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Deep coalbed methane resource and its exploration and development prospect in East China
SANG Shuxun,HAN Sijie,ZHOU Xiaozhi,LIU Shiqi,WANG Yuejiang
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 403-415.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.001
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Deep coalbed methane(CBM) development in East China is of great significance to ensure regional energy demand, optimize regional energy structure and realize the dual carbon goal. Based on the systematic investigation and previous works, the current situations of CBM extraction in East China were summarized, and the gas-bearing attributes and resources potential of deep CBM were analyzed. Then, the applicability of existing deep CBM exploration and development technologies in East China was discussed, and the potential favorable areas of deep CBM exploration and development in East China were discussed and predicted. Finally, the advantages and challenges of deep CBM exploration and development in East China are put forward. Previous results show that: East China has a good CBM development accumulation on the tectonically deformed coal and in the coal mine area, such as “Huainan CBM extraction model” and horizontal well staged fracturing in the roof of the tectonically deformed coal. Deep coal in East China has a high gas content(greater than10 cm3/g) and gas-bearing saturation(greater than 80 %). The predicted geological resources of deep CBM are 8 984.69×108 m3 in the Huannan-Huanbei mining area, suggesting that Huainan and Huaibei coal field has an attractive deep CBM resources potential. Horizontal well development and hydraulic fracturing techniques for deep CBM have great application prospects in East China. Panxie mine area in Huainan coal field is expected to be a pilot area for deep CBM exploration and development in these areas. However, the overall exploration and development degree of deep CBM is low, so it is necessary to carry out the more detailed resource evaluation and analysis of deep CBM geological accumulation in the type area, like deep Panxie coal mine in Huainan coal field.

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China's CCUS technology challenges and countermeasures under “double carbon” target
YE Xiaodong,CHEN Jun,CHEN Xi,WANG Haimei,WANG Huijun
Petroleum Reservoir Evaluation and Development    2024, 14 (1): 1-9.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.01.001
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Carbon Capture, Utilization, and Storage(CCUS) technology is pivotal for global carbon emissions reduction and plays a crucial role in ensuring China's energy security and fostering the concurrent growth of its economy. It also supports China's path towards sustainable development and ecological advancement. While significant strides have been made in CCUS technology within China, challenges persist that hinder its widespread adoption. Based on literature research and work accumulation, the current status of CCUS technology both domestically and internationally is described, and the current technical challenges and research directions that CCUS technology are pointed out. The existing research efforts have provided countermeasures to address the challenges of high energy consumption and cost of capture technologies, the need for further research on oil recovery and storage technologies, the high energy consumption and low conversion efficiency of chemical utilization technologies, and the lack of a technical system for monitoring and evaluating the safety of storage. These countermeasures are as follows: ①Diversified integration of different carbon capture methods to achieve cost reduction at the source based on the characteristics of different emission sources; ②Tackling multi-objective optimization techniques, coordinating and optimizing oil recovery efficiency and CO2 storage rate; ③Continuously developing new catalysts to accelerate the conversion reaction of CO2 and improve conversion efficiency; ④Fully draw on the carbon tax policies of countries such as the United States and Australia, explore fiscal and tax incentive policies suitable for China's CCUS industry, increase economic benefits, and enhance enterprise enthusiasm; ⑤Establish a series of standard specifications covering all aspects of the CCUS entire chain, guide the implementation of engineering construction, and reduce enterprise risks from a standardized perspective. Through the implementation of these measures, the rapid development of CCUS technology in China will be promoted, and greater contribution will be made to achieving the goal of carbon neutrality.

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Development practices of geology-engineering integration in complex structural area of Nanchuan normal pressure shale gas field
YAO Hongsheng, WANG Wei, HE Xipeng, ZHENG Yongwang, NI Zhenyu
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 537-547.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.001
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The normal pressure shale gas reservoir within the complex structural belt of Nanchuan has been subject to the influences of multiple tectonic movements. The geological conditions in this region exhibit a high degree of complexity, thereby amplifying the challenges associated with efficient resource extraction. In response, an integrated geological engineering approach, tailored to the unique geological attributes of normal pressure shale gas in the intricate structural belt of Nanchuan, has been devised. This approach is aimed at mitigating challenges such as low rates of drilling in “sweet spots”, reduced mechanical drilling speeds, and suboptimal outcomes in fracturing transformations stemming from the intricacies of geological reservoir structures. In pursuit of optimizing the development of normal shale gas resources, a comprehensive investigation was undertaken, leveraging interdisciplinary knowledge spanning geophysical exploration, geology, drilling and completion, and fracturing techniques. An integrated process was established, fostering collaborative problem-solving and the mutual enrichment of geological and engineering insights. At its core, this approach emphasizes the synergy between geophysical exploration, geology, and engineering, thereby forming a pivotal development technology tailored for normal pressure shale gas reservoirs within complex structural zones. Through practical field applications, notable enhancements have been achieved. Mechanical drilling speeds and the rate of target window drilling in complex structural areas have witnessed significant improvements. Concurrently, the costs associated with fracturing operations have been consistently reduced, yielding improved gas well fracturing outcomes and enhanced productivity. These advancements collectively culminate in the efficient development of the Nanchuan normal shale gas field. Furthermore, they offer invaluable technological insights and experiential wisdom for the efficient extraction of normal shale gas reservoirs in the intricate regions of southeastern Chongqing.

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Petroleum Reservoir Evaluation and Development    2024, 14 (1): 0-.  
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Petroleum Reservoir Evaluation and Development    2024, 14 (2): 0-.  
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Effect of rock-soil stratification on the heat transfer performance of U-shaped butted well in medium-deep layers
GAO Xiaorong, LI Hongyan, REN Xiaoqing, SUN Caixia, LU Xingchen, LIU Lin, LYU Qiangqiang, XU Yong, DONG Wenbin, WANG Zemu, WANG Rongkang, MIAO Ruican
Petroleum Reservoir Evaluation and Development    2023, 13 (6): 703-712.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.06.001
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The medium-deep geothermal exchanger featuring a U-shaped pipe configuration presents an optimal solution for geothermal energy heat exchange due to its capability to deliver higher temperature water, achieve greater heat extraction rates, and maintain minimal flow resistance. A layered analytical model for such exchanger is established based on the theory of thermal resistance in series methods. Experimental results are employed to validate the accuracy of this layered analytical model. By focusing on the Guanzhong Basin in Shaanxi Province as the focal point of research, the model investigates the influence of subterranean stratification in thermal conductivity and volumetric specific heat on the outlet water temperature and heat extraction rate throughout an entire heating period for a 3 000 m deep geothermal exchanger with U-shaped pipe. The findings reveal that the underground thermal conductivity stratification has a significant impact on the heat transfer performance. A simplistic approach using average thermal conductivity, as opposed to a detailed accounting of layered conductivities, results in an overestimation of outlet water temperature and heat extraction rate by approximately 6 % to 15 %. However, specific heat stratification exerts minimal influence on the subterranean heat transfer dynamics. This underscores the importance of considering the effects of underground thermal property stratification in the design and analysis of the heat transfer performance of a medium-deep geothermal exchanger with U-shaped pipe. For precise modeling and results, it is recommended to segment the underground area into at least eight distinct layers.

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Research progress of evaluation of CO2 storage potential and suitability assessment indexes in saline aquifers
ZHAO Yulong, YANG Bo, CAO Cheng, ZHANG Liehui, ZHOU Xiang, HUANG Chenzhi, RUI Yiming, LI Jinlong
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 484-494.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.010
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CO2 storage in saline aquifers is one of the feasible technical deployment schemes, and it is also the main approach to reduce CO2 emission in the medium and long term. To meet the assessment requirements of the storage potential in saline aquifers, four CO2 geological storage mechanisms are systematically expounded. Based on the storage mechanism, an evaluation index system for the suitability of CO2 geological storage in saline aquifers is established, including four evaluation index layers of safety, technology, economy, and social environment. The weight of each evaluation index factor is calculated using the analytic hierarchy process. For saline aquifers with an open structure and rich hydrogeology, it is recommended to consider the combination of residual trapping and solubility trapping to evaluate CO2 storage potential. The CO2 geological storage suitability evaluation index system of saline aquifers provides a reference for conducting the national CO2 storage suitability evaluation.

