23 June 2024, Volume 51 Issue 3
  • ZHI Dongming, LI Jianzhong, YANG Fan, CHEN Xuan, WU Chao, WANG Bo, ZHANG Hua, HU Jun, JIN Jikun
    Petroleum Exploration and Development, 2024, 51(3): 453-466. https://doi.org/10.11698/PED.20240028
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    Based on the latest results of near-source exploration in the Middle and Lower Jurassic of the Tuha Basin, a new understanding of the source rocks, reservoir conditions, and source-reservoir-cap rock combinations of the Jurassic Shuixigou Group in the Taibei Sag is established using the concept of the whole petroleum system, and the coal-measure whole petroleum system is analyzed thoroughly. The results are obtained in three aspects. First, the coal-measure source rocks of the Badaowan Formation and Xishanyao Formation and the argillaceous source rocks of the Sangonghe Formation in the Shuixigou Group exhibit the characteristics of long-term hydrocarbon generation, multiple hydrocarbon generation peaks, and simultaneous oil and gas generation, providing sufficient oil and gas sources for the whole petroleum system in the Jurassic coal-bearing basin. Second, multi-phase shallow braided river delta-shallow lacustrine deposits contribute multiple types of reservoirs, e.g. sandstone, tight sandstone, shale and coal rock, in slope and depression areas, providing effective storage space for the petroleum reservoir formation in coal-measure strata. Third, three phases of hydrocarbon charging and structural evolution, as well as effective configuration of multiple types of reservoirs, result in the sequential accumulation of conventional-unconventional hydrocarbons. From high structural positions to depression, there are conventional structural and structural-lithological reservoirs far from the source, low-saturation structural-lithological reservoirs near the source, and tight sandstone gas, coal rock gas and shale oil accumulations within the source. Typically, the tight sandstone gas and coal rock gas are the key options for further exploration, and the shale oil and gas in the depression area is worth of more attention. The new understanding of the whole petroleum system in the coal measures could further enrich and improve the geological theory of the whole petroleum system, and provide new ideas for the overall exploration of oil and gas resources in the Tuha Basin.

  • XU Changgui, ZHANG Gongcheng, HUANG Shengbing, SHAN Xuanlong, LI Jiahui
    Petroleum Exploration and Development, 2024, 51(3): 467-477. https://doi.org/10.11698/PED.20230288
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    Based on the geological and geophysical data of Mesozoic oil-gas exploration in the sea area of Bohai Bay Basin and the discovered high-yield volcanic oil and gas wells since 2019, this paper methodically summarizes the formation conditions of large- and medium-sized Cretaceous volcanic oil and gas reservoirs in the Bohai Sea. Research shows that the Mesozoic large intermediate-felsic lava and intermediate-felsic composite volcanic edifices in the Bohai Sea are the material basis for the formation of large-scale volcanic reservoirs. The upper subfacies of effusive facies and cryptoexplosive breccia subfacies of volcanic conduit facies of volcanic vent-proximal facies belts are favorable for large-scale volcanic reservoir formation. Two types of efficient reservoirs, characterized by high porosity and medium to low permeability, as well as medium porosity and medium to low permeability, are the core of the formation of large- and medium-sized volcanic reservoirs. The reservoir with high porosity and medium to low permeability is formed by intermediate-felsic vesicular lava or the cryptoexplosive breccia superimposed by intensive dissolution. The reservoir with medium porosity and medium to low permeability is formed by intense tectonism superimposed by fluid dissolution. Weathering and tectonic transformation are main formation mechanisms for large and medium-sized volcanic reservoirs in the study area. The “source-reservoir draping type” at the low source is the optimum source-reservoir configuration relationship for large- and medium-sized volcanic reservoirs. There exists favorable volcanic facies, efficient reservoirs and source-reservoir draping configuration relationship on the periphery of Bozhong Sag, and the large intermediate-felsic lava and intermediate-felsic composite volcanic edifices close to strike-slip faults and their branch faults are the main directions of future exploration.

