Table of Content

25 December 2023, Volume 30 Issue 6

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Summary

Research Progress of Nanofluid Phase Permeability Curves

Qu Ming, Sun Haitong, Liang Tuo, Yan Ting, Hou Jirui, Jiao Hongyan, Deng Song, Yang Erlong

2023, 30(6):  1-9.  DOI: 10.3969/j.issn.1006-6535.2023.06.001

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Nanoparticles are widely used in oil and gas reservoir development because of their extremely small size, large specific surface area and low dosage, but little research has been reported on the phase permeability curves of nanofluids. Therefore, through literature research, the effects of factors such as the number of capillary, wettability, temperature and net effective pressure on the shape of phase permeability curves before and after the oil displacement by nanofluids are reviewed, the mathematical modeling methods for constructing the phase permeability curves are summarized and discussed, and the method of obtaining phase permeability curves that is applicable to nanofluids is preferred in combination with the characteristics of nanofluids. This study can provide certain theoretical references and guidance for the accurate acquisition of phase permeability curves of nanofluids, the establishment of numerical models of phase permeability and the in-depth study of the mechanism of oil displacement by nanofluids.

Geologic Exploration

Physical Properties Prediction Method and Application of Metamorphic Buried-hill Reservoirs based on Parameters of Mud Logging Engineering While Drilling

Li Hui, Tan Zhongjian, Geng Changxi, Deng Jinhui, Zhang Zhihu, Zhang Ligang, Li Wenyuan, Li Hao

2023, 30(6):  10-15.  DOI: 10.3969/j.issn.1006-6535.2023.06.002

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The formation process of metamorphic buried-hill reservoirs in Bohai Oilfield was complicated, which was affected by tectonic movement, weathering and leaching, paleogeomorphology and other geological factors, resulting in the diversified reservoir space and extremely strong non-homogeneity. However, the existing reservoir physical properties evaluation methods had problems such as low quality of collected data, strong multi-solutions and poor real-time accuracy. For this reason, the metamorphic buried-hill reservoir in Bohai Oilfield was taken as a target area, the field outcrop sampling was carried out, interval transit time and microdrill drilling experiments were carried out to obtain the interval transit time and mechanical specific energy values of rocks with different physical characteristics, and a mathematical model of physical property index and reservoir porosity were established. The study shows that the interval transit time of the outcrops of the Archaeozoic metamorphic rocks of the Bohai Oilfield ranges from 371.75 to 617.29 μs/m, and the mechanical specific energy value ranges from 297.43 to 1207.47 MPa. The value of the mechanical specific energy shows an exponential function to decrease with the increase of the interval transit time, and the porosity shows a logarithmic function to decrease with the increase of the physical property index. The method has been popularized and applied in the metamorphic buried-hill reservoir of Bohai Oilfield, and the compliance rate with the logging interpretation results has reached more than 85%. This study provide reference and basis for the identification of metamorphic buried-hill reservoirs.

Classification Method and Application of Conglomerate Reservoir Based on ClusteringAnalysis

Liu Mingxi, Song Kaoping, Guo Ping, Fu Hong, Xu Mingxiao, Wang Longxin, Patiguri McMatty, Yun Qingqing

2023, 30(6):  16-22.  DOI: 10.3969/j.issn.1006-6535.2023.06.003

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The lithology of conglomerate is rich and variable, the pore structure is complex, the classification of reservoir type is difficult, without standardized evaluation parameters. Taking the conglomerate reservoirs of the Upper-Lower Karamay Formation in District Min-7 of Karamay Oilfield of Xinjiang as the object of study, based on the high-pressure mercury injection data of the reservoir rocks of the Formation 106, the classification scheme of the conglomerate reservoirs was established by using the clustering analysis method; the classification parameters of the conglomerate reservoirs were simplified and clarified by the methods such as the variance calculation and the validity of this method was verified by the use of the discriminant analysis in the end. The results show that the non-homogeneity of the conglomerate reservoir in the study area is strengthened as the physical properties become better and the pore-throat size becomes larger, reflecting the complexity of the conglomerate pore structure; the clustering analysis after data preprocessing can effectively classify the reservoirs, and there are significant differences between the classes; based on the quantification of parameter centralization and dispersion, six parameters for reservoir classification, such as the median pressure and the average pore-throat radius, are preferred; after the validation of the discriminant analysis, the accuracy of classification is still as high as 95.80% after the parameter preference, indicating that the method has high classification accuracy and is not geographically restricted, which makes it valuable for generalization.