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Types of fine-grained sedimentary rocks assemblage and its significance for shale oil exploration: A case study of the fifth member of Xujiahe Formation in western Sichuan Depression, Sichuan Basin
XIONG Liang, CAO Qinming, ZHANG Ling, WANG Linghui
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 548-558.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.002
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Due to the complex lithology of fine-grained sedimentary rocks and the difficulty to determine the “sweet spot” of the fifth member of Xujiahe Formation(short for Xu-5 Member) of western Sichuan Depression, Sichuan Basin, a comprehensive geological analysis was conducted. This analysis encompassed various geological data sources, including X-ray diffraction, thin sections, scanning electron microscopy, physical properties, organic carbon content, and elemental analysis. Additionally, core observations were incorporated into the study. Upon scrutinizing this array of data, a classification of 14 distinct lithofacies types was established. This categorization was formulated based on the analysis of lithofacies and the evolution of sedimentary paleoenvironments. Furthermore, through a comparative examination of shale gas evaluation parameters, the primary lithofacies types constituting the “sweet spots” were identified. This not only sheds light on the composition of Xu-5 Member but also provides valuable guidance for the exploration of continental shale gas within this formation. The results indicate that: ①The main lithofacies of Xu-5 Member in western Sichuan Depression are massive clayey siltstone and massive mixed sedimentary rock, followed by laminated mixed sedimentary rock, laminated clayey siltstone and massive silty clay rock; ②The sedimentary paleoenvironment of Xu-5 Member undergoes the process from dry heat sedimentary with shallow brackish water to wet sedimentary with deep fresh water, then back to dry heat sedimentary with shallow brackish water. The land source input decreases first and then increases. The middle part of Xu-5 Member is the “sweet spot” for the enrichment of organic matter. ③Laminated clayey siltstone and laminated mixed sedimentary rock are favorable lithofacies types for “sweet spot” development due to the high organic matter content, debris particle dissolution pore, high content of brittle minerals and good fracturing performance.

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Application of machine deep learning technology in tight sandstones reservoir prediction: A case study of Xujiahe Formation in Xinchang, western Sichuan Depression
QIAN Yugui
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 600-607.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.007
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The second member of Xujiahe Formation in Xinchang western Sichuan Depression, a tight sandstone reservoir, exhibits strong heterogeneity and thin reservoir characteristics. Previous interpretations of lithology and reservoir properties obtained directly through seismic attributes and inversion techniques were limited by individual understanding and interpretation accuracy. Consequently, the interpretation results often fell short of meeting the requirements for detailed reservoir development in gas fields.To address these challenges, a novel approach was implemented. Sensitivity parameters related to pre-stack lithology and reservoir properties were used as learning samples. Pre-stack inversion techniques were combined with machine deep learning algorithms to construct an interpretation model. This innovative method ultimately achieved quantitative predictions of sandstone thickness and reservoir properties. This method not only improves the resolution of reservoir prediction, but also greatly improves the prediction accuracy. The prediction results provide effective support for sedimentary microfacies research, reservoir formation analysis, and well location deployment, and have achieved good application results in the development of the second member gas reservoir of Xujiahe Formation in Xinchang. This article introduces a new interpretation approach for quantitative prediction of lithology and reservoirs, and serves as a valuable reference for gas field development in other regions.

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Numerical simulation study on the influence of coal rock fracture morphology on seepage capacity
SHI Leiting, ZHAO Qiming, REN Zhenyu, ZHU Shijie, ZHU Shanshan
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 424-432.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.003
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The fracture network developed in coal rock serves as the primary channel for gas migration, significantly influencing the seepage capacity of coal reservoir. The geometric characteristics of fracture plays a crucial role on determining the flow characteristics of coal-bed methane. To study this, a two-dimensional fracture network model of coal rock was established using COMSOL Multiphysics simulation software, focusing on the coal samples of Baode block as the research subject. The effects of fracture length, density, opening degree and angle on production were investigated, providing valuable theoretical guidance for enhancing coal-bed methane production. The results indicate that fracture length, density, and opening degree have a positive correlation with the seepage capacity of coal rock, while the angle with the flow direction negatively impacts it. However, with the increase of length, density and opening degree, the improvement in flow rate slows down, and the effect of increasing single factor to improve coal-bed methane mining can be neglected, making it difficult to control the cost-benefit ratio. Among the factors influencing outlet, angle and density exert a more significant effect than length and opening degree. Considering the surface directional well plus the high pressure hydraulic cutting method, we can enhance the efficiency of coalbed methane development. This approach connects the natural fracture system using directional borehole and hydraulic slot, fully utilizing the permeability advantage of parallel surface cutting direction. The high-pressure hydraulic cutting process induces cracks in the coal seam, increasing the number and connectivity of diversion channels, thereby bolstering the production of coal-bed methane.

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Question and comment for FETKOVICH’s typical curve
CHEN Yuanqian,WANG Xin,LIU Yang,SHI Xiaomin
Petroleum Reservoir Evaluation and Development    2024, 14 (2): 159-166.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.02.001
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FETKOVICH proposed the water influx rate equation in finite aquifer and the type curve with constant pressure in 1971 and 1980 respectively, which have been widely recognized and cited by experts both domestically and internationally. His methodology allows for the determination of a well's drainage radius and area by fitting actual production data to his type curve, a technique that has gained popularity among field experts. The derivation of this paper shows that the equation for water influx rate equation in finite aquifer of FETKOVICH is an is characterized by an exponential decline, a model he directly applied to analyze production declines in wells with volumetrically closed boundaries. He derived a dimensionless time for the type curve based on the relationship with the initial decline rate and used the inverse of dimensionless pressure as a proxy for dimensionless production to develop the type curve's dimensionless production profile. However, it's important to note that FETKOVICH's model does not establish a direct functional relationship between dimensionless time and dimensionless production in the type curve model, which means that a comprehensive dimensionless type curve cannot be formulated directly from his equations. This article deduces the water influx rate equation in finite aquifer and the dimensionless time and dimensionless production of the type curve, and questioned and commented on the existing problems.

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Key engineering technologies of one-million-ton CCUS transportation-injection-extraction in Shengli Oilfield
SHU Huawen
Petroleum Reservoir Evaluation and Development    2024, 14 (1): 10-17.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.01.002
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CCUS technology is a crucial technology for achieving the goal of “dual carbon”, involving process such as capture, transportation, injection, extraction and re-injection. Shengli Oilfield has developed essential engineering technologies for transportation and injection through years of exploration. To manage the phase changes of CO2 and the risks of long-distance leakage due to pressure loss and temperature variations, a safety transportation technology for long-distance CO2 pipelines was established. This technology is based on phase state control, ensuring efficient and cost-effective transportation. developed China’s first casing pipeline transport pump; and built China’s longest long-distance supercritical pressure CO2 pipeline, which makes up for the shortcomings of the long-distance CO2 transport in China. In order to meet the needs of high-pressure injection of large-displacement CO2 in the demonstration project, China’s first high-pressure dense-phase injection pump has been developed, realizing high-pressure dense-phase injection of 40 MPa. In view of the problems of high injection pressure, high gas-to-liquid ratio, low pumping efficiency, and corrosion of CO2, the engineering process technology of injection and extraction supporting such as safe injection of gas pipeline columns for pressure-free wells, multi-functional oil recovery pipeline columns, and corrosion prevention of CO2 repulsion has been formed to realize high-efficiency, safe injection and extraction and long-lasting corrosion protection. China's first multi-field, multi-node, one-million-ton CCUS demonstration project integrating pipeline transport engineering, injection equipment, flooding and sequestration, injection-extraction process, and gathering-transmission and re-injection, has been operating well and realizing “smooth, safe, efficient and green” operation in all aspects. This summary of the one-million-ton CCUS transportation-injection-extraction process and supporting equipment in Shengli Oilfield is intended to provide reference and guidance for the construction of subsequent CCUS project.

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Petroleum Reservoir Evaluation and Development    2023, 13 (4): 0-0.  
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A model for shale gas well production prediction based on improved artificial neural network
LIN Hun, SUN Xinyi, SONG Xixiang, MENG Chun, XIONG Wenxin, HUANG Junhe, LIU Hongbo, LIU Cheng
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 467-473.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.008
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Traditional methods for predicting shale gas well production often struggle to effectively analyze the complex relationship between reservoir parameters, fracturing parameters and production. To address these challenges, a novel approach is introduced, involving the construction of characteristic parameters based on physical meaning and random combination. The small batch gradient descent method(MBGD) is adopted as the training function to develop an improved artificial neural network prediction model for shale gas well production. An example is utilized to demonstrate the effectiveness of the improved artificial neural network model in predicting shale gas well production. The model’s performance is evaluated using the mean squared error(MSE) and the modified determination coefficient(T). The results indicate that the predictions from the improved network model align well with the actual production data. Moreover, the model exhibits superior prediction accuracy and stability compared to the traditional BP(error backpropagation algorithm) neural network model. With its high accuracy and reliability, the proposed model can provide valuable support for fracturing optimization design and productivity evaluation in shale gas reservoirs.