  • SHI Yuanpeng, LIU Zhanguo, WANG Shaochun, WU Jin, LIU Xiheng, HU Yanxu, CHEN Shuguang, FENG Guangye, WANG Biao, WANG Haoyu
    Petroleum Exploration and Development, 2024, 51(3): 478-489. https://doi.org/10.11698/PED.20240023
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    Based on new data from cores, drilling and logging, combined with extensive rock and mineral testing analysis, a systematic analysis is conducted on the characteristics, diagenesis types, genesis and controlling factors of deep to ultra-deep abnormally high porosity clastic rock reservoirs in the Oligocene Linhe Formation in the Hetao Basin. The reservoir space of the deep to ultra-deep clastic rock reservoirs in the Linhe Formation is mainly primary pores, and the coupling of three favorable diagenetic elements, namely the rock fabric with strong compaction resistance, weak thermal compaction diagenetic dynamic field, and diagenetic environment with weak fluid compaction-weak cementation, is conducive to the preservation of primary pores. The Linhe Formation clastic rocks have a superior preexisting material composition, with an average total content of 90% for quartz, feldspar, and rigid rock fragments, and strong resistance to compaction. The geothermal gradient in Linhe Depression in the range of (2.0-2.6) ℃/100 m is low, and together with the burial history of long-term shallow burial and late rapid deep burial, it forms a weak thermal compaction diagenetic dynamic field environment. The diagenetic environment of the saline lake basin is characterized by weak fluid compaction. At the same time, the paleosalinity has zoning characteristics, and weak cementation in low salinity areas is conducive to the preservation of primary pores. The hydrodynamic conditions of sedimentation, salinity differentiation of ancient water in saline lake basins, and sand body thickness jointly control the distribution of high-quality reservoirs in the Linhe Formation.

  • TANG Yong, HU Suyun, GONG Deyu, YOU Xincai, LI Hui, LIU Hailei, CHEN Xuan
    Petroleum Exploration and Development, 2024, 51(3): 490-500. https://doi.org/10.11698/PED.20230631
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    Based on the organic geochemical data and the component and stable carbon isotopic composition of natural gas of the Lower Permian Fengcheng Formation in the western Central Depression of Junggar Basin, combined with sedimentary environment analysis and hydrocarbon generation simulation, the gas-generating potential of the Fengcheng source rock is evaluated, the distribution of large-scale effective source kitchen is described, the genetic types of natural gas are clarified, and four types of favorable exploration targets are selected. The results show that: (1) The Fengcheng Formation is a set of oil-prone source rock, and the retained liquid hydrocarbon is conducive to late cracking into gas, with characteristics of high gas-generating potential and late accumulation; (2) The maximum thickness of Fengcheng source rock reaches 900 m. The source rock has entered the main gas-generating stage in Well Pen-1 western and Shawan sags, and the area with gas generation intensity greater than 20×108 m3/km2 is approximately 6 500 km2. (3) Around the western Central Depression, highly mature oil-type gas with light carbon isotope composition was identified to be derived from the Fengcheng source rocks mainly, while the rest was coal-derived gas from the Carboniferous source rock; (4) Four types of favorable exploration targets with exploration potential were developed in the western Central Depression which are structural traps neighboring to the source, stratigraphic traps neighboring to the source, shale-gas type within the source, and structural traps within the source.