Quantitative Evaluation Method of Anomalous Formation Pressure Under the Effect of Undercompaction and Its Application

Zhou Penggao

2023, 30(6):  23-30.  DOI: 10.3969/j.issn.1006-6535.2023.06.004

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The current formation pressure prediction methods based on the undercompaction theory are essentially empirical models, which are not generalizable, and the prediction accuracy is constrained by various factors. For this reason, the quantitative study of anomalous formation pressure was carried out from the perspective of rock pore volume and fluid volume. According to the theory of elastic mechanics of porous media, the quantitative evaluation model of anomalous formation pressure and pressure coefficient under the effect of undercompaction was established by comprehensively considering the factors such as temperature, stress, fluid composition, and depth change. The model is applicable to the evaluation of anomalous formation pressure with undercompaction as the main genesis, and has high accuracy. The simulation results show that the formation pressure increases under the effect of the undercompaction, but the pressure coefficient may increase, remain unchanged or decrease due to the increase of burial depth, and the influence of the increase of burial depth on the pressure coefficient shall not be neglected; the undercompaction can form both anomalous high pressure and anomalous low pressure; the changes of the formation pressure and the pressure coefficient are related to the physical properties of the fluid and the rock, and the increment of the formation depth as well as the initial depth; the influences of the compression coefficient of the fluid and the increment of the formation depth are relatively significant, while the influences of other factors are relatively weak. The research results break through the previous knowledge of the relationship between undercompaction and anomalous high pressure, and enrich and develop the theory of undercompaction.

Characteristics of the Paleocene Oil and Gas Transmission System in North Kengdong Area

Zhang Wei, Jiang Youlu, Hou Shuai, Jing Anyu, Sun Chao

2023, 30(6):  31-39.  DOI: 10.3969/j.issn.1006-6535.2023.06.005

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To address the problems such as the characteristics of the Paleocene oil and gas transmission system and its control role on oil and gas distribution in north Kendong Area, based on geological, seismic and well-logging data, we analyzed the development characteristics of the transmission elements and evaluated and classified their transmission capacity and combination types, so as to clarify the relationship between the transmission system and the oil and gas distribution. The study shows that oil source faults with strong activity during the reservoir formation period and laterally connected sand body or unconformable carrier bed are important channels for oil and gas transmission; when the fault-sand body/unconformable lateral flow coefficient is greater than the lower-limit value, the oil/gas may be laterally charged along the faults to the sand body/unconformable carrier bed. Five transmission systems have been classified according to the characteristics of the combination of transmission elements and transmission capacity, of which type Ⅰ, type Ⅱ, type Ⅲ have strong transmission capacity, and type Ⅳ, type Ⅴ have weak transmission capacity, resulting in the multilayered system was enriched in the middle of the north Kendong Area, and the oil and gas were deeply gathered in the east and west. The study results have certain reference significance for the next oil and gas exploration work in north Kendong Area.

Application in the Prediction of Thin Sand Body Within Short-term Sequence Cycle Based on 3D Seismic Data

Zhao Changyong, Chen Xiguang, Li Junfei, Song Zhihua, Chang Shaoying, Shan Xiang, Guo Huajun, Hou Gangfu

2023, 30(6):  40-47.  DOI: 10.3969/j.issn.1006-6535.2023.06.006

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Thin sand bodies are widely developed in the Cretaceous Qingshuihe Formation in the hinterland of Junggar Basin, and the thickness of the reservoir is about 10-20 m. The prediction of thin sand bodies is difficult due to the lack of discernible seismic data. With the data from logging curves and well drilling, and under the guidance of the principle of high-resolution sequence stratigraphy, the first member of the Cretaceous Qingshuihe Formation was divided into 1 long-term cycle, 2 medium-term cycles, and 6 short-term cycles. Within each short-term cycle, 6 seismic inversion slices were preferentially selected through the seismic slicing technique. By this method, the sedimentary evolution characteristics of sand bodies in six different periods, namely, low level period, lake intrusion period, high level period, lake recession period, lake intrusion period, and lake flooding period, within the first member of the Qingshuihe Formation (about 140 m thick) in the hinterland of the Junggar Basin, were identified, thus reducing the multiplicity of interpretations of the seismic data. This paper combines seismic slicing and high-resolution sequence stratigraphy, plays the role of lateral resolution of seismic data and high-resolution of wells, overcomes the lack of seismic resolution, deepens the research on the identification of thin sand body and depositional law in short-term cycle, achieves a good exploration effect, guides the deployment of wells in the field, and serves as a reference for the identification of thin bed in other areas.

