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On philosophy and innovative thinking of oil & gas exploration and development: Commemoration of the first oil well on land in China, Well-Yan1
HE Faqi,XU Bingwei,SHAO Longkan
Reservoir Evaluation and Development    2022, 12 (2): 265-273.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.001
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Oil & gas exploration and development is a combination of innovative thinking and practice. Firstly, a geologist should have the concept of oil and gas in his mind. The geologists should constantly emancipate their minds and be full of passion for oil exploration. They should look at the problems in a sight of development, re-recognize themselves, re-recognize the underground, re-recognize the potential of geological-engineering integration, and study the geological situation of oil and gas reservoirs with the continuous development of the understanding. On the basis of re-understanding the exploration discovery of Well-Yan1, the theory of fault-fracture body reservoir is formed by summarizing the exploration and development practice and the field geological investigation of oil and gas reservoirs in Ordos Basin. The continuous innovation of exploration and development theory has realized the continuous breakthrough of exploration and development in Ordos Basin. As the annual oil and gas equivalent has exceeded 80 million tons, Ordos Basin become the first oil and gas bearing basin in China. By summarizing the experiences of Sinopec North China Oil and Gas Company in oil and gas exploration and development in Ordos Basin, it is found that seeking truth from facts is the key to deepen the understanding of oil reservoirs for the breakthrough of oil and gas exploration, the philosophical method of dialectical thinking can obtain new understanding of oil and gas geology at different stages, the fine description of oil and gas reservoirs is the basis for the preparation of development plans, and the integration of geological engineering realize the benefit development of tight oil and gas reservoirs. The object of oil and gas exploration and development will be more complex in Ordos Basin. As a result, the oil and gas exploration should focus on the whole basin to re-recognize the oil and gas reservoirs, and find different types of oil and gas reservoirs by the breakthrough of exploration and development theory.

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Occurrence of normally-pressured shale gas in China and the United States and their effects on mobility and production: A case study of southeast Sichuan Basin and Appalachia Basin
JIANG Shu,LI Chun,CHEN Guohui,GUO Tonglou,WU Yuyuan,HE Xipeng,GAO Yuqiao,ZHANG Peixian
Reservoir Evaluation and Development    2022, 12 (3): 399-406.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.001
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Normal pressure shale gas plays such as the Ohio Formation Shale and Marcellus Formation Shale in the Appalachian Basin in the U.S. have been developed commercially. Although Wufeng-Longmaxi Shale in southeast Sichuan Basin in China has been initially developed, its production efficiency is not obvious and its cost is high due to the large burial depth and poor reservoir properties physical properties. In the normal pressure shale gas formation, the absolute pressure changes at different depths, which influences the gas occurrence state, and then has a significant influence on gas content and mobility. Therefore, it is urgent to carry out quantitative research on the differences of normal pressure shale gas reservoir conditions, gas occurrence state, gas content and mobility between China and the US. In this study, the Wufeng-Longmaxi shales of Well-LY1 in Pengshui of China and the Marcellus shale and Ohio Shale of Appalachian Basin in the United States are selected as the research objects under normal pressure. Based on the volume method, and with the considering of the influence of the temperature, pressure, maturity, water and oil on the adsorption capability and maximum adsorption capacity, and the temperature and pressure, porosity and water saturation on the determination of free gas volume, the gas content of three groups of shale reservoirs is evaluated. The reservoir pressures are considered as the initial pressures and the simulation are conducted based on a pressure drop of 5 MPa. On the basis of clarifying the desorption process of adsorption and free gas in the depressurized production respectively, the fundamental cause of the difference in normal pressure shale gas production between China and the U.S. is revealed. Compared to the Marcellus Shale in Appalachian Basin, the lower adsorption capacity, porosity and free gas of the Wufeng-Longmaxi shales result in low production of adsorbed gas and free gas. However, compared to the shale of the Ohio Formation, the deeper burial, higher temperature and higher pressure in the Wufeng-Longmaxi shales result in the extremely low recovery rate of adsorbed gas. Its lower porosity also contributes to the lower free gas production.

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Regional distribution of field shale outcrop in China and its shale gas significance
ZHANG Jinchuan,TAO Jia,LI Zhongming,YANG Yuanyuan,WANG Dongsheng,ZHANG Dong,LI Qianchao,WU Xiangzhen,NIU Jialiang,ZHAO Xingxu,LANG Yue
Reservoir Evaluation and Development    2022, 12 (1): 29-46.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.003
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In China, shales are widely distributed, continuous in time and complex in space. In this paper, the distribution of shales in the North China, South China and Tarim Plates are systematically sorted out and discussed. The Middle and Upper Proterozoic shales are dominated by marine facies with some continental facies, of which the littoral-neritic to neritic shelf, marine and continental moraine shales are developed, and the field shale sections are characterized by the distribution on the edges of different paleoplates. The Lower Paleozoic shales are dominated by marine facies, with the development of open shelf to neritic shelf shales, which are mainly distributed in the South China Plate and the Tarim Plate. The Upper Paleozoic shales which are dominated by marine-continental transitional facies and locally by marine and continental facies have the largest development and distribution in China. The Mesozoic and Cenozoic shale types are diverse but dominated by continental facies. The Mesozoic shales are mainly developed longitudinally along Yunnan, Sichuan and Shanxi and latitudinally from Xinjiang to Heilongjiang via Shanxi, while the Cenozoic shales are primarily developed in the eastern and western sides of the North China Plate. The plate margins, fold belts and complex tectonic activity areas exert an important impact on the distribution of shales. The ancient trough has a significant influence on the shale deposition, so do the depositional environment on the shale components, and the components on the weathering resistance of field shale sections. The development of field shale sections in different epochs and regions are affected by multi-factors, and each has specific geological characteristics. Shale in sections can be divided as manganese, siliceous, calcite or dolomite, silty, carbonaceous, coal and mixed types, in which carbonaceous shale can occur in various sections. Manganese shale is primarily developed in the strata before Middle Permian in South China Plate, while siliceous shale is mainly found in the open shelf facies, coal-type shale is developed later and mainly deposited in the marine-continental transitional facies and continental facies, The silty, calcite or dolomite shales are widely distributed. Each type of shale has specific epochal and regional distribution characteristics, so a systematic review of the shale strata in China could be helpful for the discovery for more shale gas in new strata or new areas.

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Electricity substitution technology of drilling and completion electrification promote petroleum and gas industry to achieve “carbon peak and neutrality” targets
ZHANG Liehui,ZHANG An’an,CHEN Yi’nan,DING Ning,LI Hai,QU Guanglong,WANG Tao,YAO Shaobin
Reservoir Evaluation and Development    2022, 12 (5): 703-710.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.05.001
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In recent years, extensive attention has been paid to the decarbonization of petroleum and gas exploration and related technologies at home and broad. The structural transformation of the energy industry of the oil and gas is one of the inevitable ways for China to achieve the “carbon peak and neutrality” targets. Under the prerequisite of energy reform to accelerate the achievement of the targets, the energy reform direction and pathway for the oil and gas technology have been analyzed. Taking the project of the electricity substitution technology in the PetroChina Southwest Oil and Gasfield Company as an example, the changes in terms of environmental pollution and energy consumption before and after the implementation of the project are compared. Then, it focuses on the necessity of the drilling and completion electrification transformation and the advantages of the drilling and completion are emphasized. Based on the analyses and summary of the key and difficulties in the practice process, the key technologies that restrict the development of electricity substitution technology and the breakthrough points of the future researches are put forward, which provides reference for the application of “electricity substitution” technology in oil and gas exploration and development under the “dual-carbon” targets.

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Engineered full flowsheet technology of CCUS and its research progress
SANG Shuxun,LIU Shiqi,LU Shijian,ZHU Qianlin,WANG Meng,HAN Sijie,LIU Tong,ZHENG Sijian
Reservoir Evaluation and Development    2022, 12 (5): 711-725.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.05.002
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Cluster deployment is the only way to realize the decarbonization industry development for the carbon capture, utilization and storage (CCUS) technology. The innovation and development for the engineered full flowsheet technology of CCUS is the key and urgent need to complete the scale deployment of CCUS decarbonization industry cluster, serving great significance to China’s energy security and carbon neutrality. In this study, the scientific connotations are clarified. The concept is proposed. The basic mode, application mode and key combination mode are firstly summarized, then the technologically scientific process is analyzed. The key techniques are summarized. The formation mechanisms are investigated. The representative project cases both at home and abroad are summarized. The current challenges and outlook are discussed and analyzed. Current works have shown that the efficient CO2 capture technology, CO2 chemical and bio-utilization, CO2 mineralization, efficient CO2 geological utilization and storage are the core connotation, with CCUS system optimization, source-sink matching and technology matching as the configuration mechanisms. The full flowsheet technology of CCUS is complex and diverse, with five main steps composing in its technical and scientific process. The framework of this technology has been established, and a lot of progress has been made in the field of scientific research and engineering applications. However, there is still a gap between China and developed countries in Europe and America in this field. The main direction of tackling challenges in China includes: accelerating the engineering demonstration of CCUS cluster scale deployment, strengthening the formation mechanism of the engineered full flowsheet technology of CCUS cluster scale deployment technology and scientific research, focusing on the breakthrough of CO2 capture, geological storage, and other key technical links among the engineered full flowsheet CCUS technology.

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Characteristics of geological section of Well-GY8HC in Gulong Sag, Northern Songliao Basin
HE Wenyuan,FENG Zihui,ZHANG Jinyou,BAI Yunfeng,FU Xiuli,ZHAO Ying,CHENG Xinyang,GAO Bo,LIU Chang
Reservoir Evaluation and Development    2022, 12 (1): 1-9.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.001
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In order to study the lithology, property and brittleness of Gulong shale reservoir, a whole-section coring well, Well-GY8HC, is deployed in Gulong Sag. Detailed core description and element analysis show that the sedimentary microfacies in Gulong Sag are mainly semi-deep to deep lacustrine facies during the sedimentary period of Q1 to Q9 reservoirs, with thick organic-rich shale developed and can be subdivided into four types of lithology which are shale, siltstone, shell limestone and dolomite. Based on the classification principle of “structure+lithology” and combined with the lithology content characteristics, the lithofacies are divided into four types which are laminated shale, intercalated shale, massive dolomite and massive siltstone. The paleo-sedimentary environment is fresh water-brackish water+weak provenance+strong reduction in warm and humid climate, providing favorable place for organic matter formation and preservation. Comprehensive evaluation of three indexes of reservoir capacity, oil-bearing property and fracability shows that several reservoir space types of Q1 to Q3 reservoirs with good physical property, excellent oil bearing property and efficient fracability for shale oil production, being the most favorable interval for medium and high mature shale oil exploration in Daqing Oilfield.