  • DENG Xiuqin, CHU Meijuan, WANG Long, CHEN Xiu, WANG Yanxin
    Petroleum Exploration and Development, 2024, 51(3): 501-512. https://doi.org/10.11698/PED.20230410
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    Based on a large number of newly added deep well data in recent years, the subsidence of the Ordos Basin in the Mid-Late Triassic is systematically studied, and it is proposed that the Ordos Basin experienced two important subsidence events during this depositional period. Through contrastive analysis of the two stages of tectonic subsidence, including stratigraphic characteristics, lithology combination, location of catchment area and sedimentary evolution, it is proposed that both of them are responses to the Indosinian Qinling tectonic activity on the northern edge of the craton basin. The early subsidence occurred in the Chang 10 Member was featured by high amplitude, large debris supply and fast deposition rate, with coarse debris filling and rapid subsidence accompanied by rapid accumulation, resulting in strata thickness increasing from northeast to southwest in wedge-shape. The subsidence center was located in Huanxian-Zhenyuan-Qingyang-Zhengning areas of southwestern basin with the strata thickness of 800-1 300 m. The subsidence center deviating from the depocenter developed multiple catchment areas, until then, unified lake basin has not been formed yet. Under the combined action of subsidence and Carnian heavy rainfall event during the deposition period of Chang 7 Member, a large deep-water depression was formed at slow deposition rate, with the subsidence center coincided with the depocenter basically in the Mahuangshan-Huachi-Huangling areas. The deep-water sediments were 120-320 m thick in the subsidence center, characterized by fine grain. There are differences in the mechanism between the two stages of subsidence. The early one was the response to the northward subduction of the MianLüe Ocean and intense depression under compression in Qinling during Mid-Triassic. The later subsidence is controlled by the weak extensional tectonic environment of the post-collision stage during Late Triassic.

  • TANG Wu, XIE Xiaojun, XIONG Lianqiao, GUO Shuai, XU Min, XU Enze, BAI Haiqiang, LIU Ziyu
    Petroleum Exploration and Development, 2024, 51(3): 513-525. https://doi.org/10.11698/PED.20230620
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    The coupling relationship between shelf-edge deltas and deep-water fan sand bodies is a hot and cutting-edge field of international sedimentology and deep-water oil and gas exploration. Based on the newly acquired high-resolution 3D seismic, logging and core data of Pearl River Mouth Basin (PRMB), this paper dissected the shelf-edge delta to deep-water fan (SEDDF) depositional system in the Oligocene Zhuhai Formation of Paleogene in south subsag of Baiyun Sag, and revealed the complex coupling relationship from the continental shelf edge to deep-water fan sedimentation and its genetic mechanisms. The results show that during the deposition of the fourth to first members of the Zhuhai Formation, the scale of the SEDDF depositional system in the study area showed a pattern of first increasing and then decreasing, with deep-water fan developed in the third to first members and the largest plane distribution scale developed in the late stage of the second member. Based on the development of SEDDF depositional system along the source direction, three types of coupling relationships are divided, namely, deltas that are linked downdip to fans, deltas that lack downdip fans and fans that lack updip coeval deltas, with different depositional characteristics and genetic mechanisms. (1) Deltas that are linked downdip to fans: with the development of shelf-edge deltas in the shelf area and deep-water fans in the downdip slope area, and the strong source supply and relative sea level decline are the two key factors which control the development of this type of source-to-sink (S2S). The development of channels on the continental shelf edge is conducive to the formation of this type of S2S system even with weak source supply and high sea level. (2) Deltas that lack downdip fans: with the development of shelf edge deltas in shelf area, while deep water fans are not developed in the downdip slope area. The lack of “sources” and “channels”, and fluid transformation are the three main reasons for the formation of this type of S2S system. (3) Fans that lack updip coeval deltas: with the development of deep-water fans in continental slope area and the absence of updip coeval shelf edge deltas, which is jointly controlled by the coupling of fluid transformation at the shelf edge and the “channels” in the continental slope area.