Research on the Prediction Method of Hydrocarbon Migration and Accumulation Period Controlled by Oil Source Fault in Shallow Layerand Its Application

Chang Di, Lyu Hao, Sun Huaiya, Huang Lin, Yang Hao

2023, 30(6):  48-54.  DOI: 10.3969/j.issn.1006-6535.2023.06.007

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In order to study the hydrocarbon enrichment law of shallow oil source fault in hydrocarbon-bearing basins, a variety of factors affecting the hydrocarbon migration and accumulation along shallow oil source fault were comprehensively considered, and a set of prediction methods applicable to the hydrocarbon migration and accumulation period controlled by oil source fault in shallow sandy mudstone formations was established. It is clarified that the hydrocarbon migration and accumulation period in shallow oil source fault should be the superposition of the period of hydrocarbon transportation in oil source fault, the period of seepage in all regional mudstone caprocks crossed by the faults, and the period of closure formation in shallow regional mudstone caprocks. The method was applied to the shallow Guantao Formation stratum of the Manqikou Sag in the Bohai Bay Basin, and it was clarified that the hydrocarbon migration and accumulation period in the Gangdong Fault was from the middle to the end of the deposition of the Minghuazhen Formation. The determination of the hydrocarbon migration and accumulation period is of great significance in guiding the hydrocarbon exploration at the shallow oil source fault in hydrocarbon-bearing basins.

Characteristics of Geochemistry and Depositional Environment of Terrestrial Shales in the First Member of Qingshankou Formation of Changling Fault Depression in the Southern Songliao Basin

Zhao Chenxu, Li Zhongcheng, Guo Shichao, Bao Zhidong, Wei Zhaosheng, Li Lei, Wang Hailong

2023, 30(6):  55-61.  DOI: 10.3969/j.issn.1006-6535.2023.06.008

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In response to the problem of unclear understanding of geochemistry and depositional environment characteristics of terrestrial shale in the first member of Qingshankou Formation of Changling fault depression in the southern Songliao Basin, the experiments on organic geochemistry, molecular geochemistry and elemental geochemistry were systematically carried out to clarify the hydrocarbon generation potential of terrestrial shale in the study area, and to explore the controlling effect of depositional environment characteristics on the enrichment of organic matters. The study results show that the terrestrial shale in the first member of Qingshankou Formation is rich in organic matters, with an average TOC of 1.71% and an average chloroform asphalt "A" of 0.52%, which has good hydrocarbon generation potential. The types of kerogen are mainly Ⅰ and Ⅱ₁, and the thermal evolution of organic matter is at a mature stage, with the average pyrolysis parameter T_max of 447 ℃ and average R_o of 1.06%; the C₂₇-C₂₉ regular sterane indicates that the organic matter of the shale is mainly originated from lower-order aquatic organisms, such as algae, and partly imported from higher-order plants, the ratio of trace elements and biomarker compound parameters indicate that the paleoproductivity level is high, and the shale is originated from saline-water and brackish-water reducing environment, which is favorable for organic matter preservation; the chloroform asphalt "A" has a positive correlation with P/Ti and Sr/Ba, which suggests that the paleoproductivity and the preservation conditions jointly control the organic matter enrichment of shale. According to the evaluation criteria of shale oil "sweet spot" of TOC>2.00% and S₁>1 mg/g, the favorable area is determined to be 5 000 km², and the geological reserves calculated by volumetric method is 54.7×10⁸t. The study is of strategic significance for the evaluation of shale oil resource potential in the southern Songliao Basin.

Sequence Stratigraphical Analysis and Facies-Controlled Reservoir Prediction of Migratory Oolitic Beach in Triassic Feixianguan Formation, Northeastern Sichuan Basin

Tao Xiayan, Huang Tianjun, Zhang Yihua, Bian Shutao, Wei Penghui, Han Song, Deng Hui, Cai Qiang