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Quantitative evaluation system of geothermal resources based on analytic hierarchy process: A case study of middle-deep hydrothermal sandstone reservoir in Caofeidian of Hebei Province
HE Dongbo, REN Lu, HAO Jie, LIU Xiaoping, CAO Qian
Petroleum Reservoir Evaluation and Development    2023, 13 (6): 713-725.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.06.002
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To quantitatively assess the quality of deep hydrothermal geothermal resources in the target area, with a focus on middle-deep hydrothermal resources in sedimentary basins, a comprehensive analysis is conducted. This analysis delves into the effects of geothermal geological conditions, the nature of the geothermal resources themselves, and the quality of geothermal fluids on the overall resource quality. For this assessment, sixteen indicators that significantly impact the quality of geothermal resources are identified. These indicators are then incorporated into an Analytic Hierarchy Process(AHP) framework, which assigns weights to each indicator, facilitating a quantitative evaluation. The middle-deep hydrothermal geothermal resources are divided into three levels and seven categories. Level Ⅰ areas are resource advantage areas that can be efficiently developed; Level Ⅱ areas are resource rich areas that meet the requirements of industrial development; Level Ⅲ areas are resource non enriched areas. Ultimately, a quantifiable resource evaluation system is formed to provide data analysis conclusions on whether geothermal resources can be utilized. The relevance and practicality of this evaluation system are demonstrated through its application in a case study. The example of geothermal development and usage in the Caofeidian District of Tangshan City, Hebei Province, serves as a testament to the system's effectiveness in guiding decision-making processes for geothermal resource utilization.

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Prestack seismic prediction of sandstone reservoirs in the fifth member of Xujiahe Formation in Dongfengchang area of Ziyang
ZHENG Gongying, LYU Qibiao, YANG Yongjian, XU Shoucheng
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 569-580.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.004
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In the Dongfengchang area of Ziyang, the fifth member of Xujiahe Formation exhibits multiple phase of superimposed channels with rapid facies changes in the channel sandstones. The reservoirs are highly heterogeneous, with minimal differences in impedance between sandstones and mudstones. The seismic response characteristics of the reservoirs are multifaceted. Additionally, the pre-stack seismic data quality is suboptimal, compounded by an absence of shear wave logging data. In the preliminary stages, conventional post-stack attributes were used to characterize the boundaries of channel sand bodies and the distribution of high-quality reservoirs, but the accuracy of this characterization was limited. To address the mentioned challenges, high-quality pre-stack seismic data was obtained through noise suppression, data flattening, and optimal frequency enhancement techniques. An improved XU-WHITE model-based approach was utilized to predict shear wave velocities. Innovative indicators based on rock physics analysis were developed, and a seismic prediction volume for lithology and reservoir properties was obtained through simultaneous inversion of three pre-stack parameters. This approach allowed for a detailed characterization of sand body boundaries and distribution. In favorable facies zones, using property prediction attributes, the distribution of “sweet spots” within tight sandstone reservoirs was predicted. The research results indicate the following: ①High-fidelity pre-stack data optimization processing provides reliable and AVO-compliant pre-stack data, establishing a solid foundation for subsequent pre-stack inversion; ②The improved XU-WHITE model-based shear wave velocity prediction technique yields more accurate shear wave velocities, which are beneficial for rock physics analysis; ③The construction and inversion techniques of lithology and physical property indicator factors are effective in achieving a precise characterization of the lithology and physical properties of tight sandstone reservoirs. This technology has shown promising results in characterizing the tight sandstone reservoirs and predicting “sweet spots” in the Xujiahe Formation gas reservoirs in Ziyang. It holds potential for broader applications in similar geological settings.

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Origin of “cake-like” fractures and its significance for gas exploration in the second member of Xujiahe Formation of Xinchang structural belt
YAN Lini, ZHU Hongquan, YE Sujuan, ZHU Li
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 559-568.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.003
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A distinct category of fractures, characterized by a substantial proportion, shallow angle, and contentious origin, commonly referred to n as “cake-like” fractures or “laminar cake” fractures within the second member of Xujiahe Formation of Xinchang structural belt, has been chosen as the research target. This study employs meticulous core observation, precise thin section analysis, and a comprehensive comparative assessment of both macroscopic and microscopic traits. The primary objective is to classify these “cake-shaped” fractures for the first time and elucidate their corresponding lithofacies attributes and genesis. The discussion regarding the oil and gas geological significance of these “cake-like” fractures is rooted in the distinctions in gas-bearing properties. The analysis reveals the presence of three distinct types of “cake-like” fractures: thin layer “shortcake” fractures, medium-thick layer unequal spacing fractures and medium-thick layer isometric fractures. The thin layer “shortcake” fractures manifest within isolated distributary channels with coarse-grained textures and a high quartz composition. Conversely, the medium-thick layer unequal distance fractures are evident in interbedded distributary channels exhibiting fine, medium-grained, and coarse-grained textures with a notable feldspar content. The medium-thick layer isometric fractures occur within distributary channels or estuarine bar resulting from the deposition of alternating fine and medium-grained calcareous-rich sand and calcareous-poor sand. The initial two fracture types can not only improve reservoir permeability, but also intensify the dissolution effect, leading to higher gas content, while the latter type only increases the permeability and has a limited impact on the matrix pores, resulting in lower gas content. The “cake-like” fracture phenomenon represents a composite fracture formation influenced by sedimentary environment, tectonic stress, and differential diagenesis. It defies a simple classification as a tectonic shear fracture, sedimentary bedding fracture, or stress unloading fracture. The areas with high structural position, well-developed pie fractures and favorable reservoir properties, augmented by effective fracture network fracturing technology, present promising prospects for future exploration endeavors.

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Development characteristics of fractures in the second member of Xujiahe Formation in Hexingchang Gas Field, western Sichuan Depression and their main control factors of formation: A case study of Hexingchang Gas Field
ZHANG Zhuang, ZHANG Shunli, HE Xiubin, XIE Dan, LIU Yanhua
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 581-590.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.005
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The Hexingchang gas field of the western Sichuan Depression is an ultra-low porosity and ultra-low permeability tight sandstone reservoir, with well-developed and diverse types of fractures. The degree of fracture development plays a pivotal role in influencing on the migration, reservoir formation, and productivity of natural gas. In order to guide the exploration and development of the area, a comprehensive study was conducted to examine the development characteristics and underlying factors controlling fractures within the second member of Xujiahe Formation. This investigation drew upon a range of analytical techniques, including core observation, thin section analysis, imaging logging, and the examination of fracture filling inclusions. The fractures in the research area can be divided into three categories based on their genesis: structural fractures, diagenetic fractures, and abnormally high pressure fractures. There are three stages of development of structural fractures, corresponding to the late Indosinian period, mid late Yanshan period, and Himalayan period. Structural fractures have the characteristics of long extension, large width, and low filling degree of fractures; The diagenetic fractures are mainly bedding fractures, with a small amount of sutures developed; The development of abnormally high pressure fractures is relatively rare, which is related to hydrocarbon generation and pressurization. Building upon this foundation, the main controlling factors for the development of fractures were further clarified. The degree of structural fracture development is primarily influenced by a multitude of factors, including structural deformation, fractures, rock facies, rock layer thickness, and phase transformation; The development degree of diagenetic fractures is primarily influenced by rock facies and rock layer thickness; The development degree of abnormally high pressure fractures is chiefly influenced by hydrocarbon generation and pressurization. Based on the structural style and lithological combination of the second member of Xujiahe Formation in the research area, a fracture genesis model has been established. The fracture development area of the second member of Xujiahe Formation in the research area is located at the structural turning point, near the north-south trending fault, with a moderate thickness of single layer sandstone(sand mud interbedding, thick sand thin mud type), a north-south trending lithofacies change zone, and an abnormal pressure development area.