  • TIAN Fanglei, GUO Tonglou, HE Dengfa, GU Zhanyu, MENG Xianwu, WANG Renfu, WANG Ying, ZHANG Weikang, LU Guo
    Petroleum Exploration and Development, 2024, 51(3): 526-540. https://doi.org/10.11698/PED.20230635
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    With drilling and seismic data of Transtensional (strike-slip) Fault System in the Ziyang area of the central Sichuan Basin, through plane-section integrated structural interpretation, 3-D fault framework model building, fault throw analyzing, and balanced profile restoration, it is pointed out that the transtensional fault system in the Ziyang 3-D seismic survey consists of the northeast-trending FI19 and FI20 fault zones dominated by extensional deformation, as well as 3 sets of northwest-trending en echelon normal faults experienced dextral shear deformation. Among them, the FI19 and FI20 fault zones cut through the Neoproterozoic to Middle-Lower Triassic Jialingjiang Formation, presenting a 3-D structure of an “S”-shaped ribbon. And before Permian and during the Early Triassic, the FI19 and FI20 fault zones underwent at least two periods of structural superimposition. Besides, the 3 sets of northwest-trending en echelon normal faults are composed of small normal faults arranged in pairs, with opposite directions and partially left-stepped arrangement. And before Permian, they had formed almost, restricting the eastward growth and propagation of the FI19 fault zone. The FI19 and FI20 fault zones communicate multiple sets of source rocks and reservoirs from deep to shallow, and the timing of fault activity matches well with oil and gas generation peaks. If there were favorable Cambrian-Triassic sedimentary facies and reservoirs developing on the local anticlinal belts of both sides of the FI19 and FI20 fault zones, the major reservoirs in this area are expected to achieve breakthroughs in oil and gas exploration.

  • ZHANG Lei, CAO Qian, ZHANG Caili, ZHANG Jianwu, WEI Jiayi, LI Han, WANG Xingjian, PAN Xing, YAN Ting, QUAN Haiqi
    Petroleum Exploration and Development, 2024, 51(3): 541-552. https://doi.org/10.11698/PED.20230580
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    Based on the data of outcrop, core, logging, gas testing, and experiments, the natural gas accumulation and aluminous rock mineralization integrated research was adopted to analyze the controlling factors of aluminous rock series effective reservoirs in the Ordos Basin, NW China, as well as the configuration of coal-measure source rocks and aluminous rock series reservoirs. A natural gas accumulation model was constructed to evaluate the gas exploration potential of aluminous rock series under coal seam in the basin. The effective reservoirs of aluminous rock series in the Ordos Basin is composed of honeycomb-shaped bauxites with porous residual pisolitic and detrital structures, with the diasporite content of greater than 80% and dissolved pores as the main storage space. The bauxite reservoirs are formed under a model that planation controls the material supply, karst paleogeomorphology controls diagenesis, and land surface leaching improves reservoir quality. The hot humid climate and sea level changes in the Late Carboniferous-Early Permian dominated the development of a typical coal-aluminum-iron three-stage stratigraphic structure. The natural gas generated by the extensive hydrocarbon generation of coal-measure source rocks was accumulated in aluminous rock series under the coal seam, indicating a model of hydrocarbon accumulation under the source. During the Upper Carboniferous-Lower Permian, the relatively low-lying area on the edge of an ancient land or island in the North China landmass was developed. The gas reservoirs of aluminous rock series, which are clustered at multiple points in lenticular shape, are important new natural gas exploration fields with great potential in the Upper Paleozoic of North China Craton.

  • XIONG Wenjun, XIAO Lizhi, YUAN Jiangru, YUE Wenzheng
    Petroleum Exploration and Development, 2024, 51(3): 553-564. https://doi.org/10.11698/PED.20230460
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    In the traditional well log depth matching tasks, manual adjustments are required, which means significantly labor-intensive for multiple wells, leading to low work efficiency. This paper introduces a multi-agent deep reinforcement learning (MARL) method to automate the depth matching of multi-well logs. This method defines multiple top-down dual sliding windows based on the convolutional neural network (CNN) to extract and capture similar feature sequences on well logs, and it establishes an interaction mechanism between agents and the environment to control the depth matching process. Specifically, the agent selects an action to translate or scale the feature sequence based on the double deep Q-network (DDQN). Through the feedback of the reward signal, it evaluates the effectiveness of each action, aiming to obtain the optimal strategy and improve the accuracy of the matching task. Our experiments show that MARL can automatically perform depth matches for well-logs in multiple wells, and reduce manual intervention. In the application to the oil field, a comparative analysis of dynamic time warping (DTW), deep Q-learning network (DQN), and DDQN methods revealed that the DDQN algorithm, with its dual-network evaluation mechanism, significantly improves performance by identifying and aligning more details in the well log feature sequences, thus achieving higher depth matching accuracy.