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Application of seismic exploration technology in shale gas exploration and development in Nanchuan area
LIU Ming,MENG Qingli,DU Yuan,LI Yanjing
Reservoir Evaluation and Development    2022, 12 (3): 407-416.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.002
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Considering of the “Multi-Complex” geological characteristics of the surface and underground in the Nanchuan District, a set of relatively complete ideas and technical processes for shale gas geophysics exploration have been explored through technical research on seismic data acquisition, processing and interpretation. And it has been successfully applied in shale gas exploration and development in Nanchuan District, including three aspects: ①In terms of acquisition, the quality of seismic data in limestone outcrops, karst caves and mined-out areas can be improved through real-time optimization of excitation points; ②In terms of processing, in order to improve the imaging effect, high-precision static correction technique in complex mountainous areas, the targeted processing technique in karst cave and goaf, and the Anisotropic Pre-Stack Migration Imaging technique are adopted; ③In terms of interpretation, on the basis of fine structure interpretation, the “sweet spot” prediction of shale reservoir is carried out from three dimensions: the enrichment of shale gas, the remodelling of reservoir and the driving of reservoir., and in the process of developing shale gas, horizontal well drilling is guided by prediction technology of dynamic target buried depth and formation dip prediction technique for horizontal wells.

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Characteristics and exploration significance of Wufeng-Longmaxi Formation stratigraphic section in Mount Huaying, Sichuan Basin
XIONG Liang,DONG Xiaoxia,ZHAO Yong,WEI Limin,WANG Tong,WANG Yan
Reservoir Evaluation and Development    2022, 12 (1): 58-67.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.005
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In recent years, the exploration of Longmaxi Formation in Sichuan Basin has been successful, but the shale gas of the complex structural belt’s Longmaxi Formation are still the next areas for exploration. Therefore, it is necessary to carry out systematic researches on the Sanbaiti section in Mount Huaying of high-steep structural belt in Sichuan Basin, so as to provide ideas for the further exploration breakthrough. The section’s lithology, paleontology, mineral composition, geochemical characteristics, pore type and structure are studied, and compared with the drilling wells of adjacent areas. The findings are as follows. ①The outcrop in Mount Huaying section is well exposed. The shale strata from Wufeng Formation to the bottom of Longmaxi Formation are complete and continuous. Wufeng Formation is divided into two sections, and the Longmaxi Formation(no top) is divided into three sections. The WF2-LM9 graptolite biozone is well developed. From the bottom to the top, the sedimentary environment changed from reduction to oxidation, and the biogenic siliceous environment has been destroyed. The injection amount of terrigenous debris increases, and the abundance of organic matter shows a downward trend. The organic matter in Long-1 member of Wufeng Formation is relatively rich, and the content of brittle minerals is high. The reservoir space is dominated by organic pores, followed by inorganic pores and microfractures. The pore structure is dominated by ink bottles, and a small amount of slit pores. ②For the Hirnantian-Rhuddanian, although the Sanbaiti section of Mount Huaying is located in the deep-water shelf zone in southern Sichuan, the underwater highland micro-paleogeomorphology is locally developed. Due to the influence of undercurrent and other factors, the deposition thickness of organic-rich shale is thin. So that, the micro-paleogeomorphology has an important influence on the material basis of shale gas formation, which can provide ideas for the further evaluation of Longmaxi Formation. ③The formation of organic-rich shale reservoirs in Long-1 member of Wufeng Formation is mainly controlled by the combined action of volcanism, source supply and reduction environment.

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Multi cluster perforation optimization design method and its application effect of tight sandstone horizontal wells in Qiulin area, central Sichuan
TANG Botao,ZENG Ji,CHEN Weihua,CHEN Yixin,WANG Tao,LIU Cheng,FENG Feng
Reservoir Evaluation and Development    2022, 12 (2): 337-344.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.009
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In order to solve the problems that the natural cracks of the dense sandstone reservoir in Sichuan region is undeveloped with low hole, low permeability and strong spatial heterogeneity, the transformation idea of “segment clusters created + sand + high strength long slot” is established by the indoor model experiments. On this basis, a calculation model of stress field around the wells based on the effective stress theory is established. Meanwhile, the above model is combined with the flow-stress coupling fracture extension model for horizontal wells to clarify the influence mechanism of cluster spacing on the crack competition expansion and interseam seepage interference. Therefore, the non-uniform arrangement method of cracks in the sand body of river channel considering stress interference and seepage shadow is formed. It is concluded that the optimal spacing of multiple clusters in the horizontal well section of dense sandstone in Qiulin is seven to twelve meters, which can make the opening rate of the injection cluster up to 92.3 %. This method effectively improves the effect of the transformation of the tight gas reservoirs.

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Development characteristics of microfractures in tight sandstone reservoir and its influence on physical properties: A case study of Shiligiahan zone in Hangjinqi
ZHAO Lan
Reservoir Evaluation and Development    2022, 12 (2): 285-291.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.003
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The average porosity and permeability of sandstone of Lower Shihezi Formation of Permian system in Shilijiahan area of Hangjinqi area are of 8.3 % and 0.89×10-3 μm2 respectively, causing the reservior to be a typical tight sandstone reservoir. Meanwhile, the microfractures play an important role in improving the physical properties of tight sandstone reservoir. Therefore, the researches of the reservoir in this area focus on the microfractures. By the observation of the microscopic thin section, and combined with the mercury injection, core physical properties and structural characteristics, the types and genesis, formation stages, control factors and the influence of micro fractures on physical properties in this area have been studied. The results show that the tight sandstone of Lower Shihezi Formation in the study area can be divided into intragranular fracture, grain edge fracture and grain penetrating fracture according to the contact relationship of strata, and can be divided into unfilled fracture, incomplete filled fracture and complete filled fracture according to the filling degree. According to the genetic analysis, there are at least three stages of micro fractures in the study area. Their development degree are controlled by the combination of internal factors (sandstone particle size, rock debris composition, rock debris and interstitial content, contact relationship between particles, etc.) and external factors (tectonic stress). The microfractures mainly affect the permeability of the reservoir. The multi-factor influence is a basic feature of micro fractured tight reservoir. The average throat radius plays a major role in controlling the permeability of the reservoir.

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Outcrop of Ordovician Wufeng Formation-Silurian Longmaxi Formation in Qilong Village, Xishui, Guizhou
LIU Shugen,RAN Bo,YE Yuehao,WANG Shiyu,YANG Di,LUO Chao,HAN Yuyue,SONG Jinmin,ZHANG Xuan
Reservoir Evaluation and Development    2022, 12 (1): 10-28.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.002
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As a systematic study of the Wufeng-Longmaxi Formation was carried out by paleontological comparison, thin section identification, scanning electron microscopy and Nitrogen Adsorption Method in Qilong Village outcrop, Xishui, Guizhou Province, the following main insights are obtained: ① The Wufeng-Longmaxi Formation in Qilong Village outcrop is complete, and is conformable with overlying Silurian Shiniulan Formation and the underlying Ordovician Jiancaogou Formation, with 12 graptolite biozones developed and without unconformity; ② Based on a variety of sedimentary fabric features, six major shale lithofacies in the Wufeng-Longmaxi Formation are determined; ③ The quartz content of the Wufeng Longmaxi Formation decreases, while clay minerals increase gradually from the bottom to the top in Qilong Village outcrop, which shows the content of brittle minerals decreases, and a decrease of fracability of the shale from the bottom to the top; ④ The organic matter types of Wufeng-Longmaxi Formation in Qilong Village outcrop are mainly of type Ⅰ and type Ⅱ1, and the high TOC shale is mainly distributed in the Wufeng and lower Longmaxi Formation; ⑤ There is relatively low paleoproductivity of the Wufeng-Longmaxi Formation in Qilong Village outcrop. The high quality black shale was deposited in anoxic-dysoxic conditions, and high content of organic matter benefits from the high burial efficiency of organic matter; ⑥ The organic pores of the Wufeng-Longmaxi Formation in Qilong Village outcrop are mainly distributed in Wufeng and lower Longmaxi Formation, while organic pores were not developed in the upper member of Longmaxi Formation or Guanyinqiao member. The abundance of the small pores vertically decreases with stratigraphy upwards and The abundance of the large pore increases with stratigraphy upwards; ⑦ The natural gas adsorption capacity of the Wufeng-Longmaxi Formation in Qilong Village outcrop is a minimum of 1.62 m3/t, a maximum of 2.8 m3/t, and an average value of 2.13 m3/t. This shows that the larger the TOC value is, the stronger the corresponding adsorption capacity will be, and indicates organic matter content plays a decisive role in gas-bearing capacity of organic-rich shales.

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Geological characteristic and its implications of shale exploration in Qijiang, Chongqing, China
GAO Yuqiao,LIU Nana,ZHANG Peixian,HE Guisong,GAO Quanfang
Reservoir Evaluation and Development    2022, 12 (1): 119-129.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.010
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Detailed field description and experimental analysis have been carried out for Wufeng-Longmaxi Formation shale profile in Anwen Town, Qijiang, Chongqing, by field profile observations and field measurements. Three kinds of lithology formation, namely black siliceous shale of Wufeng Formation, dark gray shell argillaceous limestone of Guanyinqiao and black shale of Longmaxi Formation,are exposed from bottom to top in shale section of Anwen Town. There are three main conclusions. First, the exposed shale is the main formation of current exploration and development, the indicators of reservoir forming conditions are superior, TOC ranges from 1.10 % to 8.10 %, with an average of 3.40 %. The average Ro is 2.70 %; Quartz content ranges from 33.90 % to 56.60 %, with an average of 42.36 %, and clay content ranges from 18.00 % to 57.20 %, with an average of 42.62 %. Second, the main reservoir space types are microfracture, organic pore and inorganic pore. Third, combined with the exploration and development practice, the ①~③ subzone of black shale at the lower part of Wufeng-Longmaxi Formation is the sweet spot section, which is a favorable target of horizontal well.