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CO2 flooding technology and its application in Jiangsu Oilfield in Subei Basin
TANG Jiandong, WANG Zhilin, GE Zhengjun
Petroleum Reservoir Evaluation and Development    2024, 14 (1): 18-25.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.01.003
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CCUS(Carbon capture, Utilization and Storage) technology is of great significance to the green and low-carbon transformation and the realization of the “dual carbon” goal, It includes important strategies like CO2 enhanced oil recovery(EOR) and sequestration. Jiangsu Oilfield has been focusing on CO2 EOR to improve recovery rates in the challenging fault block reservoirs of the Subei Basin. The company has developed four unique CO2 EOR models suitable for these complex reservoirs, featuring techniques like gravity-stable displacement. A notable achievement is the successful pilot of the methods such as “simulated horizontal well” GAGD technology in Hua-26 fault block, which led to the one hundred thousand CCUS project tailored for such reservoirs. According to statistics, Jiangsu Oilfield has injected a total of 30.34×104 t of liquid CO2, with a cumulative oil increase of 9.83×104 t, realizing a better production increase and economic benefits. These technical researches and tests can provide valuable insights for applying CO2 EOR in similar complex reservoirs.

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Improvement and application of a novel drainage pump of deep coalbed methane wells in south Yanchuan
WU Zhuangkun, ZHANG Honglu, CHI Yuxuan, YIN Zhonghua, ZHANG Zhuang
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 416-423.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.002
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In order to solve the problem of frequent well laying in the coalbed methane field in south Yanchuan due to sand production(pulverized coal), a novel drainage pump in south Yanchuan coalbed methane well has been developed. The novel drainage pump is designed as a forced pull rod hemisphere-type seal, and the plunger assembly adopts a hollow design. The pump diameter is ø38 mm, the stroke is three meters, the stroke time ranges from one to three times per minute, and the displacement is 4.8~14.6 m3/d. The novel drainage pump is used together with hollow rod and tubing, forming a dual-channel integrated pipe string for production and cleaning. It can not only meet the normal drainage gas production, but also facilitates well flushing and discharging pulverized coal. In addition, the flushing fluid does not enter the stratum during well flushing, avoiding the pollution of the flushing fluid to the stratum and preventing the failure of the fixed valve and the pump from being stuck caused by the deposition of pulverized coal or sand in the coalbed methane field drainage well. In 2022, the novel drainage pump was applied in two wells in the south Yanchuan coalbed methane field, and since then, no fixed valve failure or pulverized coal card pump has occurred. As a result the average pump inspection period of measure wells has been extended by 285 days. Field tests demonstrate that the novel drainage pump has the dual functions of normal gas drainage and coal powder discharge through well flushing, providing a new technical support for improving the overall development level of coalbed methane field in south Yanchuan.

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Evaluation of geological engineering factors for productivity of deep CBM well after fracturing based on grey correlation method
KONG Xiangwei,XIE Xin,WANG Cunwu,SHI Xian
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 433-440.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.004
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Coal-bed methane reservoirs are characterized by low porosity, low permeability and low pressure, making their industrial exploitation primarily reliant on techniques like hydraulic fracturing. Currently, more than 50 percent of the gas wells in the Shizhuang block in the Qinshui Basin currently produce less than 500 m3/d of coal bed methane. However, the increase in production after gas well retrofitting has not been ideal and the main factors affecting gas well productivity remain unclear, directly impacting the overall improvement. To address this, the degree of influence of geological and engineering factors on fracturing productivity in coal-bed gas wells is described using the gray correlation method, and the main factors controlling gas well productivity after fracturing are analyzed. A correlation mathematical model between the main control factors and gas well production is established using the Pearson correlation analysis method to predict gas well productivity. The reliability of the prediction model is verified through gas well data validation. Furthermore, a classification decision tree is established using the chi-square automatic interactive detection decision tree method, in conjunction with gas well productivity data, to understand the impact of geological and engineering factors on gas well productivity in fractured wells. Under high gas content conditions, engineering factors have a relatively small impact on the productivity improvement of gas wells. However, as the gas content decreases, the impact of different engineering factors on the gas well productivity gradually increases, which helps optimize the main design parameters such as displacement, sand volume, and total liquid volume, enriching the evaluation methods for post fracturing productivity of coal seam pressure.

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Parameter optimization and field practice of CO2 pre-fracturing process in Jimsar shale oil block
ZHAO Kun,LI Zeyang,LIU Juanli,HU Ke,JIANG Ranran,WANG Weixiang,LIU Xiuzhen
Petroleum Reservoir Evaluation and Development    2024, 14 (1): 83-90.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.01.012
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The shale oil of Lucaogou Formation in Jimsar Sag has the characteristics of extremely low original permeability and high viscosity of crude oil, making it uneconomical to produce under natural conditions. Field practices have demonstrated that dense drilling combined with high-intensity volume fracturing is one of the most effective means to achieve large-scale development of shale oil. However, how to slow down the decline rate of oil wells and improve the recovery rate per well remains a pressing issue to be addressed. From 2019 to 2022, the researches and field tests of CO2 pre-fracturing assisted production technology were carried out in Jimsar shale oil block. The application effect of CO2 pre-storage fracturing and CO2 huff and puff in Jimsar shale oil block was systematically studied and analyzed. The results indicate that supercritical CO2 has the effects of miscible energy increase, dissolution to improve reservoir conditions, improve imbibition replacement efficiency, and increase the complexity of fracture network. The optimal injection volume, injection speed, and injection methods were determined, and a preliminary technological system for CO2 pre-fracturing in shale oil reservoirs was established. According to the prediction of production data, the CO2 pre-fracturing process can increase the final recovery rate by about 20%, which provides a reference for realizing the benefit development of shale oil and improving the development effect of other types of shale reservoirs.

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Analysis of characteristics of coal fine production and its influence factors in Baode block
MENG Wenhui, ZHANG Wen, WANG Boyang, HAO Shuai, WANG Zebin, PAN Wujie
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 441-450.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.005
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The issue of coal fine production is increasingly prominent in the development of coal-bed methane. Implementing appropriate measures to control the migration and production of coal fines is crucial for achieving stable and high production of coal-bed methane wells. However, the characteristics of coal migration and production in the coal seams of Baode block remain unclear, which hinders the efficient development of coal-bed methane in some wells in this area. To address the problem of coal fine production in coal-bed methane development, core flooding experiments were conducted to investigate the migration and production characteristics of coal fines concerning influencing factors such as formation water velocity, salinity, gas-water ratio, effective stress, etc. The experimental results revealed that during the drainage stage, the amount of coal fines produced at low formation water flow is minimal, with coal fines moving within fractures and accumulating at the outlet, forming a coal powder filter cake. However, when formation water flow surpasses the critical flow, a significant amount of coal fines is produced. A substantial pressure fluctuation can flush out the coal fines obstructing the outlet. Furthermore, the salinity of the formation water plays a role in carrying coal powder, with higher salinity increasing its transport capacity. While single gas phase flow is not effective in displacing the coal fine migration and production, two-phase flow with a gas-water ratio of 50∶50 exhibits a stronger ability to carry coal powder. The concentration of coal fine in the produced liquid continued to decline with the increase of the effective stress loaded on the coal, Similarly, the holding pressure at the outlet follows a downward trend, but the displacement pressure difference increases. The research findings provide essential data and a theoretical basis for implementing on-site prevention and control of coal fine production.

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Productivity evaluation of multi-stage fracturing horizontal wells in shale gas reservoir with complex artificial fracture occurrence
HU Zhijian, LI Shuxin, WANG Jianjun, ZHOU Hong, ZHAO Yulong, ZHANG Liehui
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 459-466.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.007
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Considering complex shape and non-uniform distribution of fracturing fractures in shale reservoir, on the basis of multiple migration mechanisms a unified apparent permeability model is developed, incorporating two types of pore apparent permeability based on multiple migration mechanisms. This model serves as the foundation for establishing a gas reservoir-fracture-wellbore coupled seepage model, utilizing real space source function theory and pressure drawdown superposition principle. Through simulations and analyses, the study investigates the effects of micro seepage, fracture shape and non-uniform distribution of fractures on shale gas productivity. The demonstrate that micro seepage significantly impacts shale gas well production, with daily gas production being 20.3 % higher when considering micro seepage during the initial stage compared to neglecting it. Furthermore, the productivity of wells with complex fractures is lower than that of wells with ideal rectangular fractures, and star-shaped fractures exhibit the lowest productivity. The non-uniform distribution of fractures also affects the productivity of horizontal wells, and an optimal fracture layout is identified. The model takes into account both the micro seepage mechanism and actual fracturing fracture of shale gas, providing valuable guidance for the productivity research of fractured horizontal wells in shale gas reservoir.