  • XU Zhaohui, LI Jiangtao, LI Jian, CHEN Yan, YANG Shaoyong, WANG Yongsheng, SHAO Zeyu
    Petroleum Exploration and Development, 2024, 51(3): 565-577. https://doi.org/10.11698/PED.20230550
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    To solve the problems in restoring sedimentary facies and predicting reservoirs in loose gas-bearing sediment, based on seismic sedimentologic analysis of China’s first 9-component S-wave 3D seismic dataset, a fourth-order isochronous stratigraphic framework was set up and then sedimentary facies and reservoirs in the Pleistocene Qigequan Formation in Taidong area of Qaidam Basin were studied by seismic geomorphology and seismic lithology. The study method and thought are as following. Firstly, techniques of phase rotation, frequency decomposition and fusion, and stratal slicing were applied to the 9-component S-wave seismic data to restore sedimentary facies of major marker beds based on sedimentary models reflected by satellite images. Then, techniques of seismic attribute extraction, principal component analysis, and random fitting were applied to calculate the reservoir thickness and physical parameters of a key sandbody, and the results are satisfactory and confirmed by blind testing wells. Study results reveal that the dominant sedimentary facies in the Qigequan Formation within the study area are delta front and shallow lake. The RGB fused slices indicate that there are two cycles with three sets of underwater distributary channel systems in one period. Among them, sandstones in the distributary channels of middle-low Qigequan Formation are thick and broad with superior physical properties, which are favorable reservoirs. The reservoir permeability is also affected by diagenesis. Distributary channel sandstone reservoirs extend further to the west of Sebei-1 gas field, which provides a basis to expand exploration to the western peripheral area.

  • SONG Xinmin, LI Yong, LI Fengfeng, YI Liping, SONG Benbiao, ZHU Guangya, SU Haiyang, WEI Liang, YANG Chao
    Petroleum Exploration and Development, 2024, 51(3): 578-587. https://doi.org/10.11698/PED.20240112
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    Based on the waterflooding development in carbonate reservoirs in the Middle East, in order to solve the problem of the poor development effects caused by commingled injection and production, taking the thick bioclastic limestone reservoirs of Cretaceous in Iran-Iraq as an example, this paper proposes a balanced waterflooding development technology for thick and complex carbonate reservoirs. This technology is based on the fine division of development units by concealed baffles and barriers, the combination of multi well type and multi well pattern, and the construction of balanced water injection and recovery system. For the thick carbonate reservoirs in Iran and Iraq, which are extremely heterogeneous vertically with ultra-high permeability zones of various genesis, and highly concealed baffles and barriers, based on the technologies of identification characterization and sealing evaluation for concealed baffles and barriers, the balanced waterflooding development technology is proposed, and three types of balanced waterflooding development modes/techniques are formed, namely, conventional stratigraphic framework, fine stratigraphic framework, and deepened stratigraphic framework. Numerical simulations show that this technology is able to realize a fine and efficient waterflooding development to recover, in a balanced manner, the reserves of thick and complex carbonate reservoirs in Iran and Iraq. The proposed technology provides a reference for the development optimization of similar reservoirs.

  • JIANG Tingxue, SHEN Ziqi, WANG Liangjun, QI Zili, XIAO Bo, QIN Qiuping, FAN Xiqun, WANG Yong, QU Hai
    Petroleum Exploration and Development, 2024, 51(3): 588-596. https://doi.org/10.11698/PED.20230275
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    An optimization method of fracturing fluid volume strength was introduced taking well X-1 in Biyang Sag of Nanxiang Basin as an example. The characteristic curves of capillary pressure and relative permeability were obtained from history matching between forced imbibition experimental data and core-scale reservoir simulation results and taken into a large scale reservoir model to mimic the forced imbibition behavior during the well shut-in period after fracturing. The optimization of the stimulated reservoir volume (SRV) fracturing fluid volume strength should meet the requirements of estimated ultimate recovery (EUR), increased oil recovery by forced imbibition and enhancement of formation pressure and the fluid volume strength of fracturing fluid should be controlled around a critical value to avoid either insufficiency of imbibition displacement caused by insufficient fluid amount or increase of costs and potential formation damage caused by excessive fluid amount. Reservoir simulation results showed that SRV fracturing fluid volume strength positively correlated with single-well EUR and a optimal fluid volume strength existed, above which the single-well EUR increase rate kept decreasing. An optimized increase of SRV fracturing fluid volume and shut-in time would effectively increase the formation pressure and enhance well production. Field test results of well X-1 proved the practicality of established optimization method of SRV fracturing fluid volume strength on significant enhancement of shale oil well production.