2023, 30(6):  62-71.  DOI: 10.3969/j.issn.1006-6535.2023.06.009

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A large potential for oil and gas exploration and development is found at the Feixianguan Formation in the Qilibei-Duokouhe area of the northeastern Sichuan Basin, but the high-frequency rotary seismic identification and tracking are difficult, the multi-stage beach body is vertically stacked, and the reservoir has strong lateral non-homogeneity, so a supporting staged seismic prediction method for the migratory oolitic beach reservoir has not been formed. In response to the difficulties of the high-frequency rotary seismic identification and tracking and the staged seismic prediction of oolitic beach reservoirs, the horizontal fine tracking of internal cycles in the Fixianguan Formation was carried out on the basis of the method of zoning different seismic reflection phase zones, to make a fine prediction of multi-stage oolitic beach reservoirs in the Fixianguan Formation. The study shows that the seismic reflection interface tracking and comparison method for the sequence stratum based on different seismic reflection phases can effectively solve the problem of identifying the interface of high-frequency stratigraphic sequences, and the Fixianguan Formation has been divided into five types of seismic reflection phases: biaxial strong reflection, internal weak reflection, uniaxial strong reflection, cluttered-subparallel reflection, and multiaxial strong reflection; the results of the qualitative prediction of amplitude- and arc length-sensitive attributes and the quantitative prediction of the neural network inversion make clear that the high-quality reservoirs mainly develop in the The results of the quantitative prediction using amplitude and arc length sensitive attributes and neural network inversion showed that the high-quality reservoirs are mainly developed in the Cycle Ⅱ, and from the Cycle Ⅱ to the Cycle Ⅲ, and the reservoirs have the pattern of migrating and accumulating from the east to the west, and from the plateau to the trough. The practice has shown that the seismic reflection interface tracking and comparison method for the sequence stratum of different seismic reflection phases, combined with the reservoir prediction method controlled by sensitive attributes, is suitable for the migratory oolitic beach reservoir. This study is also useful for the fine reservoir prediction in the same type of gas reservoirs.

Characteristics of Paleo-sedimentary Environment Evolution of Doushantuo Formation in Well Zidi 1 of Yichang Area in West Hubei of China

Xu Hai, Zhou Xianghui, Lin Junfeng, Xu Lulu, Liu Zaoxue

2023, 30(6):  72-81.  DOI: 10.3969/j.issn.1006-6535.2023.06.010

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Doushantuo Formation is one of the important shale gas exploration target formations in the west Hubei of China. In view of the weak research on the paleo-environment of this formation, the paleo-environmental evolution law of the Doushantuo Formation in the Yichang Area of the west Hubei was analyzed through the collection of core samples for the testing of TOC, major elements and trace elements, and the favourable formations for the enrichment of the Doushantuo Formation were clarified. The study shows that the Member 1 and Member 3 of Doushantuo Formation are of organic-lean strata, and the Member 2 and Member 4 are of organic-rich strata, in which the Member 2 is significantly enriched in Ca, Mg, P, Ba, Sr, Zn, U, Mo, and Cu, and the Member 4 is significantly enriched in Ca, Si, P, Mo, U, Ba, and V. Member 1 and Member 3 have dry climate, high salinity, mainly oxidizing environment, and low paleoproductivity; the Member 2 has alternating warm-wet and dry-hot climate, high salinity, and frequent alternation between oxidizing and oxygen-poor environment; and the Member 4 has warm-wet climate, low salinity, and oxygen-deficient environment. Doushantuo Formation has weak paleohydraulic forces which was deposited in a strong euxinic basin, and Member 2 and Member 4 have higher paleoproductivity. Favorable block is located in the deep-water inter-platform basin at the west of Yichang City, the middle of Member 2 is a shale gas-rich favorable formation, in which the thickness of organic-rich strata with TOC>2.00% is more than 20 m, deposited in an oxygen-poor and oxygen-deficient environment, with the highest paleoproductivity, and it is the geological "sweet spot" of Doushantuo Formation shale gas exploration. The study results provide geochemical basis for the shale gas exploration of Doushantuo Formation in west Hubei of China.

Characteristics of Conversion Sedimentation Controlled by Differential Fault Activity in the Sangonghe Formation in the Moxizhuang Area

Yang Yi, Han Changcheng, Li Zhipeng, Ma Cunfei, Li Jian, Fan Jiale, Cheng Xuhui, Sun Ruyuan

2023, 30(6):  82-91.  DOI: 10.3969/j.issn.1006-6535.2023.06.011

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In response to the problems of complex oil and water distribution pattern, poor understanding of sand body depositional characteristics and depositional control factors in the second member of the Sangonghe Formation in the Moxizhuang area, the depositional characteristics of the area were analyzed, the depositional control factors were determined, and depositional modes were established in different periods to clarify the spatial location of sandstone reservoirs on the basis of the logging, coring, physical properties and seismic data and in combination with the fault activity. The study shows that in the Moxizhuang area, the braided river delta front sedimentary system is developed, which is divided into 8 kinds of lithofacies such as granularly supported conglomerate facies, sandy conglomerate facies,pebbly sandstone facies massive sandstone facies, cross-laminated sandstone facies, parallel-laminated sandstone facies, horizontal-laminated sandstone facies, mudstone facies and 6 kinds of sedimentary microfacies, such as braided watercourse, interdistributary bay, channel sand bar, mouth bar, distal bar, and shore-shallow lake microfacies according to the sedimentary characteristics; during the depositional period of the lower subsection of the second member of the Sangonghe Formation, the north fault activity was strong, so the slope-break geomorphology was formed in the study area, resulting in hydrodynamic conversion depositional features between the north and south parts of the study area; in the context of the lake level rising and hydrodynamic weakening, the activity of the south fault intensified during the depositional period of the upper subsection, which together with the graben tectonics formed by the north faults controlled the conversion of the deposition direction of the sand body in the southeastern part of the study area, and favored a shift in the depositional direction of the sand body to a nearly east-west direction. This study is of guiding significance in determining the spatial distribution of sand body reservoirs in the Moxizhuang Area.

