the cumulative volumes of oil/water production and steam injection.
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Three high-temperature resistant polymeric additives for water-based drilling fluids are designed and developed: weakly cross-linked zwitterionic polymer fluid loss reducer (WCZ), flexible polymer microsphere nano-plugging agent (FPM) and comb-structure polymeric lubricant (CSP). A high-temperature resistant and high-density polymeric saturated brine-based drilling fluid was developed for deep drilling. The WCZ has a good anti-polyelectrolyte effect and exhibits the API fluid loss less than 8 mL after aging in saturated salt environment at 200 °C. The FPM can reduce the fluid loss by improving the quality of the mud cake and has a good plugging effect on nano-scale pores/fractures. The CSP, with a weight average molecular weight of 4804, has multiple polar adsorption sites and exhibits excellent lubricating performance under high temperature and high salt conditions. The developed drilling fluid system with a density of 2.0 g/cm3 has good rheological properties. It shows a fluid loss less than 15 mL at 200 °C and high pressure, a sedimentation factor (SF) smaller than 0.52 after standing at high temperature for 5 d, and a rolling recovery of hydratable drill cuttings similar to oil-based drilling fluid. Besides, it has good plugging and lubricating performance.
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This paper establishes a 3D multi-well pad fracturing numerical model coupled with fracture propagation and proppant migration based on the displacement discontinuity method and Eulerian-Eulerian frameworks, and the fracture propagation and proppant distribution during multi-well fracturing are investigated by taking the actual multi-well pad parameters as an example. Fracture initiation and propagation during multi-well pad fracturing are jointly affected by a variety of stress interference mechanisms such as inter-cluster, inter-stage, and inter-well, and the fracture extension is unbalanced among clusters, asymmetric on both wings, and dipping at heels. Due to the significant influence of fracture morphology and width on the migration capacity of proppant in the fracture, proppant is mainly placed in the area near the wellbore with large fracture width, while a high-concentration sandwash may easily occur in the area with narrow fracture width as a result of quick bridging. On the whole, the proppant placement range is limited. Increasing the well-spacing can reduce the stress interference of adjacent wells and promote the uniform distribution of fractures and proppant on both wings. The maximum stimulated reservoir volume or multi-fracture uniform propagation can be achieved by optimizing the well spacing. Although reducing the perforation-cluster spacing also can improve the stimulated reservoir area, a too low cluster spacing is not conducive to effectively increasing the propped fracture area. Since increasing the stage time lag is beneficial to reduce inter-stage stress interference, zipper fracturing produces more uniform fracture propagation and proppant distribution.
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To study the fluid dynamic response mechanism under the working condition of water injection well borehole, based on the microelement analysis of fluid mechanics and the classical theory of hydrodynamics, a fluid microelement pressure-flow rate relationship model is built to derive and solve the dynamic distribution of fluid pressure and flow rate in the space of well borehole. Combined with the production data of a typical deviated well in China, numerical simulations and analyses are carried out to analyze the dynamic distribution of wellbore pressure at different injection pressures and injection volumes, the delayed and attenuated characteristics of fluid transmission in tube, and the dynamic distribution of wellbore pressure amplitude under the fluctuation of wellhead pressure. The pressure loss along the wellbore has nothing to do with the absolute pressure, and the design of the coding and decoding scheme for wave code communication doesn’t need to consider the absolute pressure during injecting. When the injection pressure is constant, the higher the injection flow rate at the wellhead, the larger the pressure loss along the wellbore. The fluid wave signal delay amplitude mainly depends on the length of the wellbore. The smaller the tubing diameter, the larger the fluid wave signal attenuation amplitude. The higher the target wave code amplitude (differential pressure identification root mean square) generated at the same well depth, the greater the wellhead pressure wave amplitude required to overcome the wellbore pressure loss.
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This paper systematically reviews the trend of carbon dioxide capture, utilization and storage (CCUS) industry in the world and China, presents the CCUS projects, clusters, technologies and strategies/policies, and analyzes the CCUS challenges and countermeasures in China based on the comparison of CCUS industrial development at home and abroad. The global CCUS development has experienced three stages: exploration stage, policy driven stage, and dual-drive stage. Currently, the active large-scale CCUS projects around the world focus on enhanced oil recovery (EOR) and are expanding into storage in saline aquifers. The CCUS industry of China has evolved in three stages: exploration, pilot test, and industrialization. In the current critical period of transition from field test to industrialization, China’s CCUS projects are EOR-dominated. By comparing the industrial development of CCUS in China and abroad, it is found that the scale-up and industrialization of CCUS in China face challenges in technology, facilities and policies. Finally, future solutions to CCUS development in China are proposed as follows: strengthening the top-level design and planning of CCUS; developing high-efficiency and low-cost CCUS technologies throughout the whole industrial chain; deploying CCUS oil and gas + new energy clusters; improving the policy support system of CCUS; and strengthening discipline construction and personnel training, etc.
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In order to obtain the impact frequency of resonant coal breaking by self-excited oscillation pulsed supercritical carbon dioxide (SC-CO2) jet, large eddy simulation was used to analyze the formation and development process of self-excited oscillation pulsed SC-CO2 jet, the variation of jet impact frequency in the nozzle and the free flow field, and the variation of jet impact frequency at different positions in the jet axis and under different cavity lengths. The test device of jet impact frequency was developed, and experiments were performed to verify the conclusions of the numerical simulations. The results show that the frequency of the self-excited oscillation pulsed SC-CO2 jet is different in the nozzle and the free flow field. In the nozzle, the frequency generated by the fluid disturbance is the same, and the jet frequency at the exit of the nozzle is consistent with that inside the nozzle. In the free flow field, due to the compressibility of CO2, the pressure, velocity and other parameters of SC-CO2 jets have obvious fluctuation patterns. This feature causes the impact frequency of the self-excited oscillation pulsed SC-CO2 jet to decrease gradually in the axis. Changing the cavity length allows the adjustment of the jet impact frequency in the free flow field by affecting the disturbance frequency of the self-excited oscillation pulsed SC-CO2 jet inside the nozzle.