  • TANG Huiying, LUO Shangui, LIANG Haipeng, ZENG Bo, ZHANG Liehui, ZHAO Yulong, SONG Yi
    Petroleum Exploration and Development, 2024, 51(3): 597-607. https://doi.org/10.11698/PED.20230674
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    Based on the displacement discontinuity method and the discrete fracture unified pipe network model, a sequential iterative numerical method was used to construct a fracturing-production integrated numerical model of shale gas well considering the two-phase flow of gas and water. The model accounts for the influence of natural fractures and matrix properties on the fracturing process and directly applies post-fracturing formation pressure and water saturation distribution to subsequent well shut-in and production simulation, allowing for a more accurate fracturing-production integrated simulation. The results show that the reservoir physical properties have great impacts on fracture propagation, and the reasonable prediction of formation pressure and reservoir fluid distribution after the fracturing is critical to accurately predict the gas and fluid production of the shale gas wells. Compared with the conventional method, the proposed model can more accurately simulate the water and gas production by considering the impact of fracturing on both matrix pressure and water saturation. The established model is applied to the integrated fracturing-production simulation of actual horizontal shale gas wells, yielding the simulation results in good agreement with the actual production data, thus verifying the accuracy of the model.

  • WANG Chunsheng, MING Chuanzhong, ZHANG Hao, CHEN Jialei, QU Hao, WANG Wenchang, DI Qinfeng
    Petroleum Exploration and Development, 2024, 51(3): 608-615. https://doi.org/10.11698/PED.20240057
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    Based on the three-dimensional elastic-plastic finite element analysis of the 8" (203.2 mm) drill collar joint, this paper studies the mechanical characteristics of the pin and box of NC56 drill collar joints under complex load conditions, as well as the downhole secondary makeup features, and calculates the downhole equivalent impact torque with the relative offset at the shoulder of internal and external threads. On the basis of verifying the correctness of the calculation results by using measured results in Well GT1, the prediction model of the downhole equivalent impact torque is formed and applied in the first extra-deep well with a depth over 10 000 m in China (Well SDTK1). The results indicate that under complex loads, the stress distribution in drill collar joints is uneven, with relatively higher von Mises stress at the shoulder and the threads close to the shoulder. For 203.2 mm drill collar joints pre-tightened according to the make-up torque recommended by American Petroleum Institute standards, when the downhole equivalent impact torque exceeds 65 kN·m, the preload balance of the joint is disrupted, leading to secondary make-up of the joint. As the downhole equivalent impact torque increases, the relative offset at the shoulder of internal and external threads increases. The calculation results reveal that there exists significant downhole impact torque in Well SDTK1 with complex loading environment. It is necessary to use double shoulder collar joints to improve the impact torque resistance of the joint or optimize the operating parameters to reduce the downhole impact torque, and effectively prevent drilling tool failure.