Prediction Method for the Distribution of Dominant Paths for Oil and Gas Transmission in Sand Bodies and Its Application

Gao Wei

2023, 30(6):  92-98.  DOI: 10.3969/j.issn.1006-6535.2023.06.012

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In order to clarify the oil and gas distribution law of P_Ⅰ^1-1 sub-bed of Putaohua Reservoir in Bayantsagaan Area of northern Songliao Basin, on the basis of the research on the conditions of oil and gas transport in sand bodies and the formation mechanism of the dominant paths, the main dominant path for oil and gas transport in the sand body is determined by the distribution of sand body pore-connected distribution zones and the distribution of paleotectonic ridges on the top surface of the layer where the sand body is located; based on the sand body pore-connected distribution zone and the distribution of dominant-phase sand bodies, the subdominant paths for oil and gas transport in sand bodies are determined, thus forming a method for predicting the distribution of dominant paths for oil and gas transport in sand bodies in oil and gas-bearing basins with undeveloped fractures. The study results show that the dominant paths for oil and gas transport in sand bodies are affected by the connectivity of sand bodies and the difference in potential energy of oil and gas. Five main dominant paths for oil and gas transport in sand bodies have been developed in the P_Ⅰ^1-1 sub-bed of Putaohua Reservoir in Bayantsagaan Area, and there is one relatively large-scale north-south oriented main dominant path for oil and gas transport in sand bodies in the center and east of the area; and there are two subdominant paths for oil and gas transport in sand bodies in the northern and southeastern parts of the area. The two relatively large-scale main dominant paths for oil and gas transport in sand bodies are conducive to the accumulation of hydrocarbons from the source rocks of the underlying Qingshankou Formation within the P_Ⅰ^1-1 sub-bed, which is consistent with the distribution of hydrocarbons discovered so far, indicating that this method is feasible for predicting dominant paths for oil and gas transport in sand bodies.Accurately predicting the advantageous pathways of oil and gas transmission in sand bodies at different levels is of great significance for clarifying the distribution patterns, it will guide oil and gas exploration.

Reservoir Engineering

Optimization Design of Storage in Gas Fields Based on the Chance Constrained Programming

Zhou Jun, Hu Chengqiang, Liang Guangchuan, Zhang Ping, Peng Jinghong, Ma Junjie, Xu Dongyang

2023, 30(6):  99-106.  DOI: 10.3969/j.issn.1006-6535.2023.06.013

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Aiming at the reality that traditional deterministic optimization method of gas storage is difficult to cope with the fluctuation of natural gas users'demand, the chance constrained programming method was adopted to establish the optimization model for the design of storage in gas fields with the objective of minimizing the total investment cost under the demand uncertainty. The optimization model took the cushion gas volume, the number of wells, the number of compressors, and the number of dewatering equipment as the decision variables, and involved the constraints such as inventory change, single-well injection and extraction capacity, and demand uncertainty, etc. In view of the uncertainty of users' demand, the chance constrained programming method was adopted for the pre-processing of the uncertainty, the optimization model was applied to the gas storage W23 in a certain oil field, and the GAMS modeling system with DICOPT solver was used for the solution. The results show that the optimization scheme under uncertainty saves CNY 60 213.34×10⁴ in the total investment cost, with obvious optimization effect; the uncertainty of user demand affects the investment decision of the gas storage facility to a larger extent, and the relationship between the total investment cost and the confidence level reflects the contradictory decision-making relationship between benefit and risk under uncertainty. The study is of great significance for the design of the gas storage.