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Gas-water flow characteristics and influencing factors of tight sandstone in Danfengchang Gas Field
YANG Yubin,XIAO Wenlian,HAN Jian,GOU Ling,LI Min,ZHOU Keming,OUYANG Mukun,CHEN Li
Reservoir Evaluation and Development    2022, 12 (2): 356-364.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.011
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In order to understand the influence of displacement pressure on the gas flow capacity for different types of reservoirs and clarify the reasonable production pressures of different types of reservoirs, the tight sandstones of the main reservoir type Ⅱ and Ⅲ in the Xujiahe Formation of Danfengchang Gas Field are taken as the research object. And with the help of the NMR technology, the gas-flooding experiments of the tight rock samples of the two types of reservoirs under different displacement pressures are carried out to analyze the effect of displacement pressure on the gas flow capacity. The results show that the the pore structure and the displacement pressure difference have different effects on the gas flow characteristics of the rock samples in type Ⅱ and type Ⅲ reservoir. The gas flow characteristics of the rock samples in type Ⅱ reservoir are mainly affected by the displacement pressure difference. The greater the displacement pressure difference, the stronger the gas flow ability. And it mainly affects the flow ability in the small pore throat. While the pore structure and displacement pressure difference of type Ⅲ reservoir rock samples affect the gas flow characteristics together. When the capillary pressures of the layers are close to each other, the gas flow capacity is the best. Therefore, for tight sandstones in different types of reservoirs in Danfengchang Gas Field, the best production pressure should be used to achieve the best gas flow capacity during production.

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High precision numerical simulation of thin sandstone reservoir with sufficient bottom water and multiple cyclothem: A case study on lower formation of 9th block of Tahe Oilfield
LIU Xueli,ZHENG Xiaojie,DOU Lian,XIE Shuang,PENG Xiaolong,ZHU Suyang
Reservoir Evaluation and Development    2022, 12 (2): 391-398.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.015
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The sufficient bottom water energy and complex rhythmic layer distribution in the lower oil formation reservoir of 9th block of Tahe Oilfield lead to the great difficulties of the conventional numerical simulation technology to characterize the complex bottom water rising regulation and the effect of EOR measures. Taking the lower Triassic oil formation reservoir in 9th block of Tahe Oilfield as an example, the high-precision numerical simulation technology under the background of non up-scaling geological model is introduced. By the early movable water simulation, single diaphragm flow, multiple diaphragm flow and dynamic relative permeability techniques are deployed. Then, the reservoir history matching research is carried out, and the overall production matching degree of the reservoir reaches 95.23 %. At the same time, the high precision numerical simulation technology is used to predict the field rate enhancement and gas injection measures, which is highly consistent with the field production effect. In the process of high-precision numerical simulation, the water breakthrough mode of horizontal well is changed from water ridge in conventional simulation to “water-breakthrough at point” mode. The main controlling factor of flow field is the collaborative control of pressure field and physical parameter field.

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Physical properties of water-bearing tight sandstone reservoir for improving permeability by thermal stimulation
YOU Lijun,WANG Yang,KANG Yili,TANG Jirui,LIU Jiang,YANG Dongsheng
Reservoir Evaluation and Development    2022, 12 (2): 320-328.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.007
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The pore throat of tight sandstone reservoir block is narrow, and during the whole process of gas reservoir development, the water phase trapping damage is easy to prone, which restrict the development process of tight gas. The field test and laboratory experimental study have proved that the heat treatment technology for reservoirs can remove this damage and increase the permeability, but it has not been popularized and applied because of the unclear reservoir physical properties. Therefore, typical tight sandstone cores in Kuqa Depression, Huimin Depression and Jidong Depression are selected in order to simulate the fracture surface where heat treatment fracturing fluid stays or the near-wellbore zone where water phase gathers in the production process. A thermal shock experiment is carried out with 3 % KCL solution completely saturated experimental cores, the permeability of tight sandstone with different reservoir quality coefficient RQI before and after thermal shock is tested, and the relationship between the reservoir quality coefficient RQI and the increasing permeability is analyzed. The researches show that the permeability of tight sandstone samples does not change obviously when heated from room temperature to 100 ℃, but decreases slightly when heated to 200 ℃, and increases by 200 %~500 % when heated to 300~400 ℃, but the permeability of some samples does not change obviously, which is related to the reservoir quality coefficient RQI of the samples. The critical value of quality coefficient of water-bearing tight sandstone reservoir suitable for thermal surge permeability is 0.25. When RQI value is less than 0.25, the thermal surge permeability amplitude of rock samples is monotonically decreasing with RQI value. When RQI value is constant and heat shock temperature is greater than 200 ℃, the higher the temperature, the better the effect of thermal surge infiltration.

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Efficient development technique of tight sandstone gas reservoir in narrow channel of Zhongjiang Gas Field
LIU Chengchuan,WANG Yongfei,BI Youyi
Reservoir Evaluation and Development    2022, 12 (2): 345-355.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.010
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Efficient development of Zhongjiang gas reservoir is faced with four difficulties: the meticulous channel depiction, the establishment of high-yield enrichment mode, the formulation with development technology policy, and corresponding engineering fracturing technology. For the narrow channel sand bodies, the multi-domain and multi-attribute fine description and accurate reservoir prediction technology are used, and the spatial distribution characteristics of multi-stage and overlapping channel sand bodies are well described. It can depict the channel sand bodies of the thinnest 8 m and the narrowest 50 m, and the sedimentary time sequence of each channel sand body is also very clear. An improved three-parameter pre-stack inversion technique based on ray parameter domain is used to realize the high-precision quantitative prediction of thin-layer, the predicted error of reservoir thickness and porosity is less than 10 %. By establishing an effective combination model of source rock fault and channel sand, with high ancient and modern structures or high ancient and low modern structures, and good reservoir physical properties, it is expected to obtain high and stable production of gas wells in these areas. By using the techniques of 3D deployment of well groups, well pattern optimization and horizontal well optimization design, the production degree of tight sandstone gas reservoir in narrow channel is greatly enhanced, and the investment cast is saved. By using the integrated horizontal well fracturing technology, the single well test gas production is steadily increased, and the transformation effect is increased to 10.6 times before implementation. High-efficiency development technology of tight sandstone gas reservoir formed by narrow channel enables efficient exploration and development of the Zhongjiang Gas Field, the largest gas field of Sinopec in western Sichuan, with an annual gas production of more than 1 billion cubic meters.

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Practice of potential tapping of remaining gas in channel sandstone gas reservoir under the background of mudstone interlayers development: A case study of JS22 gas layer in Xinchang Gas Filed
LI Hongwei,YUAN Jian,ZHAO Zhichuan,ZHOU Zhilin
Reservoir Evaluation and Development    2022, 12 (2): 365-372.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.012
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The JS22 gas reservoir in the Xinchang Gas Field is the microfacies of distributary channel deposit in the delta front subfacies. The mudstone interlayer developed in some sandstone layers form the channel sediments twice. For some gas wells with double developed sand layers, the perforation and fracturing are carried out only in one of the two layers, while the rest may be blocked by mudstone interlayer, resulting in its untapped situation. However, the understanding of the distribution rule of the mudstone interlayer is unclear, and the sealing performance of interlayers hasn't been verified by precedent, limiting the development of the remaining gas in this reservoir. By the establishment of the logging curve identification standards of the interlayer, the interlayer of every single well is identified and divided, and the development scale and plane distribution rule of the interlayer are studied. And then, the old wells are used to explore the vertical sealing performance of the mudstone interlayer inside the channel sandstone. The study results show that the mudstone interlayer, with the thickness of 1~15 meters, is mainly distributed in the east of the JS22 gas reservoir, and has the characteristic of one thin-line area laying between two thick areas along the distribution direction. In the application of potential tapping of Well-A1, the production obviously increase after the perforation and sand-fracture, firstly verifying that the mudstone interlayer with the thickness of 10 meters in A1 well area has better vertical sealing performance. This achievement will provide new ideas and practical basis for the development of remaining gas in the JS22 gas reservoir, and is of great significance for improving the recovery rate of the entire gas reservoir.

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Analysis of logging characteristics of high quality shale gas reservoirs
MA Lin,JIANG Xiani,GONG Jinsong
Reservoir Evaluation and Development    2022, 12 (3): 445-454.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.006
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The logging response characteristics of different productivity shale gas wells are obviously different. By comparing and analyzing the logging response characteristics of shale gas well with different productivity, the logging response characteristics of high production shale gas reservoir are summarized. Then, by the analyses of the differences of lithology, electrical properties, physical properties, in-situ stress and pore pressure in shale gas wells with different productivity, and the geophysics logging information such as resistivity logging, radioactive logging and acoustic scanning, etc., a set of high-quality and high-yield shale reservoir identification methods based on integrated logging response characteristics is developed by considering the key parameters of organic quality and formation pressure to reflect shale gas productivity. The results show that the electrical characteristics of high-quality and high-yield shale reservoirs are high gamma-ray, low density, low neutron, high acoustic time difference and medium-high resistivity. This set of analysis method can accurately identify the exploration and development potential of shale reservoirs. The comparison between the field gas test results of different types of shale gas reservoirs in different shale gas blocks in southeastern Sichuan and the results of comprehensive well logging analysis shows that the method has a high coincidence rate. It can provide scientific basis for later completion plan decision of shale gas well.

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Sedimentary micro-facies and gas bearing property of He2+3 Member in Shiguhao gas area, northern margin of Ordos Basin
GAO Zhaopu
Reservoir Evaluation and Development    2022, 12 (2): 292-301.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.004
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Taking He2+3 Member in shiguhao gas area of Dongsheng gas field as the research object, the types and plane distribution of sedimentary facies in this area have been described, and the relation between sedimentary microfacies and natural gas distribution has been studied. Due to the influence of complex paleogeomorphic characteristics on the sedimentary system distribution, the transportation channel of sedimentary debris and the distribution space of sedimentary system mainly is defined by the description of paleogeomorphology. On the basis of core observation, 14 lithofacies types and 5 lithofacies associations are summarized, and three sedimentary microfacies of channel bar, braided channel and river flood deposition are identified in He2+3 Member. The vertical sedimentary sequence of typical wells is analyzed, which is dominated by the normal grain sequence with coarse grain size, forming a single-stage large set of thick gravelly medium-coarse sandstone. The vertical and plane distribution characteristics of braided river sedimentary facies are characterized. The sand body is distributed in a nearly north-south strip, and the river channel migrates and swings frequently laterally. Combined with the reservoir physical parameters, the influence of different microfacies on reservoir physical properties is summarized, the distribution of gas-bearing reservoirs in sedimentary microfacies is analyzed, and finally the braided river channel bar is proved to have good physical properties and gas-bearing properties, which has great natural gas development potential.