  • GUO Jianchun, REN Shan, ZHANG Shaobin, DIAO Su, LU Yang, ZHANG Tao
    Petroleum Exploration and Development, 2024, 51(3): 616-623. https://doi.org/10.11698/PED.20230649
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    Fiber is highly escapable in conventional slickwater, making it difficult to form fiber-proppant agglomerate with propppant and exhibit limited effectiveness. To solve these problems, a novel structure stabilizer (SS) is developed. Through microscopic structural observations and performance evaluations in indoor experiments, the mechanism of proppant placement under the action of the SS and the effects of the SS on proppant placement dimensions and fracture conductivity were elucidated. The SS facilitates the formation of robust fiber-proppant agglomerates by polymer, fiber, and quartz sand. Compared to bare proppants, these agglomerates exhibit reduced density, increased volume, and enlarged contact area with the fluid during settlement, leading to heightened buoyancy and drag forces, ultimately resulting in slower settling velocities and enhanced transportability into deeper regions of the fracture. Co-injecting the fiber and the SS alongside the proppant into the reservoir effectively reduces the fiber escape rate, increases the proppant volume in the slickwater, and boosts the proppant placement height, conveyance distance and fracture conductivity, while also decreasing the proppant backflow. Experimental results indicate an optimal SS mass fraction of 0.3%. The application of this SS in over 80 wells targeting tight gas, shale oil, and shale gas reservoirs has substantiated its strong adaptability and general suitability for meeting the production enhancement, cost reduction, and sand control requirements of such wells.

  • ZOU Yushi, LI Yanchao, YANG Can, ZHANG Shicheng, MA Xinfang, ZOU Longqing
    Petroleum Exploration and Development, 2024, 51(3): 624-634. https://doi.org/10.11698/PED.20240042
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    This study conducted temporary plugging and diversion fracturing (TPDF) experiments using a true triaxial fracturing simulation system within a laboratory setting that replicated a lab-based horizontal well completion with multi-cluster sand jetting perforation. The effects of temporary plugging agent (TPA) particle size, TPA concentration, single-cluster perforation number and cluster number on plugging pressure, multi-fracture diversion pattern and distribution of TPAs were investigated. A combination of TPAs with small particle sizes within the fracture and large particle sizes within the segment is conducive to increasing the plugging pressure and promoting the diversion of multi-fractures. The addition of fibers can quickly achieve ultra-high pressure, but it may lead to longitudinal fractures extending along the wellbore. The temporary plugging peak pressure increases with an increase in the concentration of the TPA, reaching a peak at a certain concentration, and further increases do not significantly improve the temporary plugging peak pressure. The breaking pressure and temporary plugging peak pressure show a decreasing trend with an increase in single-cluster perforation number. A lower number of single-cluster perforations is beneficial for increasing the breaking pressure and temporary plugging peak pressure, and it has a more significant control on the propagation of multi-cluster fractures. A lower number of clusters is not conducive to increasing the total number and complexity of artificial fractures, while a higher number of clusters makes it difficult to achieve effective plugging. The TPAs within the fracture is mainly concentrated in the complex fracture areas, especially at the intersections of fractures. Meanwhile, the TPAs within the segment is primarily distributed near the perforation cluster apertures which initiated complex fractures.

  • LYU Weifeng, LI Yushu, WANG Mingyuan, LIN Qianguo, JIA Ninghong, JI Zemin, HE Chang
    Petroleum Exploration and Development, 2024, 51(3): 635-645. https://doi.org/10.11698/PED.20240143
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    This paper systematically reviews the current applications of various spatial information technologies in CO2 sequestration monitoring, analyzes the challenges faced by spatial information technologies in CO2 sequestration monitoring, and prospects the development of spatial information technologies in CO2 sequestration monitoring. Currently, the spatial information technologies applied in CO2 sequestration monitoring mainly include five categories: eddy covariance method, remote sensing technology, geographic information system, Internet of Things technology, and global navigation satellite system. These technologies are involved in three aspects: monitoring data acquisition, positioning and data transmission, and data management and decision support. Challenges faced by the spatial information technologies in CO2 sequestration monitoring include: selecting spatial information technologies that match different monitoring purposes, different platforms, and different monitoring sites; establishing effective data storage and computing capabilities to cope with the broad sources and large volumes of monitoring data; and promoting collaborative operations by interacting and validating spatial information technologies with mature monitoring technologies. In the future, it is necessary to establish methods and standards for designing spatial information technology monitoring schemes, develop collaborative application methods for cross-scale monitoring technologies, integrate spatial information technologies with artificial intelligence and high-performance computing technologies, and accelerate the application of spatial information technologies in carbon sequestration projects in China.