Influence of the Cluster Effect on the Fracture Connectivity

Yuan Feiyu, Tang Chao, Zhang Chao, Fu Yafei, Chen Bo

2023, 30(6):  107-113.  DOI: 10.3969/j.issn.1006-6535.2023.06.014

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In response to the problem that it is necessary to fully consider the randomness and non-homogeneity of the fracture network layout due to the strong non-homogeneity and disordered and complex distribution of fractures of the fractured-vuggy reservoirs in Tahe Oilfield, the percolation theory was adopted to simplify the fracture network into a random and disordered system, and then the connectivity of fracture networks with the clustering behavior was investigated. The results show that as the fracture network transforms from isotropic to anisotropic, the connectivity increases and then decreases; the local clustering effect of the fracture network affects the percolation threshold, which decreases with the increase of the clustering effect, suggesting that the clustering effect can improve the local network connectivity but impair the overall connectivity. The method was applied in the development of Tahe unit A, and the unit recovery rate increased from 15.6% to 20.7%, and the new recoverable reserves were more than 42.1×10⁴t by formulating programs such as well network construction, well network flow potential adjustment, and oil displacement of well group through injection of nitrogen. This study is of great significance to the recovery enhancement of fractured-vuggy reservoirs in Tahe Oilfield.

Experiment on Replacement of High Carbon Gas with High Hydrocarbon Gas and Its Mechanism Evaluation

Cui Shuheng, Kong Jie, Lu Ruibin, Guo Minling, Wang Yujun, Zhong Hongpeng

2023, 30(6):  114-119.  DOI: 10.3969/j.issn.1006-6535.2023.06.015

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The deep gas group of a certain gas field in the western part of South China Sea is a high-carbon gas reservoir, and the shallow gas group is a high-hydrocarbon gas reservoir. In order to effectively improve the recovery rate of high-hydrocarbon gas reservoirs and increase the economic benefits, the indoor experiments of replacing high-hydrocarbon gas with high-carbon gas were carried out, and the mechanism evaluation method was adopted, to obtain the changes of gas components and solubility after the replacement of high-hydrocarbon gas with high-carbon gas, as well as the effect of the high-hydrocarbon reservoirs on the recovery rate after the replacement and the influencing factors, and the study results were applied to the evaluation of the mine pilot experiments and the prediction of the effect of CO₂ storage in high-carbon gas reservoirs of a certain gas field in western part of South China Sea. The results show that after the replacement of the high-hydrocarbon gas with the high-carbon gas, the high-carbon gas can displace the high-hydrocarbon gas in formation irreducible water, free CH₄ increases, and the long core replacement was carried out under reservoir conditions such as low-injection and high-production, large dip and high permeability of the core, with a higher cumulative CH₄ recovery degree of up to 4.5%. This study provides theoretical references for the efficient development of high-hydrocarbon gas reservoirs in China , and the evaluation of CO₂ storage mode in high-carbon gas reservoirs.

Oil-Water Occurrence Law in Typical High-Permeability Sandstone Reservoirs in the Bohai Sea Based on Microfluidic Modeling

Sun Pengxiao, Cai Hui, Chen Xiaoming, Yang Ziyou, Yao Junbo

2023, 30(6):  120-127.  DOI: 10.3969/j.issn.1006-6535.2023.06.016

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In order to further clarify the microscopic oil-water occurrence law during the water flooding process in high-permeability sandstone reservoirs,a microfluidic model of high-permeability sandstone in the Bohai Sea was established by scanning the core of the reservoir; based on the microscopic parameters such as the shape factor and Euler number, the computational program code was prepared to finely identify and extract the microscopic characterization of the remaining oil of five types, such as film, drop and column; and the experimental scheme was designed for the different fluid properties and development modes, so as to clarify the microscopic oil-water occurrence law and the evolution characteristic of the typical high-permeability sandstone of the Bohai Sea in the context of the different crude oil properties and the development regimes. The results show that With the increase of remaining oil discontinuous phase, it is difficult to produce the flow-around zone and stagnant zone within the water flooding range, and the porous and clustered remaining oil has become the main remaining oil occurrence pattern; high-speed displacement of water flooding has a larger sweep range, but the injected water flow-around is easy to lead to the water visible at the extraction end in advance, and the reach is no longer significantly increased; in low-viscosity reservoirs, the sweep efficiency of high-velocity displacement is increased by 0.154 compared to that of low-velocity displacement; in high-viscosity reservoirs, the sweep efficiency at the end of water flooding is increased by 0.137 after the liquid flow redirection and adjustment. For the typical reservoir properties of Bohai Oilfield and the conditions of high water content development stage, low-viscosity reservoirs are more suitable for increasing the displacement rate for potential tapping, and high-viscosity reservoirs are suitable for liquid flow redirection to further produce the remaining oil. The research results provide a reference for the efficient development through water flooding in Bohai Oilfield.