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Evaluation of multi-stage fracturing a horizontal well of low permeability reservoirs in East China Sea
ZHANG Fengxi, NIU Congcong, ZHANG Yichi
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 695-702.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.017
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Staged fracturing technology for offshore horizontal wells is still in an exploratory phase due to operational limitations. The effectiveness of fracturing horizontal wells has a significant impact on their productivity. Therefore, evaluating the fracturing effect and guiding the fracturing development of horizontal wells is a pressing concern. This paper firstly introduced the geological situation of low permeability reservoir in the East China Sea in detail, and the process of stage fracturing of the first open hole horizontal well was described. Then the fracturing effect of the multi-stage fractured horizontal well was evaluated successfully using the latest fracturing effect evaluation method of SPEE(Society of Petroleum Evaluation Engineers). By analyzing the fracturing operation parameters of the well and comparing EUR(Estimated Ultimate Recovery) before and after fracturing, the fracturing effect evaluation method is verified to prove the correctness and reliability. Finally, it is concluded that the gas recovery rate of this horizontal well after fracturing is increased by 9.3 % and the oil recovery rate is increased by 6.6 %. The successful implementation of staged fracturing and the subsequent evaluation of its effects on the first horizontal well in the East China Sea set the stage for future development of horizontal well staged fracturing in offshore low-permeability reservoirs.

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Theories, technologies and practices of exploration and development of volcanic gas reservoirs: A case study of Cretaceous volcanic rocks in Songnan fault depression
MA Daixin,REN Xianjun,ZHAO Mifu,HAN Jiaoyan,LIU Yuhu
Petroleum Reservoir Evaluation and Development    2024, 14 (2): 167-175.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.02.002
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In the past two decades, Sinopec Northeast Oil & Gas Company has made significant strides in exploring the southern Songliao Basin, revealing that the basin's volcanic rocks present a new and promising avenue for hydrocarbon exploration. According to the exploration practice of the basin, the company has developed a comprehensive four-component coupling reservoir control model specific to fault depressions. This model emphasizes the interconnected evolution of key elements such as hydrocarbon generating foci, reservoir formation periods, paleostructure, fault cap preservation, and effective reservoirs, with a particular focus on the main accumulation period. This strategic approach led to the significant discovery of a large-scale volcanic gas reservoir within the Huoshiling Formation in the Changling fault depression, located in the Songnan area. Consequently, the exploration focus has broadened from the Yingcheng Formation to the Huoshiling Formation, diversifying the exploration targets from acidic volcanic rocks to intermediate-basic volcanic rocks, and extending from subaerial to submarine eruptions. By using the technique of fine gas reservoir description, the integration of modeling, numerical modeling and geological engineering, the productivity breakthrough has been achieved in several wells in Songnan fault depression, and the efficient development and large-scale production of volcanic gas reservoir has been realized.

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Analysis of pressures in water injection wells considering fracture influence induced by pressure-drive water injection
CUI Chuanzhi, LI Huailiang, WU Zhongwei, ZHANG Chuanbao, LI Hongbo, ZHANG Yinghua, ZHENG Wenkuan
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 686-694.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.016
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The analysis of the well bottom pressure of the pressure-drive injection wells is of great significance for the evaluation of the pressure-drive effect and the inversion of reservoir parameters. In order to obtain the bottom hole pressure response of pressure-drive injection wells and the dynamic fracture parameters generated by pressure drive water injection, and from an fracture propagation perspective, the seepage mechanics theory and numerical simulation method are used to form a pressure analysis model of water injection wells considering the effects of fracture propagation, fracture morphology, filtration of injected fluid and other factors, and obtain the bottom hole pressure response of pressure drive water injection wells. The effects of injection flow, liquid production, formation permeability and well spacing on pressure are analyzed respectively, and applied to actual pressure drive wells to verify the accuracy of the model. It is found that the fluid flow in pressure-drive injection wells can be divided into five flow stages, namely, initial fracturing stage, fracture expansion stage, linear flow stage, transitional flow stage and boundary controlled flow stage. With the increase of injection flow rate, the fracture expansion stage is more obvious, the liquid production is greater, and the upwarping amplitude of the double logarithmic pressure analysis curve gets smaller in the late stage of pressure drive water injection. This study is of great significance to the study and understanding of the mechanism of unstable seepage flow in low permeability reservoirs developed by pressure drive water injection, and to the influence of dynamic fractures in water injection wells on bottom hole pressure.

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Seismic rock physics analysis and prediction model establishment of Shaximiao Formation in Zhongjiang Gas Field
ZHAO Di, MA Sen, CAO Yanhui
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 608-613.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.008
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Shaximiao Formation gas reservoir in Zhongjiang Gas Field has great exploration and development potential. However, it is primarily characterized by ultra-low porosity and ultra-low permeability, with pronounced reservoir heterogeneity. Addressing the challenges related to the early-stage reliability of lithology and gas-bearing identification, as well as the accuracy of reservoir porosity and thickness predictions, a comprehensive seismic rock physics analysis was undertaken. The analysis focused on assessing the feasibility of reservoir prediction through forward modeling, fluid substitution, and rock physics scaling. The objective was to elucidate the specific relationship between seismic elastic parameters, lithological parameters, and reservoir parameters for gas reservoirs. By optimizing sensitive parameters related to lithology, physical properties, and gas-bearing properties, qualitative and quantitative prediction models for reservoirs were established. This entailed using attributes such as the maximum trough attribute, minimum wave impedance attribute, and the ratio of minimum longitudinal and transverse wave velocities to predict reservoir distribution. The lithology and gas-bearing property are identified by P-wave velocity ratio and P-wave impedance intersection. The shale content is quantitatively predicted by P-wave velocity ratio fitting or co-simulation. The porosity is quantitatively predicted by P-wave impedance fitting or co-simulation in sandstone. The gas saturation is quantitatively predicted by Lamda/Mu fitting or co-simulation in gas-bearing sandstone, which lays a solid foundation for the fine prediction of Shaximiao reservoir in the study area.

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Fine characterization technique of concealed channel and its application in the Jurassic Formation of western Sichuan Depression
LI Mengqiao, YE Tairan, DING Weinan, LIU Xingyan
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 591-599.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.006
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The sandstone reservoirs in the Jurassic formation of gas fields such as ZJ, XC, and SF in western Sichuan Depression are characterized by their tight nature and are primarily situated within delta plain-frontal distributary channels. These reservoirs often pose a unique challenge in terms of geophysical analysis due to the significant impedance contrast between the type ③ reservoir and the surrounding rock formations. Therefore, the precise characterization of concealed channel distribution is a crucial focus for expanding exploration and development efforts. In this study, the rock physics characteristics of reservoirs and forward modeling of AVO(Amplitude Versus Offset) gathers were conducted to determine the relationship between different reservoir types and AVO responses. Furthermore, a method known as the FN stacking method was developed. By optimizing the processing of gathers and selecting far/near offset stacking, the identification capability of concealed channels was significantly enhanced. This technology accurately reveals the distribution of hidden channels, precisely traces their shape and boundaries, and has successfully discovered new channels that have been confirmed through actual drilling, thus expanding new exploration and development fronts.

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Pore scale fracturing fluid occurrence mechanisms in multi-scale matrix-fracture system of shale gas reservoir
XIA Haibang, HAN Kening, SONG Wenhui, WANG Wei, YAO Jun
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 627-635.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.010
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After hydraulic fracturing in shale gas reservoir, a significant volume of fracturing fluid retains in the matrix pores and induced fracture network. Currently, the pore scale fracturing fluid occurrence mechanisms are unclear. As a result, it is difficult to accurately understand the difference of fracturing fluid backflow rate of shale gas wells in the backflow process. In this work, the pore scale fracturing fluid occurrence mechanisms analysis method in shale multi-scale matrix-fracture system is developed and the fracturing fluid occurrence mechanisms in shale gas reservoir are elucidated in detail. To understand fracturing fluid occurrence pattern in shale matrix, singe pore gas-water occurrence method is established considering rock-fluid interaction and gas-water capillary pressure and is further extended into the pore network. Invasion percolation is applied to analyze the fracturing fluid occurrence pattern variation during different flowback stages. To understand fracturing fluid occurrence pattern in induced fracture network, the level-set gas-water interface tracking method is applied to calculate gas-water distribution at different flowback pressure based on induced fracture network CT imaging and the fracturing fluid occurrence pattern variation at different flowback stage is studied. Study results reveal that the fracturing fluid flowback rate in shale matrix first increases slowly and then increases fast. In the final stage, the fracturing fluid flowback rate in shale matrix reaches plateau. The fracturing fluid in shale matrix distributes in the forms of water saturated pores, corner water and water film. The fracturing fluid flowback rate in induced fracture network is influenced by pore connectivity around the induced fracture network. The fracturing fluid flowback rate first increases fast and then reaches plateau. The retained fracturing fluid distributes in the dead-end matrix pores around induced fracture network at the final stage.