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Evaluation of inter-well sand body connectivity by combination of well, seismic, and reservoir and its application: Taking the middle and deep layers of M area of Nanpu Oilfield as an example
LIN Weiqiang,QU Lili,ZHU Lu,FENG Linping
Reservoir Evaluation and Development    2022, 12 (2): 373-381.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.013
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M area in Nanpu Oilfield is the main water injection development block of Jidong Oilfield, and it has entered the middle water cut stage at present. The water injection effect in the main area is remarkable, but in some areas, the effect is not obvious due to the unclear understanding of inter-well sand body connectivity, and the utilization degree of water injection reserves is low. An accurate evaluation of inter-well sand body connectivity is of great significance for improving injection and production well pattern and enhancing oil recovery in this area. The sand bodies in this area change rapidly in transverse direction, and the number of layers in longitudinal direction is large and small, thus it is difficult to recognize the inter-well sand body connectivity. In order to solve this problem, the inter-well sand body connectivity is evalued by the multi-disciplinary comprehensive technology including including seismic phase technology, seismic attribute technology, seismic inversion technology and reservoir performance analysis technology. With the combination of well, seismic and reservoir, this technology has been widely used to determine the inter-well sand body connectivity in this area, and achieved good results in development practice. The research improves the accuracy of inter-well sand body connectivity evaluation, and provides a favorable basis for guiding reservoir development adjustment in this area. It is of good reference for the evaluation of the inter-well sand body connectivity in the same type reservoir.

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Adjustment countermeasures for efficient development of deep coalbed methane in southern Yanchuan CBM Field
YAO Hongsheng,XIAO Cui,CHEN Zhenlong,GUO Tao,LI Xin
Reservoir Evaluation and Development    2022, 12 (4): 545-555.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.04.001
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The deep underground place in China is rich in coalbed methane resources, so that it is an important field of further exploration and development of coalbed methane. However, the geological conditions of deep coalbed methane resources are more complex, and it is different to deploy supporting technologies for engineering, so there is great challenge to realize efficient development. Overcoming the technical bottle-neck of efficient development of deep coalbed methane is of great significance to promote the efficient utilization of deep coalbed methane resources. Taking the development practice of deep coalbed methane in southern Yanchuan CBM Field as an example, five challenges faced in the process of early productivity construction are systematically analyzed: ① The reservoir heterogeneity is strong, and the main controlling factors for enrichment and high yield are unknown; ② The vertical resources need to be further evaluated, and the reserve utilization degree is low; ③ The deployment mode of well pattern is single, and the control area of single well in high stress and low permeability area is small; ④ The modification of the deep coalbed methane reservoir is poor, so it is difficult to achieve long-distance effective support by conventional hydraulic fracturing in the early stage; ⑤ The traditional drainage system has a long production cycle which is resulted in poor economic benefits. On this basis, through repeated exploration and practice, a new concept and key technology for efficient development of deep coalbed methane resources have been formed by “five transformations”: ① The overall productivity construction will change to accurate delineation of favorable areas; ② The development layer system changes from single layer to composite layer; ③ The well pattern deployment has converted from single vertical wells to the mixing well pattern of “vertical well + horizontal well”; ④ Reservoir reconstruction has changed from conventional fracturing to effective support fracturing; ⑤ The drainage system has changed from “slow and long-term” to “efficient increase of production”. Based on the “five transformations”, the production and construction benefits of new wells have been significantly improved, the daily output of vertical wells has increased from 1 800 m³/d to 10 000 m³/d, and that of horizontal wells increased from 10 000 m³/d to 20 000~50 000 m³/d. Good development results have been achieved, and the breakthrough of adjustment countermeasures for efficient development of southern Yanchuan CBM Field has important demonstration and driving significance for the benefit development of deep coalbed methane.

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Mechanism and calculation model of EOR by CO2 flooding
WANG Gaofeng, LIAO Guangzhi, LI Hongbin, HU ZhiMing, WEI Ning, CONG Lianzhu
Reservoir Evaluation and Development    2022, 12 (5): 734-740.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.05.004
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The proved reserves of natural gas in place in China is huge. However, realizing the long-term large scale stable production of natural gas faces a series of challenges such as enhanced gas recovery(EGR) of complex gas reservoirs, especially for those unconventional resources such as shale gas, coalbed methane and tight sand gas. Under the background of carbon neutralization, CCUS-EGR technology has broad application prospects due to owing the functions of increasing gas rate and carbon reduction. The main EGR mechanisms for CO2 flooding are summarized into three types: substitution due to dominant adsorption of carbon dioxide, continuous convective displacement and gas reservoir energy supplement. Under the consideration that the classification of occurrence states of the adsorbed, free and dissolved natural gas are applicable to all types of the gas reservoirs. The prediction method of increased natural gas ultimate recovery factor by CO2 flooding is further deduced. It is found that CO2 flooding is expected to improve shale gas recovery of more than 20 percentage points by this method. In order to break through the technology of greatly improving natural gas recovery, it is suggested to evaluate the potential of CO2 flooding to improve natural gas recovery for gas reservoirs with good geological sequestration conditions, assess the economic feasibility of CCUS-EGR technology applying in target gas reservoirs, and carry out major pilot tests of CO2 flooding in various types of gas reservoirs. The synergistic displacement effect of flue gas components and the technology of expanding CO2 sweeping volume should be focused especially.

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Occurrence characteristics and exploration potential of Carboniferous shale gas in western Guizhou
YI Tongsheng,CHEN Jie
Reservoir Evaluation and Development    2022, 12 (1): 82-94.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.007
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In order to explore the characteristics of rich accumulation and the exploration potential of transitional shale gas, the lower Carboniferous shale in southern Guizhou is taken as the research object. Based on the data of two investigation wells and two exploration wells, the analysis is conducted from the aspects of stratigraphic sequence and sedimentary facies, occurrence characteristics of shale, accumulation conditions and favorable area evaluation. The research result shows that: ① The lower Carboniferous shale deposits in western Guizhou are controlled by the NW-SE Shuicheng-Ziyun synsedimentary fault and the Shuicheng-Liuzhi uplift partition, which can be divided into weining shuicheng tidal flat lagoon-transition sedimentary facies and Shuicheng-Ziyun shallow-water shelf marine sedimentary facies, forming Weining and Ziyun depositional central areas with deposition thickness ranging from 30 m to 200 m. The sedimentary thickness of Weining-Shuicheng is 119 m, and the embedded depth of floor is between 1 500 m and 3 000 m, which is a favorable area for exploration. ② Influenced by multi-stage structure and controlled by syndeposition, the gas accumulation type controlled by the combination of folds and faults is relatively developed in this area, which is a typical gas accumulation mode controlled by the structure of anticlinal combination blocked by reverse fault. ③ On the plane, the accumulation zone of Weishui anticline and Shuicheng-Ziyun fault structure is a favorable exploration area for shale gas research in Weining-Shuicheng, the sedimentary center of Jiusi Formation, with an area of about 944 km2. There are at least three sets of organic-rich shale gas bearing beds vertically in the shale, which have good exploration potential

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Sedimentary characteristics and geological significance of outcrop in Wufeng-Longmaxi Formation, Huangying Town, Wulong District, Chongqing
HE Xipeng,GAO Yuqiao,MA Jun,ZHANG Peixian,HE Guisong,ZHOU Dina,LIU Nana,SUN Bin
Reservoir Evaluation and Development    2022, 12 (1): 95-106.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.008
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At present, the Wufeng-Longmaxi Marine high quality shale is the only case that has been commercially exploited in China. Taking Huangying section in Wulong District, Chongqing as an example, the characteristics of sedimentary geochemistry and their interrelationship of Marine high quality shale are studied by the field observation and field measurement combined with laboratory experiment analysis. The results show that: firstly, the black siliceous shales of Wufeng Formation and dark gray shell argillaceous limestone of Guanyinqiao Formation are exposed from bottom to top in Huangying section, which reflects the sedimentary environment from deep water shelf to shallow sea and then to deep water shelf. Secondly, the biostratigraphy of outcrop layer is continuous and intact, and the Kaidian-Rudan WF2-LM5 graptolite zone can be recognized. The graptolite type, content and preservation characteristics are closely related to the sedimentary environment. Thirdly, the Wulong area is located in the hydrocarbon generation center of the deepwater shelf. The high-quality shale has large thickness, superior static index, high hydrocarbon generation intensity and good material basis for shale gas enrichment. Fourthly, Wulong area is the sweet spot of both shale gas exploration and development because of the good accumulation and enrichment conditions of shale gas in small layer ①—④.

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Factor analysis and comprehensive evaluation model of shale gas well productivity based on fuzzy analytic hierarchy process: Taking Jiaoshiba shale gas field in Sichuan Basin as an example
LI Donghui,TIAN Lingyu,NIE Haikuan,PENG Zeyang
Reservoir Evaluation and Development    2022, 12 (3): 417-428.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.003
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Shale gas reservoir is an “artificial reservoir” with complex flow mechanism and many factors affecting well productivity. The key to develop the shale gas field in a scientific and efficient way is to determine the factors influencing gas well productivity and further establish productivity evaluation model. Based on the geological background and fracturing effect of shale wells in the Jiaoshiba Block, Fuling Gas Field, the factors influencing the productivity of multi-stage fractured horizontal shale gas wells are systematically analyzed. Then, the radar chart and fuzzy analytic hierarchy process (FAHP) are used to analyze the eight main factors affecting the productivity. Results show that there are obvious differences in terms of the degree various factors influencing on well productivity in different regions. Specifically, since the reservoir physical properties in the northern of the main area and western areas are favorable, the horizontal section parameters and fracturing scale are the main control factors of gas well productivity; the productivity of gas wells in the eastern area is highly related to the preservation conditions; due to the increase of buried depth in the south of the main area, the compressibility parameters and fracturing scale jointly determine the gas well productivity. In contrast, the compressibility parameters of gas wells in the southwest of the Jiaoshiba are the controlling factor. In this paper, fuzzy analytic hierarchy process (FAHP) is applied to determine the weight of various factors affecting productivity in different areas, and then a comprehensive productivity evaluation model suitable for shale gas wells is established. The results of numerical simulation and practical application show that the gas well productivity predicted by fuzzy comprehensive evaluation model is applicable to the infill wells in the Jiaoshiba Block, and the model is effective to analyze and predict the productivity and development effect of shale gas well.