Indoor Experiment on CO₂ Huff-n-Puff in Chang7 Shale Oil Reservoir in Zhidan Oil Region

Shi Tiaotiao, Du Yan, Dang Hailong, Zhu Tongtong, Liu Shuangshuang, Shi Lihua, Zhang Jiaqi

2023, 30(6):  128-134.  DOI: 10.3969/j.issn.1006-6535.2023.06.017

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In order to evaluate the oil displacement effect of CO₂ huff-n-puff of shale oil reservoirs and the mobility of crude oil under different scales of pore throats, a natural core of Chang7 reservoir in Zhidan Oil Region of Yanchang Oilfield was selected, based on high temperature and high pressure CO₂ huff-n-puff in long cores and residual oil in short cores online NMR test experiments, and on the basis of evaluating the oil displacement effect, the mixed-phase state of CO₂ and the displacement law at different pressure measurement points were analyzed, the effect of mixed-phase huff-n-puff was compared with that of non-mixed-phase huff-n-puff at nano- and micron-scale pore throats, and the mobility of crude oil in different scale spaces of shale oil reservoirs was evaluated. The study shows that the effect of CO₂non-mixed-phase huff-n-puff was poor, the pressure inside the core increase was not obvious, and the pressure affecting range is small; under the condition of injecting the same pore volume multiplier, the recovery efficiency was increased by 8.24 percentage points compared with CO₂ non-mixed-phase huff-n-puff; the production pressure difference in the first 2 cycles of CO₂ mixed-phase huff-n-puff was large, the distance between CO₂ mixed-phase huff-n-puff intervals was long, and the characteristics of CO₂ mixed-phase displacement were obvious; in the whole pore throat of the rock sample, the proportion of micron-level pores was low, and nano-and submicron-level pores were the the main contributor of the crude oil. The study results can provide an important reference for shale reservoirs to replenish formation energy and improve recovery efficiency.

Drilling & Production Engineering

Prediction Method of Critical Sand Production Rate from Shale Gas Wells

Yin Hongchuan, Xu Liangjun, Lyu Zeyu, Pang Jin, Tang Wen, Chen Yuye

2023, 30(6):  135-140.  DOI: 10.3969/j.issn.1006-6535.2023.06.018

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The sand production of shale gas wells will reduce the flow conductivity of fractures, which in turn will reduce the production capacity of gas wells, and at the same time will cause sand plugging and erosion, thus affecting the safety of gas wells. Aiming at this problem, a prediction method for the critical sand production rate from shale gas wells was proposed. First, the critical flow rates of sand production of shale gas well fractures under different types of proppant were obtained, and the reasons leading to the difference in the critical flow rates of sand production of fractures were analyzed. Then, the critical sand production rates of shale gas wells under different fracture closure pressures was calculated in combination with the proppant mass and fracture half-length in gas well fractures. Finally, the method was validated using the field observation results of deep shale gas wells in the Longmaxi Formation of a certain block in west Chongqing. The results show that the stability of proppant and fracture varies at different stages of closure pressure, and the critical sand production flow rate is relatively low when the closure pressure is low and the equilibrium is broken due to the rupture of rock slab; the range of critical sand production flow rate of fracture corresponding to different proppant types also varies greatly, and the critical sand production flow rate of composite fracturing sand-propped fracture is relatively large in general, which is conducive to the prevention of sand production in gas wells. The sand production is predicted in 6 out of 15 wells within the example block, which is consistent with the actual production. The method is important for optimizing the early production allocation of shale gas wells.

Mechanism of Fracture Extension and Process Countermeasures in Grain-Type Shale Oil Reservoirs

Zhou Zhongya

2023, 30(6):  141-149.  DOI: 10.3969/j.issn.1006-6535.2023.06.019

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In response to the problem of high longitudinal non-homogeneity and unclear mechanism of hydraulic fracture initiation and propagation in grain-type shale oil reservoirs, the combination of discrete element fracture simulation and hydraulic fracturing physical modeling experiments was used to study the influence of factors such as vertical geostress difference, viscosity of fracturing fluid, pumping process, and perforation cluster spacing on the fracture propagation pattern of grain-type terrestrial shale oil reservoirs. The results show that: The de-viscosity and slip of weak structural surfaces between layers is an important reason for the stagnation of longitudinal propagation of fracture height in grain-type shale oil reservoirs, and the smaller the vertical principal stress difference is, the easier the laminar surfaces are activated, and the growth of fracture height is suppressed; the use of alternating pumping of high-viscosity and low-viscosity fracturing fluids is conducive to the realization of balanced longitudinal and transversal propagation of hydraulic fractures, and the realization of 3D development of reservoirs; the reduction of the perforation cluster spacing and the increase in the number of perforation clusters can significantly increase the area of hydraulic fractures and the reservoir drainage area. The study results are of great significance for realizing the deep penetration stimulation of grain-type shale oil reservoirs in the longitudinal direction and increasing the production of a single well.