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Dynamic and static feature identification method of complex buried hill reservoirs in Bohai and its application
YAN Jianli,LI Chao,MA Dong,LI Zhuo,WANG Peng
Petroleum Reservoir Evaluation and Development    2024, 14 (2): 308-316.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.02.016
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The BZ oilfield in Bohai, known for its buried hill carbonate reservoir, is currently in the middle to late stages of development. The reservoir is characterized by strong heterogeneity and a complex distribution of fractures and vugs, leading to challenges such as complicated production behavior, rapidly declining output, and significant discrepancies in the estimation of dynamic and static reserves. To address these issues, a comprehensive set of criteria for identifying different types of carbonate reservoirs in the oilfield was developed. This was based on conventional well log data, thin section analyses, limited core data, and information from well tests and production characteristics. The reservoirs were categorized into three main types: fracture, fracture-vuggy, and porous. A detailed three-dimensional numerical well-testing model was created to accurately predict high-quality reservoir zones. This model took into account the reservoir's horizontal and vertical heterogeneity, allowing for precise delineation and assessment of the reservoir boundaries and connectivity in complex wells. It also facilitated a more accurate evaluation of the dynamic reserves and confirmed the oil and gas potential in the submerged mountains at the boundary of the Archaean group. This comprehensive approach laid the groundwork for devising strategic adjustments during the latter stages of the oilfield's development. It guided field modifications aimed at maximizing the reservoir's potential, ultimately leading to validated high production outcomes.

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Primary research on expression of kerogen in Longmaxi Shale and its adsorption characteristics
HOU Dali, HAN Xin, TANG Hongming, GUO Jianchun, GONG Fengming, SUN Lei, QIANG Xianyu
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 636-646.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.011
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Adsorbed gas represents a primary mode of shale gas occurrence and is a major source of shale gas production in the later stages of development. It primarily resides within the organic kerogen and clay minerals of shale formations, with organic kerogen being the dominant host. Consequently, the study of organic kerogen characteristics and its adsorption mechanisms is crucial for understanding shale gas development. In this paper, the kerogen of Longmaxi Shale in the Sichuan Basin is taken as the research object. The microstructure of kerogen is expressed by combining methods through the solid-state NMR experiment, Fourier transform infrared spectroscopy experiment, X-ray photoelectron spectroscopy experiment, and the molecular structure model of kerogen is constructed. The adsorption mechanism and characteristics of CH4 in kerogen of Longmaxi Shale are analyzed by magnetic levitation weight experiment, molecular simulation methods of the Grand Canonical Monte Carlo(GCMC), and Molecular Dynamics(MD). The results show that the molecular formula of the kerogen of shale experimental sample of Longmaxi Formation is C237H219O21N5S4. The excess adsorption gas volume of CH4 in kerogen increase first and then decreased with the increase of pressure. Under the same pore size and pressure, the excess adsorption gas volume and total gas volume of CH4 decrease with the increase in temperature. The C and S atoms in kerogen are the main cause of CH4 adsorption. The CH4 near the kerogen pore wall presents an adsorption state, while the CH4 far from the kerogen pore wall presents a free state. As the pore size increase, the distance between the two peaks of CH4 density gradually increases, and the peak value decreases gradually.

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Well-log lithofacies classification based on machine learning for Chang-7 member in Longdong area of Ordos Basin
SHEN Li,WANG Caizhi,NING Congqian,LIU Yingming,WANG Hao
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 525-536.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.015
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Lithofacies analysis serves as the foundation for reservoir evaluation. However, due to the limited coring quantity and cost constraints, identifying lithofacies using logging data for uncored wells becomes crucial. In the Longdong area of the Ordos Basin, the lithofacies of the Chang-7 member have been classified into six types dependent on core identification results and imaging logging data. Based on core calibration, the logging response characteristics of different lithofacies were summarized, leading to the establishment of the lithofacies recognition mode using conventional logging curve. To achieve automatic lithofacies recognition in the study area, machine learning algorithms were employed. The traditional classification algorithms were affected significantly by the unbalanced sample. After comparing the application effects of different unbalanced data classification algorithm in the region, it’s found that bagging algorithm of ensemble learning notably improved the classification performance of all lithofacies by combining multiple classifiers. As a result, the overall lithofacies identification precision of this region has been improved by 20 %. According to the regional application results, the identification accuracy of single well can reach 84.33 %, demonstrating its practical applicability and effectiveness.

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Molecular dynamics simulation on interaction mechanisms of crude oil and CO2
LI Jianshan, GAO Hao, YAN Changhao, WANG Shitou, WANG Liangliang
Petroleum Reservoir Evaluation and Development    2024, 14 (1): 26-34.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.01.004
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Numerous oil displacing mechanisms of CO2 have been widely recognized, but due to reservoir factors, the effectiveness of CO2 flooding varies significantly under different reservoir conditions. It is necessary to further deepen the research on the micro-interaction mechanisms between CO2 and crude oil, clarify the CO2 flooding mode under different reservoir conditions, and maximize the potential of CO2 flooding. Molecular dynamics simulation methods have been used to study the effects of components, temperature, and pressure on the interaction between oil droplets and CO2. The kinetic parameters were obtained to quantitatively characterize the oil droplets-CO2 interaction, clarifying the micro-interaction patterns under different conditions. The simulation results show that the dispersion force is the the main driving force of the interaction between CO2 and alkane molecules, which mainly includes two aspects: one is the dissolution and diffusion of CO2 molecules into the oil droplets by overcoming the steric hindrance between alkane molecules, and the other is the extraction attraction of CO2 molecules to the outer layer molecules of the oil droplets. As the chain length of alkane molecules decreases, the temperature decreases and the pressure increases, the solubility parameter of the oil droplets and the coordination number of CO2 increase, the curvature of the molecules in the outer layer of the oil droplets decreases, and the interaction between the two is enhanced. It is concluded that CO2 miscible and near-miscible flooding should be realised as much as possible in light and medium-light reservoirs with lower temperatures and higher pressures, while in medium and heavy reservoirs with higher temperatures and lower pressures, the advantages of CO2 non-miscible flooding in terms of dissolution viscosity reduction, crude oil volume expansion and energy replenishment should be fully exploited. The study results can provide theoretical guidance for laboratorial research and field application of CO2 flooding.

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Application and research progress of CO2 capture and utilization technology
HE Zhiyong,GUO Benshuai,WANG Dong,MAO Songbai,LI Zhongyu
Petroleum Reservoir Evaluation and Development    2024, 14 (1): 70-75.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.01.010
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The global consensus on achieving carbon neutrality is driven by the urgent need to address climate change caused by excessive CO2 emissions. Carbon Capture, Utilization, and Storage(CCUS) stands out as a critical solution, receiving significant attention from the researchers. Sinopec Nanjing Research Institute of Chemical Industry Co., Ltd. has been committed to the research and development and application of CO2 capture and utilization technology for a long time. The institute has perfected three advanced carbon capture methods: low partial pressure flue gas carbon capture technology, NCMA(Nanjing chemical mixed amine) decarburization technology and catalytic hot potassium alkali decarburization technology, which have been successfully applied in many industrial projects. Furthermore, the institute is pushing boundaries in new carbon capture and CO2 utilization technologies, achieving notable advancements that align with both domestic and international standards.

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Production forecasting for normal pressure shale gas wells based on coupling of production decline method and LSTM model
HAN Kening, WANG Wei, FAN Dongyan, YAO Jun, LUO Fei, YANG Can
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 647-656.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.012
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In order to address the challenges posed by the unclear production decline patterns and the difficulty in predicting production for normal pressure shale gas wells, a novel production prediction approach has been developed. This approach combines shale gas well production decline models with Long Short-Term Memory(LSTM) neural network models, leveraging machine learning techniques and different decline models for improved accuracy. Firstly, Nanchuan shale gas wells are divided into two types according to the characteristics of water production. For type 1, gas and water are produced simultaneously at the early stage, then water production decreases significantly in the later stage; while for type 2, gas and water are produced simultaneously for a long time. Secondly, double logarithmic diagnostic curves and characteristic curves are used to identify the flow stages of gas wells; then seven gas production decline models are used to analyze the production variety. Finally, the error of the decline models are used as the inputs of the LSTM model, meanwhile the yield prediction under the coupling method is obtained after superposition. The results show that a type 1 gas well, Well-X1, is in the pesudo-steady flow stage, its optimal decline model is the improved hyperbolic decline model or the AKB model; a type 2 gas well, Well-X2, is in the linear flow stage, the preferred models are SEPD decline and Duong decline model. When the error of the decline model is large, the production prediction accuracy of shale gas wells is effectively improved after coupling the LSTM model but the effect is not obvious when the error of the decline model is small.