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Poststack fracture prediction technology of shale gas reservoir based on combination of well and seismic in Nanchuan
SUN Xiaoqin
Reservoir Evaluation and Development    2022, 12 (3): 462-467.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.008
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Natural fractures are well developed in shale gas reservoirs, which have great influence on reservoir reconstruction and later fracturing effect. Therefore, the fracture prediction is carried out by ant tracking technology based on the combination of logging and seismic. Firstly, the curves for the fracture development density of the wells are obtained by the calculation of the natural fractures by well logging. Then, by the comparison of various simulation methods, the Gaussian random method is selected, which can reflect the heterogeneity of fracture development in shale reservoir and establish the natural fracture model between wells. Finally, the Co-Kriging interpolation method is used to reflect the properties of inter-well fracture development, and ant attributes are input for the quality control in order to establish the prediction model of natural fractures in Nanchuan area. According to the prediction results, the fractures in Nanchuan area develop along the NE direction. The fractures in the east wing of Pingqiao anticline are more developed than those in the core, and the fracture network are easy to form. The prediction results are highly consistent with the actual drilling wells. This fracture prediction technology can guide the exploration and development of this area.

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Pore characteristics and evaluation of shale reservoir in Lower Carboniferous Luzhai Formation, northern part of middle Guangxi Depression
TAO Jinyu,SHEN Baojian,HU Zongquan,PAN Anyang
Reservoir Evaluation and Development    2022, 12 (3): 437-444.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.005
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The upper Paleozoic Marine shale in middle Guangxi Depression, namely Guizhong Depression, has experienced complex tectonic evolution and thermal evolution. As the main production layer of shale gas, the microscopic pore structure characterization and reservoir pore evaluation of the shale in lower Carboniferous need to be studied urgently. Focus on the Lower Carboniferous Luzhai Formation shale reservoir in the northern Guizhong Depression, the material composition and reservoir pores of the shale are characterized and evaluated in detail by rock thin section, scanning electron microscope, Xray diffraction, porosity and isothermal adsorption tests on samples both from fields and cores. The results show that the TOC in the shale of Luzhai Formation is 0.4 % ~ 6.6 %. The organic matter is in the stage of high mature to over-mature thermal evolution. The content of brittle minerals such as quartz is high, with a good fracturing ability. The shale in Luzhai Formation, with an average porosity of 2.91 % and an average permeability of 0.007 9 ×10-3μm2, is a kind of low porosity, ultra-low permeability and good breakthrough pressure shale gas reservoir. There are five types of pores in the shale reservoir: the residual intergranular pore, intergranular pore, intragranular dissolved pore, clay minerals interlayer pore and organic pore. The main contributors are the clay minerals interlayer pores, the organic pores and the pyrite intergranular pores. The aperture rangs from 17 nm to 65 nm, most of which are microporous or mesoporous with the scale less than 50 nm. The connectivity between the pores is poor and there is a certain connectivity inside the pores.

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High precision stratigraphic framework modeling for oil and gas reservoirs based on VBM algorithm: A case study of Xu2 Formation in Xinchang tectonic zone, western Sichuan Depression
SHANG Xiaofei,WANG Mingchuan,LI Meng,ZHAO Lei
Reservoir Evaluation and Development    2022, 12 (2): 302-312.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.005
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The Xujiahe Formation in Xinchang area of western Sichuan Depression has experienced multiple periods of tectonic movement superposition. The stratigraphic deformation is significant, and the whole stratum is characterized by “saddle” shape. In addition, several groups of reverse faults are developed, with different fault broken horizons and diverse fault crosscutting relationships. However, the conventional modeling methods can not accurately describe the complex structure-stratigraphic characteristics of the area, and the model is difficult to meet the actual production needs. Therefore, the VBM modeling method is used to establish the structural-stratigraphic framework model of Xu2 gas reservoir in Xinchang area. Based on the analysis of sedimentary and filling characteristics in the study area, the sequence stratigraphic framework is clarified. Then, the horizon and fault data are obtained based on seismic interpretation data and drilling stratification information to establish the model of fault frame and finely adjust the relation between sectional shape and cross section. The horizon model is used as the input data to calculate the stratigraphic thickness of each sand group, and to restore and construct the original formation model. The present structural-stratigraphic framework model can be established by accurately regulating the relation between faults and horizons by controlling the relevant parameters of them. The results show that VBM method can accurately describe complex structural model through volume conservation principle and tetrahedron grid characterization technology, and better deal with complex formation contact and fault distribution problems. The new stratigraphic framework model has higher grid quality than the traditional corner grid model, and the combination relation and sequence stratigraphic characteristics are maintained in the complex faults. This structural-stratigraphic model provides a more reliable model framework for the subsequent reservoir geological modeling.

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Lithfacies and “sweet spot” interval of marine shale in southern Sichuan: A case study of Shuanghe Outcrop in Wufeng-Longmaxi Formation, Changning
WANG Hongyan,DONG Dazhong,SHI Zhensheng,QIU Zhen,LU Bin,SHAO Nan,SUN Shasha,ZHANG Surong
Reservoir Evaluation and Development    2022, 12 (1): 68-81.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.006
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With the comprehensive application of the photography of full thin section, the optical microscope observation of small thin sections, TOC test, whole rocks X-ray composition test, physical property analysis and the observation of field emission scanning electron microscope, Ordovician Wufeng Formation amd Silurian Longmaxi Formation in Shuanghe Outcrop in Changning area are analyzed systematically. The results show that the black shale of Wufeng-Longmaxi Formation in Shuanghe Outcrop of Changning area in southern Sichuan Basin is mainly siliceous shale, calcareous shale and mixed shale, and the average values of quartz, calcium carbonate and clay minerals are 42.5 %, 37.4 % and 14.9 %, respectively, containing a small amount of plagioclase (average 2.5 %), pyrite (average 2.7 %) and organic matter (average 5.6 %). The black shale develops mud laminae and silty laminae, and these two types of laminae are composed of five bedding types: graded horizontal bedding, homogeneous bedding, banded silty sand horizontal bedding, sand mud graded horizontal bedding and sand mud thin interbedded horizontal bedding. Progressive horizontal bedding and homogeneity bedding are developed in Wufeng Formation, while strip silty sand horizontal bedding, sand-mud progressive horizontal bedding and sand-mud thin interbedded horizontal bedding are developed in Longmaxi Formation. On the basis of mineral composition and bedding types, eleven types of lithofacies are divided. LM1 member, which is the “sweet spot” interval in Shuanghe Outcrop in Changning area, is characterized by high TOC content, high siliceous content, high porosity, high permeability, high horizontal/vertical permeability ratio and high organic pore content. The strip silty sand horizontal bedding develops here.

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Structural characteristics and gas storage properties of gas hydrates based on molecular simulation
XIANG Xueni,HUANG Liang,ZHOU Wen,ZOU Jie,ZHANG Zhuoya
Reservoir Evaluation and Development    2022, 12 (5): 825-832.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.05.015
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Natural gas hydrate are rich, which is one of the most potential new energy resources with abundant resources. However, gas hydrate has not been exploited commercially at present, and its micro-structure characteristics and gas storage mechanism need to be clarified urgently. Based on the framework and guest molecular information of SI, SII and SH type gas hydrates, the molecular models of three typical gas hydrates are constructed and optimized. The hydrogen bonds number, hydrogen bonds length, porosity, pore composition, pore size distribution and other structural characteristics of hydrates are determined by structural characterization, and the micro-structure differences of three typical hydrates are compared and analyzed. Based on the hydrate skeleton structure, the adsorption behavior of methane and carbon dioxide is studied by the grand Canonical Monte Carlo method. Combined with the adsorption capacity and adsorption heat, the gas storage characteristics and differences of the three hydrates are clarified. The results show that the hydrogen bonds in SII hydrate are the longest and the most abundant, but the pore connectivity is the worst. High pressure is conducive to increasing the gas storage capacity of hydrate, while low temperature can increase the stability of gas adsorption in hydrate. Although the amount of carbon dioxide storage is smaller than that of methane, the adsorption stability of carbon dioxide is stronger. The adsorption capacity of gas in SII type hydrate is the largest, and the adsorption heat in SI type hydrate is the largest.

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Relation between macro-heterogeneity of reservoir and gas reservoir types of He-1 Member in eastern Hangjinqi
FAN Lingling
Reservoir Evaluation and Development    2022, 12 (2): 274-284.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.002
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In order to solve the problems of the difference in macro-heterogeneity between the southern and northern sandstone reservoirs in the southern and northern He-1 Member of Hangjinqi, Ordos Basin, and the unclear relationship with gas reservoir types, the He-1 sandstone reservoir is taken as the research object and its identification criteria for reservoirs and compartments are defined by sandstone classification. Then, the sand body combination style is establish. And according to the development characteristics of the reservoir in the study area, the ratio of reservoir thickness to formation thickness, the ratio of reservoir thickness to formation thickness, the number of barriers, and the frequency and density of barriers are selected to characterize the characteristics of macro-heterogeneity of He-1 Member. The relation between the macro-heterogeneity and gas reservoir types is discussed. The researches are conducted as follows. ①The sandstone of the He-1 Member is divided into three types. The properties of the microfacies of box-shaped core beach in the type Ⅰ reservoir is better than that of the filling facies of the toothed box channel in the type Ⅱ reservoir. ②Three sand body assemblage modes of the He-1 Member are established. The southern part is dominated by the assemblage modes of type Ⅰ and type Ⅱ sandbody, and the northern part is dominated by the assemblage modes of type Ⅲ sandbody. ③The macro-heterogeneity of the reservoir in He-1 Member is strong in the south part and weak in the north part. ④Lithological gas reservoirs are developed in the south part with the ratio of reservoir thickness to formation thickness of less than 0.3. While the ratio of reservoir thickness to formation thickness of the north-east part is greater than 0.3 with good reservoir connectivity, which is mainly used as a natural gas migration channel and conducive to the formation of structural gas reservoirs and structural-lithological composite gas reservoirs. The gas-bearing capacity of type Ⅰ reservoirs in the south is better than that in the north. The conclusion is that the macro-heterogeneity of the reservoir of He-1 Member is strong in the south part and weak in the north-east part; the macro-heterogeneity of the reservoir affects the type of gas reservoirs, making the south part to be a lithologic gas reservoir area, and the north-east part to be a structure-lithological complex gas reservoir area. Type Ⅰ reservoirs with a ratio of reservoir thickness to formation thickness of less than 0.3 in the south part are the favorable target areas for well location deployment. It points out the direction for the selection of exploration area in He-1 gas reservoir.