Method for Identifying the Cause of Blowout Stoppage of Horizontal Wells in Constant-Volume Gas Reservoirs and Its Application

Liu Shubing, Yan Xuecheng, Song Yang, Zhang Hexing, Liu Lei, Chen Hong

2023, 30(6):  150-156.  DOI: 10.3969/j.issn.1006-6535.2023.06.020

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The blowout stoppage of horizontal gas wells is a common problem in the middle and late stages of the development of constant-volume gas reservoirs, and it is necessary to identify the causes of the stoppage and take measures to restore production in a timely manner. To this end, the theoretical equation of critical liquid-carrying in horizontal wells was combined with the binomial deliverability equation of horizontal wells and the calculation equation of bottomhole flowing pressure to establish three criteria for blowout stoppage: critical liquid-carrying flow rate, critical lifting differential pressure, and critical formation pressure, analyze the influences of factors such as wellhead pressure and tubing inner diameter on the criteria, and study the roles of the three criteria in identifying the causes of blowout stoppage in gas wells, and then create a method to identify the causes of blowout stoppage of gas wells in a quick manner. The study shows that: The critical liquid-carrying flow rate has an increasing multiplicative power function with the wellhead pressure and tubing inner diameter, the higher the wellhead pressure and the larger the tubing inner diameter, the larger the critical liquid-carrying flow rate is, when the actual gas volume of the well is lower than the critical liquid-carrying flow rate, it can be determined that the wellbore has begun to accumulate fluids; the critical lifting differential pressure has nothing to do with the tubing inner diameter, and only rises linearly with the wellhead pressure, when the actual lifting differential pressure is lower than the critical lifting differential pressure, it is necessary to consider the problem of insufficient fluid power of the well; the tubing inner diameter only increases with the wellhead pressure; the critical lifting differential pressure has no effect on the wellhead pressure, so it is necessary to consider the problem of insufficient fluid lifting power of the gas well; when the tubing inner diameter remains unchanged, the critical formation pressure rises linearly with the wellhead pressure, and in the case of a large consumption of formation pressure, the critical formation pressure is easy to exceed the actual formation pressure of the gas well, i.e., the gas well will be triggered to stop blowout due to the insufficient driving energy. The application example proves that the method can effectively identify the reasons for the blowout stoppage of horizontal gas wells and provide theoretical basis for the technological measures. The establishment of this method is of great significance for the high-efficiency development of the low-pressure stage of constant-volume gas reservoirs.

Research and Application of Changing Rule of Fracture Flow Conductivity in Salt-Bearing Reservoirs Based on Salt Dissolution and Creep

Yu Tianxi, Wang Lei, Chen Beibei, Sun Xize, Li Shengxiang, Zhu Zhenlong

2023, 30(6):  157-164.  DOI: 10.3969/j.issn.1006-6535.2023.06.021

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The rapid decline of fracture flow conductivity after fracturing of salt-bearing reservoirs leads to the rapid decline of production, so the enhancement of fracture flow conductivity becomes the key to improve the development effect of this type of reservoir. By taking the salt-bearing reservoir in Mahu area of Junggar Basin as the research object, and based on the mineral component data of the reservoir, the salt content of the reservoir was classified, and based on this, the creep performance of the reservoir and the dissolution law of the salt rock, as well as the influence of the proppant particle size, the sanding concentration, and the fluid medium on the flow conductivity were investigated, and the effects of the creep effect of the reservoir, the salt dissolution effect, and the embeddedness of the proppant on the fracture width were quantitatively analyzed. The study shows that: The higher the salt mineral content of the salt rock, the more obvious the characteristics of its creep mechanical behavior; the higher the temperature, the lower the fluid mineralization and viscosity, and the higher the rate of salt dissolution; the fracture width is mainly affected by the embedment effect of the proppant, the creep effect of the salt-bearing reservoir and the salt dissolution effect on the fracture surface, and the embedment effect of the proppant and the creep effect of the salt-bearing reservoir lead to a decrease in the fracture width, and the fracture width increases due to the dissolution effect of the salt rock on the fracture surface. The fracturing fluid and high-concentration, large-size proppant prepared by using clear water can significantly enhance the fracture conductivity. The research results have been successfully tested in the field and show the direction for efficient fracturing of salt-bearing reservoirs.