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Confidence evaluation of fractures seismic detection in shale gas formations on WY23 Pad in Weirong
LI Jingchang, LU Ting, NIE Haikuan, FENG Dongjun, DU Wei, SUN Chuanxiang, LI Wangpeng
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 614-626.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.009
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Due to the inadequacy in the pre-assessment of natural fracture growth in shale, the exploration and development effect of Weirong shale gas field is seriously affected. It is imperative to enhance research on fracture prediction. In this paper, we applied the post-stack seismic dip-azimuth attribute to detect fractures in the WY23 Pad, and evaluated the reliability of the detection results from four aspects: geology, seismic, logging and engineering. The method employed for fracture detection revealed that fractures exhibit layer-controlled characteristics. They can be divided into two sets of upper and lower fracture systems roughly bounded by the top surface of the ③ thin layer. These fracture systems dip toward each other in the profile, with a predominant strike direction of 310° and dip angles of less than 20°. This configuration is the result of NE-SW compression. The application of this method for fracture detection has a high degree of confidence and can be promoted and applied in other development pad than WY23.

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Influence law of temperature profile for horizontal wells in tight oil reservoirs
LUO Hongwen, ZHANG Qin, LI Haitao, XIANG Yuxing, LI Ying, PANG Wei, LIU Chang, YU Hao, WANG Yaning
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 676-685.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.015
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The challenge of reliably predicting temperature profiles in horizontal wells in tight oil reservoirs, coupled with an incomplete understanding of the factors influencing these profiles, has hindered the quantitative interpretation of tight oil horizontal well production using distributed optical fiber technology. To address this issue, a comprehensive model has been developed to estimate temperature profiles in horizontal wells in tight oil reservoirs, accounting for various microthermal effects. The temperature profiles of horizontal wells in tight oil reservoir under different single factors were simulated and analyzed. Then, through orthogonal experiment analysis, it demonstrates that the sensitivity of different factors from strong to weak is production rate, fracture half-length, reservoir permeability, wellbore diameter, horizontal inclination angle, fracture conductivity, and total reservoir thermal conductivity(Q>xf>K>D>θ>FCD>Kt). It is worth noting that fracture half-length and formation permeability emerged as the primary factors influencing the temperature profile of horizontal wells in tight oil reservoirs. The research results provide available basic models and theoretical support for quantitative interpretation of production profile and artificial fracture parameters for horizontal wells in tight oil reservoir.

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Petroleum Reservoir Evaluation and Development    2023, 13 (5): 0-.  
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Petroleum Reservoir Evaluation and Development    2023, 13 (5): 1-.  
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Petroleum Reservoir Evaluation and Development    2023, 13 (6): 0-0.  
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3D geological modeling technology of medium-deep geothermal field in Shenshui 501 geothermal field in Damintun Sag
CONG Shufei, ZHOU Hong, ZHAO Yan, JIN Hailong, LIU Peng, WU Rongbi, CHEN Yuanchun
Petroleum Reservoir Evaluation and Development    2023, 13 (6): 741-748.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.06.004
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As geothermal resource development continues to advance, addressing the challenge of sustainably and efficiently harnessing these resources becomes increasingly critical. This involves achieving a balance between the exploration and sustainable use(or "irrigation") of geothermal resources. To this end, the application of Petrel, a geological modeling software originally designed for the petroleum industry, has been adapted for geothermal geological modeling, offering a promising solution. The adaptation of Petrel for geothermal purposes involves establishing a geospatial platform within the software to manage and analyze a wide range of geothermal geological data. This platform enables comprehensive research into geothermal geological elements by integrating diverse data sets to the fullest extent, thereby enhancing the quality and scope of geothermal geological studies. This approach involves scaling up from traditional small-scale oil and gas reservoir modeling to large-scale thermal reservoir modeling. Such a transition not only maintains the accuracy of the models but also aligns with the scale requirements unique to geothermal geology. Utilizing Petrel, models of the thermal reservoir temperature field, pressure field, and effective thermal reservoir can be constructed. This is achieved by combining various types of data and employing both deterministic and stochastic modeling techniques, thereby establishing a robust method for thermal reservoir geological modeling using Petrel. A key advantage of employing a 3D geological model for calculating effective thermal reservoir resources is its reduced sensitivity to reservoir heterogeneity. This approach more accurately reflects real subterranean conditions, providing a more reliable basis for resource evaluation. The resulting accurate 3D geological models and resource assessments lay a solid foundation for the numerical simulation of thermal reservoirs and the development of comprehensive thermal reservoir management plans. This, in turn, supports the scientific and sustainable exploitation and utilization of geothermal resources in the area, ensuring their efficient and responsible development.

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Overview of solutions to improve efficiency of ground source heat pump system
ZHANG Yuping, YANG Xiao, LIU Jun, LIU Boyang, TANG Fujiao, TAN Yiqiu
Petroleum Reservoir Evaluation and Development    2023, 13 (6): 726-740.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.06.003
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Shallow geothermal energy, with applications ranging from road snow melting and deicing to building heating/cooling, primarily utilizes closed-loop vertical buried pipes for resource exploitation. These pipes function by exchanging heat with the subterranean zone under specific cooling or heating loads. Given the limited capacity of a single vertical ground heat exchanger to harness geothermal resources, arrays of these exchangers are more commonly employed to effectively tap into shallow geothermal resources. However, the underground temperature field can be significantly affected by the heat exchange process between the ground heat exchanger array and the surrounding soil. Improper design and operational conditions can lead to an imbalance in the underground temperature field, potentially resulting in energy deficiencies and the malfunctioning of Ground Source Heat Pump Systems(GSHPS). Therefore, optimizing the design and operation scheme of ground heat exchanger array is the key to solve the imbalance of underground temperature field. The review summarizes the domestic and foreign research results, outlining various methods for energy storage and removal, incorporating auxiliary heating and cooling sources, and exploring relevant optimization techniques. The borehole array design optimization methods include primarily the distance between the pipe and the borehole layout. The energy storage/removal section mainly introduces the latest research results of borehole heat exchanger array by using external heat/cold sources such as solar energy and industrial waste heat. The auxiliary method mainly describes the latest researches on the application of resources like solar energy and heating towers. The operation control strategy mainly analyzes the operation control of the ground source heat pump system, including the peak cooling and heating load operation, intermittent operation, partition operation, system control strategy, etc. By thoroughly examining these optimization approaches and operational control strategies, the review provides a comprehensive analysis of the advantages and disadvantages of each scheme. This detailed evaluation serves as a valuable reference for improving the energy efficiency of GSHPS, ensuring sustainable and effective utilization of shallow geothermal resources.

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Field test of self-suspending proppant at Mahu sandstone reservoir in Xinjiang Oilfield
REN Hongda, DONG Jingfeng, GAO Jing, LIU Kaixin, ZHANG Jingchun, YIN Shuli
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 513-518.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.013
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Currently, the large-displacement slickwater fracturing process has become the primary method for developing unconventional oil and gas resource. However, the efficiency of this process is limited by the sand carrying capacity of slickwater, which results in rapid settlement and short migration distance of the proppant within the fractures, leading to a need for further improvement in the reservoir transformation effect. To address this issue, a water-soluble material is applied to coat the surface of the self-suspending proppant, enhancing its suspension effect in slickwater or clear water and thereby increasing the crack support volume. The self-suspending proppant meets the required technical standards, showing a total suspension time of less than 40 seconds in tap water at a 20 % sand ratio, and maintaining stable suspension for over two hours at 90 ℃ even during thorough mixing. In a practical on-site test at Mahu sandstone reservoir in Xinjiang Oilfield, continuous sand carrying was achieved using clean water, reaching a maximum sand concentration of 480 kg/m3 while maintaining stable construction pressure. The successful application of self-suspending proppant clear water fracturing technology in Xinjiang oilfield serves as a valuable reference for the selection of oil and gas resource technology in the future stage.