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Target position optimization for shale reservoirs in Zigong Block of southern Sichuan Basin
ZHANG Chenglin,YANG Xuefeng,ZHAO Shengxian,ZHANG Jian,DENG Feiyong,HE Yuanhan,ZHANG Deliang,WANG Gaoxiang,ZHONG Guanghai
Reservoir Evaluation and Development    2022, 12 (3): 496-505.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.012
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Zigong Block, which is located in the southern side of Weiyuan Slope in Sichuan Basin, is a monocline in NW-SE direction. O3w-S1l1-1 is the target layer of that block, which develops black shale with rich organic matters in deep-water continental shelf, while the longitudinal heterogeneity of the reservoir is strong. Different penetration degrees in the sweet spot of horizontal shale well lead to different testing results. In order to determine the longitudinal distribution of the optimal shale target and guide the tracking and adjustment of horizontal well drilling trajectory, based on stratigraphic subdivision, fine evaluation of reservoir is carried out by the comprehensive data of drilling, logging, well testing and laboratory analysis. Meanwhile, the gas production profile data are used to evaluate the impact of the target on shale gas productivity of the horizontal wells. The research results show that: ①Under the influence of both sedimentation and tectonics, the lower part of S1l1-1-1 are the optimal “sweet spots” for both geology and engineering among target layers; ②The production well logging data indicate that, the lower part of S1l1-1-1shows highest gas production contribution of per unit length, which is the optimal target position of the research area; ③The effective fracking length of shale reservoir in the lower part of S1l1-1-1 for horizontal well is the key factor for gas well productivity in Zigong Block. Based on the above results, which supports the productivity evaluation of shale gas effectively, and sets the foundation for realizing large-scale and cost-efficient development of shale gas in that block, the longitudinal distribution thickness of the optimal target in Zigong Block is accurate from 2~5 m to 1~2 m.

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Variation of crude oil properties with multi-cycle CO2 huff-n-puff of horizontal wells in ultra-low permeability reservoir
LIAO Songlin,XIA Yang,CUI Yinan,LIU Fangzhi,CAO Shengjiang,TANG Yong
Reservoir Evaluation and Development    2022, 12 (5): 784-793.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.05.010
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CO2 huff-n-puff after fracturing of horizontal wells can effectively improve the properties of crude oil and increase the oil recovery of ultra-low permeability reservoirs. Combined with the geology and fluid characteristics of a typical ultra-low permeability reservoir, Block H, the mechanism of multi-cycle CO2 injection in horizontal wells and the variation of crude oil properties in ultra-low permeability reservoirs are studied by means of laboratory experiment and numerical simulation. The results show that after CO2 injection, the saturated pressure of crude oil increases, the volume expands, the viscosity decreases, and the system becomes lighter. And the main action mechanism of different stages of CO2 huff-n-puff are different: in the injection stage, the main mechanism is to supplement the formation energy, dissolve in crude oil, and reduce the crude oil viscosity; in the soaking and the initial stage of production, the main mechanism is to reduce the crude oil viscosity and expand the scope of CO2; in the middle and late period of well opening production, the light hydrocarbons and a small amount of intermediate component hydrocarbons in the oil phase are extracted. The CO2 content in oil phases at different distances in the reservoir is analyzed by the method of fixed time and fixed point, and it is deduced that the lateral sweep radius of CO2 injection along the fracture in H block is 24~40 m. With the increase of the huff-n-puff cycle, the increase of molar content of CO2 in the oil phase decreased from 451 times in the first cycle to 0.44 times in the third cycle. The dissolved amount of injected CO2 in crude oil decreases relatively, and the effect on the properties of crude oil also gradually decreases. The above research provides a new analysis method for understanding the mechanism of CO2 huff-n-puff, and provides some theoretical support for further popularizing the multi-cycle CO2 huff-n-puff technology of horizontal wells in ultra-low permeability reservoirs.

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Mechanism of coal wettability on storage state of undersaturated CBM reservoirs
ZHU Suyang,MENG Shangzhi,PENG Xiaolong,LI Xiangchen,ZHANG Qiangui,ZHANG Si
Reservoir Evaluation and Development    2022, 12 (4): 580-588.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.04.005
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The wettability decides the fluid distribution in porous media, and the wet-phase fluid will primarily occupy the smaller pore. Based on this principle, the paradox between laboratory test of coal wettability and state of fluids distribution is analyzed. On the view of wettability, two possible coalbed methane(CBM) storage types are proposed. When the coal is gas-phase wettability, owing to capillary pressure, the free gas and adsorption gas can be trapped in matrix (smaller pore system) by the water in cleat (larger pore system). In matrix system, the sorption of gas is in equilibrium state, but the storage of gas is in the undersaturated state. The critical desorption process results from the capability pressure of water and gas. When the coal is water-phase wettability, the matrix is saturated by water, and the coalbed methane can store in the matrix in liquid-phase sorption state. This study designs the experiment to validate the gas liquid-phase sorption. The results indicate that a mass of methane can be adsorbed in the matrix in the liquid-phase sorption mode.

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Application of circulating well flushing technology in southern Yanchuan CBM Field
SHAO Xiaoping,CUI Bin,LIU Yaru,XIE Xinhan,SONG Guanwei,REN Lichang,XU Jiehua
Reservoir Evaluation and Development    2022, 12 (4): 651-656.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.04.013
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During the drainage and gas production process of coalbed methane development, due to the pressure drop, the pulverized coal is prone to appear and brought into fracturing sand. At present, the pulverized coal and the deposition of fracturing sand have become the key factors restricting the continuous and stable drainage and production of coalbed methane. As the proportion of pulverized coal pump blockage in southern Yanchuan CBM Field is high, in order to effectively reduce the occurrence of this kind of operation, prolong the maintenance free period of gas wells, ensure the continuity of the production of the gas wells and cut the operation cost, a circulating well flushing device is developed and the supporting process is formulated. After the field tests, it is clear that the automatic circulation well flushing process can effectively reduce the pump inspection times of the gas well, the hollow rod automatic circulation well flushing process can effectively prolong the maintenance-free operating period of the gas well, and the pump down well flushing process can effectively improve the pump efficiency and increase the daily liquid production of the gas wells. The application results show that the CBM circulating well flushing device and supporting process are well applied in the mine, which can effectively improve the liquid flow velocity in the oil pipe, carry the sand and pulverized coal in the oil pipe to the ground, solve the pump sticking, pump plugging and pump leakage, and provide a new idea for on-site control of pulverized coal.

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Well interference evaluation and prediction of shale gas wells based on machine learning
ZHANG Qing,HE Feng,HE Youwei
Reservoir Evaluation and Development    2022, 12 (3): 487-495.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.011
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Inter-well interference seriously affects the production of shale gas wells. The evaluation and prediction of well interference degree is of great significance to the efficient development of shale gas. But the existing research mainly focuses on the interference phenomenon between shale gas wells, production performance, and parameter optimization through numerical simulation. There are few studies on the quantitative evaluation and prediction of the interference degree between shale gas wells, and the selected parameters is incomplete, which makes it difficult to objectively evaluate the well interference between shale gas wells. Therefore, the machine learning method is used to comprehensively consider the geological parameters and fracturing parameters to evaluate and predict the degree of interference between wells in the shale gas reservoir. Firstly, the initial data are processed to improve the data quality. Then, based on the processed data, cluster analysis and random forest algorithm are used to evaluate and predict the interference degree of shale gas wells. The results show that the proportions of the wells with low, medium and high well interference in the shale gas reservoirs are 25.93 %, 37.03 % and 37.04 %, respectively. The fracturing factors show significant influence on the well interference degree in the shale gas reservoirs. After parameters optimization, the prediction results of well interference degree reaches 92.07 %, indicating that the developed prediction model can be applied to forecast the well interference degree in shale gas reservoirs.

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Geological section analysis of drilling in Wufeng-Longmaxi Formation in Well-JY1
LIU Ruobing,WEI Xiangfeng,LIU Zhujiang,YAN Jihong,YUAN Tao,WEI Fubin
Reservoir Evaluation and Development    2022, 12 (1): 47-57.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.004
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The drilling geological profile of Well-JY1 Wufeng Formation and Longmaxi Formation is the first systematic marine shale gas parameter well profile. The exploration breakthrough of Well-JY1 announces the discovery of Fuling shale gas field, which is named as“Shale Gas Development merit well” by Chongqing Fuling Municipal government. With the drilling geological section in Wufeng-Longmaxi Formation of Well-JY1 as the key point, the drilling profiles of the importance of shale gas exploration and development are expounded, the profile lithostratigraphic, biostratigraphic and graptolite biozone division and fracture development characteristics are introduced, and analyzed the period of “six”shale gas reservoir characteristics and vertical distribution are analyzed. The following conclusion are obtained. Firstly, the Wufeng-Longmaxi Formation in Well-JY1 has large thickness, continuous deposition, clear stratigraphic sequence, widest range of graptolite category and good regional comparability, which can be used as the basic drilling geological section for the analyses and researches of Wufeng-Longmaxi Formation in Sichuan Basin and its surrounding areas. Secondly, affected by sedimentary facies belt, the geological characteristics of different shale gas strata are obviously different. For example, the first interval of the first Member of Wufeng-Longmaxi Formation(small layer ①~⑤), which belongs to the deep-water shelf facies generally with four high characteristic of “high TOC, high porosity, high air content, high siliceous”, is the main “sweet spot” of the shale gas exploration and development in this area. Thirdly, the small layer ①~③ in high quality shale gas reservoir, which show the high coupling law of double “sweet spot” of geological and engineering, are the optimal layers for the best target “window” of the horizontal wells. Among them, the small layer ② with high gamma value is the best position to ensure the horizontal trajectory and drilling ratio of high quality shale. The determination of high quality shale and the target “window” in deep-water shelf facies is the key for the major breakthrough of shale gas exploration in Wufeng-Longmaxi Formation of Well-JY1 and the continuous stable and high production, and also points out the direction for the selection of the areas and layers during the subsequent shale gas exploration.