  • ZHAO Peng, ZHU Haiyan, LI Gensheng, CHEN Zuo, CHEN Shijie, SHANGGUAN Shuantong, QI Xiaofei
    Petroleum Exploration and Development, 2024, 51(3): 646-654. https://doi.org/10.11698/PED.20230592
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    Based on the independently developed true triaxial multi-physical field large-scale physical simulation system of in-situ injection and production, we conducted physical simulation on the long-term injection and production of multiple wells in the hot dry rocks in the Gonghe Basin of Qinghai Province, NW China. By virtue of multi-well connectivity experiments, the spatial distribution characteristics of the natural fracture system in the rock samples and the connectivity between fracture and wellbore were clarified. The injection and production wells were selected to conduct the experiments, namely one injection well and two production wells, one injection well and one production well. The variation of several physical parameters in the production well was analyzed, such as the flow rate, the temperature, the heat recovery rate and the fluid recovery. The results show that under the combination of thermal shock and injection pressure, the fracture conductivity was enhanced, and the production temperature showed a downward trend. The larger the flow rate, the faster the decrease. When the local closed area of the fracture was gradually activated, new heat transfer areas were generated, resulting in a lower rate of increase or decrease in the mining temperature. The heat recovery rate was mainly controlled by the extraction flow rate and the temperature difference between injection and production fluid. As the conductivity of the leak-off channel increased, the fluid recovery of the production well rapidly decreased. The influence mechanisms of dominant channels and fluid leak-off on thermal recovery performance are different. The former limits the heat exchange area, while the latter affects the flow rate of the produced fluid. Both of them are important factors affecting the long-term and efficient development of hot dry rock.

  • FENG Ziqi, HAO Fang, HU Lin, HU Gaowei, ZHANG Yazhen, LI Yangming, WANG Wei, LI Hao, XIAO Junjie, TIAN Jinqiang
    Petroleum Exploration and Development, 2024, 51(3): 655-666. https://doi.org/10.11698/PED.20230686
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    Based on the geochemical parameters and analytical data, the heat conservation equation, mass balance law, Rayleigh fractionation model and other methods were used to quantify the in-situ yield and external flux of crust-derived helium, and the initial He concentration and thermal driving mechanism of mantle-derived helium, in the Ledong Diapir area, the Yinggehai Basin, in order to understand the genetic source and migration & accumulation mechanisms of helium under deep hydrothermal fluid activities. The helium in the Ledong diapir area is primarily derived from the crust and a small amount from the mantle. For mantle-derived helium, the 3He/4He values are (0.002-2.190)×10-6, the R/Ra values are 0.01-1.52, and the contribution is estimated to be 0.09%-19.84%, suggesting a relatively small percentage. In contrast, the contribution of crust-derived helium is more than 80%. For crust-sourced helium, the in-situ 4He yield is only (4.10-4.25)×10-4 cm3/g, while the external 4He flux is significantly high, being (5.84-9.06)×10-2 cm3/g, indicating that crust-sourced helium is dominated by external input, which is speculated to be related to atmospheric recharge of formation fluids and deep rock-water interaction. Deep hydrothermal fluid in the diapir area significantly affects the geothermal field. The ratio of the initial mass volume of 3He to the corresponding enthalpy (W) is (0.006-0.018)×10?11 cm3/J, and the thermal contribution from the deep mantle (XM) is between 7.63% and 36.18%, suggesting that the diapir thermal fluid plays a certain role in driving the migration of mantle-sourced 3He. The primary migration of helium in the study area is dominated by advection, and the secondary migration is controlled by hydrothermal degassing and gas-liquid separation. During the migration of helium from deep to shallow, the CO2/3He value increases from 1.34×109 to 486×109, indicating the large-scale precipitation of CO2 and apparent escape of 3He due to the effect of crust-mantle mixing and degassing. Under the influence of deep hydrothermal fluid, the migration and accumulation mechanisms of helium include: deep heat driven diffusion, advection release, vertical hydrothermal degassing; shallow lateral migration, accumulation in traps far from faults; partial pressure balance, complete cover sealing; and so on.

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