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Characteristics of pore dynamics in shale reservoirs by CO2 flooding
ZHANG Zhichao,BAI Mingxing,DU Siyu
Petroleum Reservoir Evaluation and Development    2024, 14 (1): 42-47.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.01.006
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The pore utilization characteristics of CO2 during shale oil displacement are a crucial indicator for evaluating its effectiveness in enhancing shale oil reservoir recovery rates. Therefore, experiments on supercritical CO2 displacing shale cores were conducted in the laboratory, and nuclear magnetic resonance(NMR) online core scanning technology was used to study the pore utilization characteristics and patterns of CO2 displacement in shale oil reservoirs. The results indicate that immiscible flooding by supercritical CO2 mainly develops the oil in shale pores with radius of 0.1~3.0 μm, but the oil content in pore radius less than 0.008 μm actually increases. The analysis shows that CO2 brings shale oil from large pores into small pores through pressure difference and diffusion effect in the shale layer and makes oil undergo adsorption and retention. After a displacement time of five hours, the recovery rate of shale oil by CO2 displacement reached 35.7%, indicating a relatively effective oil displacement result.

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Research and application of modular skid-mounted CO2 recovery technology
CHEN Xingming,HE Zhishan
Petroleum Reservoir Evaluation and Development    2024, 14 (1): 64-69.   DOI: 10.13809/j.cnki.cn32-1825/te.2024.01.009
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Under the background of “carbon peak and carbon neutrality”, traditional chemical enterprises are encountering challenges due to CO2 emission limitations. CCUS(Carbon Capture, Utilization and Storage) technology emerges as a crucial strategy for addressing CO2 emissions. To mitigate emissions at the source, chemical companies are turning to CO2 flue gas capture and recovery technologies, while also exploring ways to integrate these efforts into a cost-effective CCUS industrial chain. To overcome the drawbacks of traditional CO2 flue gas recovery units, such as large land use, high construction costs, inflexibility, and lengthy construction times, the modular skid-mounted CO2 recovery technology has been introduced. This innovative approach minimizes upfront investment and accelerates project timelines by modularizing the recovery process, allowing for 100% factory prefabrication and streamlined on-site assembly. The skid-mounted design efficiently organizes pipelines and valves, integrating equipment within each module onto skids, resulting in a fully modular skid-mounted CO2 recovery unit. Field applications demonstrate significant advantages of the modular skid-mounted approach over conventional methods. For example, a 5×104 tons per year coal-to-hydrogen CO2 flue gas recovery unit saw a 74.0% reduction in construction costs, a 75.2% decrease in required space, and a 50.0% shorter construction timeline, effectively meeting the objectives of cost reduction and expedited project completion.

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Discrete element simulation study on fracture propagation law of dual well synchronous fracturing
ZHANG Jiawei, LIU Xiangjun, XIONG Jian, LIANG Lixi, REN Jianfei, LIU Baiqu
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 657-667.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.013
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The understanding of fracture propagation and evolution during dual well synchronous hydraulic fracturing, particularly under various conditions, remains limited. Meanwhile, the interaction between fractures will cause fracture reorientation and affect the hydraulic fracturing effect. In order to solve these problems, the fracture propagation law and failure mode under the influence of different factors are studied by the discrete element method. The results show that when the angle between the interwell connecting line and the maximum principal stress (θ) is 0°, and under the influence of the horizontal stress difference, the stress around the borehole wall can be divided into two stages: the stable stage before the fracture intersection and the steep rise stage after the fracture intersection. With the decrease of the horizontal principal stress difference, the failure mode changes from single fracture to multi fracture failure. When θ≠0°, the in-situ stress field of the formation changes, which causes the fracture deflection and forms an inclined fracture connecting the two wells. During the fracturing process, the expansion of the fracture exerts great stress on the surrounding area, and the magnitude and direction of local stress state change due to the expansion of the main fracture. So that the crack spreads away from the direction of the maximum principal stress.

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Genesis analysis and effective development of normal pressure shale gas reservoir: A case of Wufeng-Longmaxi shale gas reservoir in southeast margin of Sichuan Basin
XUE Gang, XIONG Wei, ZHANG Peixian
Petroleum Reservoir Evaluation and Development    2023, 13 (5): 668-675.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.05.014
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There are two types of shale gas reservoirs in the Wufeng-Longmaxi shale formation of southeast margin of Sichuan Basin: normal pressure shale gas reservoir in Wulong residual syncline and abnormal over-pressure shale gas reservoir in Fuling anticline. This study takes an integrated geology-engineering approach to analyze the genesis and formation mechanisms of normal pressure shale gas reservoirs in the Wulong area. The analysis is based on shale burial history curves, drilling data, horizontal well fracturing parameters, and the geological characteristics specific to normal pressure shale gas reservoirs. Combined with the actual production effects of two horizontal shale gas wells, the fracturing process parameters of normal pressure shale gas reservoirs are optimised. Then three main points have been obtained in this study: ①The normal pressure shale gas reservoir of the Wufeng-Longmaxi Formation in Wulong area is formed during the structural destruction adjustment of the Yanshanian and Himalayan tectonic periods. ②The shale gas escaping caused by tectonic elevation is the main reason for the formation of normal pressure shale gas. ③Compared with the Marcellus normal pressure shale gas reservoir, Wulong normal pressure shale gas reservoir has the similar geological characteristics, but the development effect varies greatly. The fracturing scale simulation shows that it is necessary to further optimise the horizontal well segmented fracturing parameters, increase the output of single wells, and reduce development costs. Only in this way can effective development be realised.

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Oil displacement efficiency based on different well pattern adjustment simulation in high water cut reservoirs
YANG Bing, FU Qiang, GUAN Jingtao, LI Linxiang, PAN Haoyu, SONG Hongbin, QIN Tingting, ZHU Zhiwei
Petroleum Reservoir Evaluation and Development    2023, 13 (4): 519-524.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.04.014
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The adjustment of the flow field proves to be an effective way for enhancing the recovery of remaining oil during the high water cut development stage in a water-flooding oilfield. As the water flooding oilfield enters the high water cut development stage, a dominant flow field gradually forms between oil and water wells, resulting in the ineffective circulation of injected water. As a result, the effect of reservoir development is reduced. To address this issue, a flow field adjustment model is established based on standard determinant well pattern arrangement using Python programming language, guided by the working principle of flow field adjustment. In this model, the flow field streamlines transition angles are 27°, and 45° respectively. The finite difference method is employed to simulate the dominant flow field range before and after the adjustment. The results demonstrate that the nine-spot method and the five-spot method could enhance the oil displacement efficiency, while the flooding efficiency of the M-shaped well-mesh is relatively low. Moreover, the 45°-streamline transition proves to be particularly beneficial for oil exploitation during the high water cut development stage in a water-flooding oilfield. The study holds significant guiding significance for adjusting the well pattern and enhancing the recovery efficiency, thereby facilitating the extraction of remaining oil in the high water cut development stage.

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Development and application of Sinopec integrated management platform for underground gas storage
MI Lidong,ZENG Daqian,LIU Hua,ZHANG Guangquan,ZHANG Junfa
Petroleum Reservoir Evaluation and Development    2023, 13 (6): 781-788.   DOI: 10.13809/j.cnki.cn32-1825/te.2023.06.009
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Underground Gas Storage(UGS) is a complex, multifaceted process with multiple stages and a long operational cycle, making it a long-term systemic endeavor. The lifecycle of gas storage encompasses various phases including site selection evaluation, scheme design, engineering construction, production and operation, optimization of operations, and eventual abandonment. The integration of these phases is crucial for the safe construction and efficient operation of gas storage facilities. Given the complexity and scope of UGS, there is a pressing need for a comprehensive system that encompasses “management decision-making, monitoring, early warning, simulation analysis, and production control” to facilitate the integrated application of the entire gas storage process. This paper specifically addresses the construction plan of Sinopec gas storage, aligning with the national mandate for “industrialization and informatization” integration. It aims to bridge the gap between management, research, and production in gas storage, addressing both managerial and technical challenges throughout the entire process of site location, design, operation, and analysis. The ultimate objective is to enhance quality and efficiency in gas storage operations. An integrated platform for UGS has been designed and developed, focusing on “production monitoring, tracking analysis, remote control, and auxiliary decision-making” as its core components. Research indicates that this platform has significantly advanced the digitalization of various aspects of gas storage, such as site optimization, geological research, injection and production control, and peak shaving optimization, across all nodes. It enables precise control over production process nodes, intelligent analysis of production and operational trends, and scientific decision-making for production and control. The research shows that the platform has realized the digital improvement of the gas storage site optimization, geological research, injection and production control, peak shaving optimization and the whole node, accurately controlled the production process nodes, intelligently analyzed the production and operation trend, scientifically made the production and control decisions, and realized the integrated management and research of the gas storage site optimization, scheme design, production and operation, and dynamic analysis.

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