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Numerical simulation of influence of water injection pressure and cave internal pressure on fracture propagation
YE Shen,QIAO Jiangmei,LI Tongchun
Reservoir Evaluation and Development    2022, 12 (2): 382-390.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.014
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The cave is the main reserve space in fracture-cavity carbonate reservoir. The basic method of fracture-cavity reservoirs exploitation is to generate hydraulic fractures connecting the boreholes and caves through hydraulic fracturing. Based on the TOUGH-AiFrac coupling solver, the influence of different water injection pressures and internal pressure of caves on hydraulic fracture propagation is studied respectively. The results show that with the increase of water injection pressure, the influence of in-situ stress on hydraulic fractures is gradually weakened, and the fractures tend to initiate and propagate along the initial direction. When the water injection pressure is 1.6 times greater than the horizontal maximum principal stress, the rangeability of the fracture initiation directions weaken obviously, and the fracture direction tends to be stable. When the water injection pressure is 2.4 times greater than the horizontal maximum principal stress, the fracture propagation path tends to be stable. The greater internal pressure of the caves, the stronger the cave’s effect on hydraulic fractures. The caves with internal pressure reaching two times of the maximum principal stress exert a kind of “attraction” effect on the hydraulic fractures, which will be gradually strengthened with the increase of cave’s internal pressure while be weakened with the increase of injection pressure. The research results can be used as a guideline to optimize the fracturing work parameters and thereby enhance the oil/gas production rate according to the geological conditions.

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Design method of plugging formula for deep naturally fractured reservoir based on efficient bridging and compact filling
XU Chengyuan,YANG Yang,PU Shi,KANG Yili,LI Daqi,ZHANG Dujie,YAN Xiaopeng,YANG Bin
Reservoir Evaluation and Development    2022, 12 (3): 534-544.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.016
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Drilling fluid loss is an important engineering and technical problem that restricts deep and ultra-deep drilling, and the well loss in reservoir interval is the most serious reservoir damage mode in drilling and completion stage. It is the main way to control lost circulation to use the bridging plugging material to block the fracture leakage channel. However, the design of bridge plugging formula often adopts the empirical or semi-empirical method, leading to low plugging success rate and poor plugging effect. By the CFD-DEM simulation, it is clear that the bridge retention, accumulation filling and pressurized plugging are three key links in the formation process of fracture sealing layer. Considering the efficient bridging and compact filling of the plugging material, and based on the concept of “absolute bridge addition” and the theory of tight packing, a new experimental formula design method for pressurized plugging is proposed. “Absolute bridging amount” is used as a optimization parameter to determine the bridging material amount in the formula. The traditional compact packing theory is improved by the “complementation method”, which overcomes its defects of poor adaptability to the filling materials with discontinuous or overlapping particle size distribution, and determines the filling material addition in the plugging formula. The results of laboratory and field experiments show that the proposed method can realize the rapid and efficient design of the formula for deep naturally fractured reservoir, effectively ensure the sealing effect of the formula for deep naturally fractured reservoir and reduce the total amount of materials in the formula and save the material cost. The proposed method provides a new idea and theoretical basis for the design of plugging formula for deep naturally fractured reservoir.

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Numerical simulation of influence of diabase bed intrusion on thermal evolution of organic rich host rock: A case study of Zhaojiashan Xiamaling Formation
LIU Junlan,ZHANG Jinchuan,WANG Sheng,CHEN Li,NIU Jialiang
Reservoir Evaluation and Development    2022, 12 (1): 255-264.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.022
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The black shales is widely distributed in Proterozoic Xiamaling Formation of Yanshan area, making the Xiamaling Formation to be an important potential target for shale gas exploration. Field profile survey shows that several sets of diabase sill intruded into Xiamaling Formation, which has great influence on oil and gas accumulation. Therefore, the numerical simulation study on the influence of a set of diabase bed about 7 m thick on the maturity of host rock is carried out based on the measurement of the field section and bitumen reflectance of the neighbouring shales. The results show that the influence range of this diabase bed on Ro of organic matter in host rock is about 8.5 m, which is about 1.2 times of its own thickness. The measured Ro values increases exponentially near the bedrock. The numerical simulation results show that the diabase will cool down almost completely after 110 years, and the disturbance range to the surrounding rock geothermal field is about 100 m, which is much larger than the influence range of Ro. Only when the surrounding rock temperature is greater than or equal to 250 ℃ can it cause the change response of the Ro values. The greater the thickness of diabase bed, the greater the influence range on Ro of organic matter in host rock, and the greater the increase of Ro near the bedrock. The influence range of diabase bed on Ro of organic matter in host rock is about the same to its own thickness.

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Molecular simulation of adsorption law for shale kerogen
LI Jinghui,HAN Xin,HUANG Sijing,YU Yangyang,QIANG Xianyu,GU Kangfu,HOU Dali
Reservoir Evaluation and Development    2022, 12 (3): 455-461.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.007
Abstract49)   HTML4)    PDF(pc) (7974KB)(17)       Save

Shale gas is unconventional natural gas, mainly CH4, occurring in organic shale. The adsorbed gas is the main source for later production of shale gas. Therefore, studying the adsorption mechanism of shale plays an important role in shale gas development. By using type Ⅱ kerogen molecules, a type Ⅱ kerogen model is established. Then, Monte Carlo method and molecular simulation method are used to study the micro adsorption behavior and mechanism of CH4 in type Ⅱ kerogen. Experimental data are used to verify this model, and the effects of pore size, temperature and pressure on the adsorption behavior are investigated. The findings are as follows: ① The higher the pore size, the greater the excess adsorption capacity of CH4. The higher the temperature, the lower the excess adsorption capacity of CH4. With the increase of pressure, the absolute adsorption amount of CH4 increases rapidly at first and then gently, and the excess adsorption amount of CH4 increases first and then decreases. ② The adsorption heat of CH4 decreases with the increase of pore size. The adsorption of CH4 in kerogen is physical adsorption. ③ When the pore size is smaller than 1 nm, CH4 is the adsorption phase in kerogen; when the pore size is larger than one nanometer(1 nm), CH4 is the coexistence of adsorption phase and free phase in kerogen.

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Pore structure characterization of Shahezi Formation shale in Songliao Basin: Based on low-field nuclear magnetic resonance technology
LI Chuxiong,SHEN Baojian,LU Longfei,JIANG Qigui,PAN Anyang,TAO Jinyu,DING Jianghui
Reservoir Evaluation and Development    2022, 12 (3): 468-476.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.009
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In order to characterize the micro pore structure of Shahezi Formation shale in Songliao Basin, nine shale samples from the lower part of the Shahezi Formation in the Songliao Basin were selected to carry out NMR T2 tests in saturated and dry conditions, and simultaneous petrophysical testing with field emission scanning electron microscope observation. The T2 relaxation characteristics, pore types and distribution characteristics were systematically analyzed. And the difference of porosity measured by the NMR method and the gas method was compared. The results show that the NMR T2 spectrum of the shale samples from the Shahezi Formation is dominated by a single peak type with shorter relaxation time, and the pore diameter is mainly distributed in the range of 10~1 000 nm. The pore types are mainly nano-scale inorganic pores, and the organic pores and microfracture generally underdeveloped. The NMR porosity calculated after deducting the base signal is 0.68 %~3.66 %, which has a good matching relationship with Helium porosity. The samples with smaller porosity are more likely to be affected by the background signal of rock matrix, resulting in the relative error of test results. In generally, the nuclear magnetic resonance technology can accurately analyze the porosity and pore size distribution of low porosity and low permeability shale samples, but attention should be paid to the NMR signal interference caused by organic matter and clay mineral bound water.

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Research on production stage division and reasonable production mode of shale gas well in Pingqiao area of Nanchuan Block
FANG Dazhi,MA Weijun,GU Hongtao,LU Bi,HU Chunfeng
Reservoir Evaluation and Development    2022, 12 (3): 477-486.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.03.010
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It is an effective way to realize efficient production of shale gas to adopt corresponding production mode in different production stages. The southern area of Pingqiao anticline in Nanchuan Block is a normal pressure shale gas reservoir with relatively low production and wellhead pressure, so the production mode needs to be further optimized. By analyzing the production characteristics of 30 wells in different stages in the southern area of Pingqiao, the reasonable production mode is summarized. The results show that the shale gas well can be divided into five production stages: pressure control, production increase and liquid carrying, intermittent production, pressurized production and low pressure and low production. In the stage of pressure control production, the principle of “keeping pressure + discharging liquid” is adopted to run downhole choke to improve the production cycle. The downhole choke is taken out to prevent the gas well from accumulating liquid in the stage of increasing production and carrying liquid. Measures such as gas lift, foam drainage are adopted in the intermittent production stage. Compressor is used to reduce the influence of pipeline gas transmission pressure in the pressurization stage. Low cost drainage technology such as jet pump is adopted in the stage of low pressure and low production. The mode has achieved good application effect in the south area of Pingqiao, which can provide reference for the development of normal pressure shale gas reservoir in the complex structural area of basin margin.

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Characteristics and exploration horizon optimization of marine-continental transitional shale in the South of North China Basin: A case study of Upper Paleozoic in Tongxu area
CHEN Qianqian
Reservoir Evaluation and Development    2022, 12 (4): 690-697.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.04.018
Abstract48)   HTML2)    PDF(pc) (2790KB)(11)       Save

The gas test breakthrough of mudstone shale of Taiyuan Formation in Well-MY1 and Well-ZDY2 has proved that the Upper Paleozoic marine-continental transitional shale gas in the South of North China Basin has potential for further tapping resources. Based on the latest data of Well-TX3 and Well-TX4, this paper comprehensively analyzes the shale geochemistry, petrology, reservoir space, physical properties and gas bearing properties of the Taiyuan Formation and Shanxi Formation of the Upper Paleozoic in Tongxu area in the South of North China Basin, the results show that: ① The organic matter of the mud shales of the Taiyuan and Shanxi Formations comes from the vascular plant and belongs to type Ⅲ Kerogen; TOC value is 1.0 %~4.5 % and belongs to good source rock; Ro value is 2.4 %~3.4 % and is in the over mature stage. The mud shale reservoir has higher brittle mineral content, which is favorable for the later fracturing reconstruction. ②The reservoir space is dominated by fractures and micro-fractures, followed by inorganic pores, less developed organic pores and isolated distribution. ③Based on the comparison of the gas test results and shale gas evaluation parameters, the shale gas resource potential of Taiyuan Formation is obviously better than that of Shanxi Formation.

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Experimental study on interfacial interaction between methane and vitrinite and durain: A case study of bituminous coal in Minhe Basin
MA Dongmin,WANG Xin,TENG Jinxiang,JI Changjiang,SHAO Kai,ZHENG Chao,JI Yusong,HUI Peng
Reservoir Evaluation and Development    2022, 12 (4): 556-563.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.04.002
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In order to study the differences in the adsorption/desorption characteristics of methane between the gelification and fusinization in the bituminous coal, the 2# coal seam of the Haishiwan Coal Mine in Minhe Basin is collected as the research object. By using the Langmuir fitting and dual-site Langmuir fitting on the experimental data of isothermal adsorption/desorption respectively, the adsorption thermodynamic characteristics of different fugacity environments are analyzed by calculating the isosteric adsorption heat, and the influence of maceral difference on coalbed methane production is discussed. The results show that: ①The adsorption of methane on the gelification and fusinization in coal accords with the Langmuir function, and the fitting degree is higher than 0.99. The adsorption capacity of the gelification is much higher than that of the fusinization. ②At the same temperature point, there is desorption lag phenomenon in both granular coal and pillar coal, which is due to the difference of adsorption heat. The fitting results of granular coal experiment are larger than those of lump coal experiment. ③The equivalent adsorption heat increases with the increase of fugacity and decreases with the increase of temperature. The influence of adsorption phase density on the equivalent adsorption heat is greater than that of temperature, leading to the adsorption of methane molecules with greater kinetic energy on the coal surface. The equivalent adsorption heat decreases with the increase of temperature as a whole. ④The adsorption capacity of different components of coal is quite different, and areas with high vitrain content should be the first choice for CBM well location deployment.

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Application of pre-stack elastic impedance inversion method based on VTI medium: A case of tight sandstone fractured reservoir in Xujiahe Formation, Western Sichuan Depression
HAN Lei,LIU Junzhou,YANG Rui,ZHANG Guangzhi,ZHOU You
Reservoir Evaluation and Development    2022, 12 (2): 313-319.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.006
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The tight sandstone reservoirs in Xujiahe Formation in Sichuan are rich in oil and gas, but highly heterogeneous. The tight sandstone fractured reservoirs of Xujiahe Formation in Western Sichuan Depression are characterized by heterogeneity. Combining with the actual situation and based on rock physics analysis, the relationship between reservoir characteristic parameters and anisotropy parameters is deduced, and the anisotropic elastic impedance inversion workflow of tight sandstone reservoirs is carried out. Based on the proposed fracture parameter inversion method, the model and the actual work field data are tested, respectively. The results show that the proposed approach has great robustness, the inversion results are in good agreement with the well-log, and the estimated anisotropy parameters can accurately show the location of fractured reservoirs and achieve effective description of the fracture characteristics of tight sandstone reservoirs.

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Geological section analysis of shale oil in Lucaogou Formation of Well-Ji-174, Junggar Basin
WANG Ran,HE Wenjun,ZHAO Xinmei,LIU Guoliang,ZHOU Zuoming,ZHAO Yi
Reservoir Evaluation and Development    2022, 12 (1): 192-203.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.01.017
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Well-Ji-174 is an exploration well with the longest core extraction and the most data in the shale oil reservoir of Lucaogou Formation in Jimusar sag, Junggar Basin. The establishment of the “iron pillar” is of great significance to the studies of the shale oil longitudinal characteristics. It is found that the lithology of reservoir is mainly transitional lithology mixed with clastic rock and carbonate rock, and changes quickly in the longitudinal direction. The lithofacies reflects the semi-deep to deep lacustrine sedimentary environment with gradually deepening upward water body. The average porosity and permeability of the reservoir are 11.1 % and 0.056×10-3 μm2, respectively, which make the reservoir presents the characteristics of medium-low porosity, low-permeability and ultra-low permeability. The dolomite and sand content of the reservoir are positively correlated with the physical property and oil content. The upper and lower sweet spots are developed. The main lithology of the upper sweet spot is clastic dolomite, allowing the formation of the reservoir space with developed dissolution pores and a thickness of 24 m. The main lithology of the lower one is fine siltstone, dolomite sandstone and dolomite siltstone, whose reservoir space with thickness of 35 m is mostly fissures and pores. The favorable area of these two sweet spots covers an area of 1 299 km2, indicating that the shale oil in Lucaogou Formation has large-scale exploration potential.

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Laboratory experiment of front migration and gas channeling of CO2 immiscible flooding
KONG Weijun,CUI Chuanzhi,WU Zhongwei,LI Lifeng,SU Shuzhen,ZHANG Jianning
Reservoir Evaluation and Development    2022, 12 (5): 764-776.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.05.008
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Currently, there are few works on the laws of front migration and gas channeling with laboratory experiments from the aspect of CO2 sweep efficiency. Therefore, a visual physical simulation device is used to carry out the physical simulation experiment of CO2 immiscible flooding of slab core. The influences of factors such as crude oil viscosity, reservoir permeability, reservoir heterogeneity and injection rate on the migration of CO2 immiscible flooding front and gas channeling laws are analyzed. The study found that under the conditions of constant flow injection in injection wells and constant pressure production in production wells, the viscosity of crude oil decreases, the permeability decreases, the reservoir is homogeneous, and the injection speed increases, which will lead to an increase in the recovery degree of CO2 immiscible flooding. Meanwhile, the decrease in the viscosity of crude oil, the lower the permeability, and the increase in the injection rate, also lead to the enhancement of the ability of the oil well to continue to expand sweep factor after gas breakthrough, that is, it can alleviate gas channeling. It is concluded that under the condition of constant flow injection in injection wells and constant pressure production in production wells, high injection rate development can alleviate gas channeling and obtain better development results. When the injection rate increased from 0.1 mL/min to 2 mL/min, the recovery increased from 15.4 % to 35.3 %, and the sweep factor difference increased from 8.3 % to 26.2 %. This research is of great significance for CO2 immiscible flooding gas channeling suppression and enhanced oil recovery.

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Change law of reservoir property during multi-cycle steam stimulation in heavy oil reservoir: A case study of HJ Oilfield
CHENG Keyang,QI Zhilin,TIAN Jie,YAN Wende,HUANG Xiaoliang,HUANG Shiwen
Reservoir Evaluation and Development    2022, 12 (5): 816-824.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.05.014
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After multi-cycle steam stimulation in HJ Oilfield, the changes of reservoir physical properties are obvious and difficult to determine, which brings serious obstacles to the design and implementation of subsequent development measures. In order to solve this problem, the relationships among porosity, permeability, wettability and steam stimulation cycles are conducted by using one-dimensional physical simulation experimental setup after the design of sweep multiples based on two wells, Well-J151 and Well-J117 in HJ Oilfield. The results show that the physical property parameters of reservoir will change under the long-term sweep of high temperature steam. In the scope of steam sweep, both porosity and permeability all increase with the increase of the steam stimulation cycles. With the increase of steam stimulation cycles, the lipophilicity of reservoir rocks gradually weakened and the hydrophilicity gradually strengthened. Based on the experimental results, the relationship between sweep multiples and porosity growth rate, as well as the chart of the relationship between oil layer sweep multiples and permeability growth rate are established. The parameters of the porosity and permeability of reservoirs in different stages of steam stimulation development can be predicted by the above relationship and chart, and the relationship and chart can be also extended to other similar heavy oil reservoirs.

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Test and application of new amphoteric-nonionic foaming agents in Lower Palaeozoic gas reservoir
YANG Bing,ZHANG Tailai,LI Jia,ZHAO Jianjun,WANG Chengfeng
Reservoir Evaluation and Development    2022, 12 (2): 329-336.   DOI: 10.13809/j.cnki.cn32-1825/te.2022.02.008
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The formation water of Lower Palaeozoic gas reservoir in Daniudi Gas Field is high-salinity and acidity, and downhole throttling technology is mostly used. Thus, the amphoteric foaming agents widely used in gas fields has poor foaming and foam stabilization performance, and this cannot meet the demand for high-efficiency and low-cost drainage gas recovery. Although dozens of foaming agents have been formed internationally, there is no reports about foaming agents developed for the characteristics of Lower Palaeozoic reservoir of Daniudi Gas Field. Considering the fluid and process characteristics of Lower Palaeozoic reservoir, and the influence of high-salinity formation water, the sensitivity to pH and the stability of foam passing through the choke, to construct a new type amphoteric-nonionic compound foaming agent with sulfonated AEO3 and lauramide propyl phosphobetaine as the main agent, coconut oil fatty acid monoethanolamide as the foaming aid, and sapindus extract as the foam stabilizer. The indoor evaluation shows that the amphoteric-nonionic composite foaming agent has strong foaming, stabilizing-foam, secondary foaming and liquid-carrying ability under high-salinity and acidic; after the field test application, the well drainage capacity improved, the pressure difference with tubing to casing decreased, and the gas production increased. It is shown that its application effect and economic benefits prospects are good. The amphoteric-nonionic composite foaming agent fills the void of the foaming agent for Lower Palaeozoic gas reservoir in Daniudi Gas Field, improving the technical problems of insufficient liquid-carrying, and has the value of popularization and application.

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