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06 March 2023, Volume 19 Issue 1

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OIL AND GAS DEVELOPMENT

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Optimization of Well Shut-in Time after Fracturing in Jimusar Shale Oil Reservoirs

ZHANG Yanjun , XU Shucan , LIU Yafei , WANG Xiaoping , GE Hongkui , ZHOU Desheng

2023, 19(1):  1-7.  DOI: 10.12388/j.issn.1673-2677.2023.01.001

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Well shut-in after fracturing is of great importance for increasing the oil recovery and production of shale oil reservoirs. The key is to determine the shut-in time. At present，there is no systematic and effective method for determining the time of shut-in either in China or across the world. The pressure transmission of the fracture system，the ion diffusion of the produced fluid and the capillary force imbibition are the key problems to be solved for addressing the above challenges. With laboratory experiments and field analysis，a comprehensive determination method for the shut-in time for Jimsar shale oil reservoirs was developed by clarifying the microscopic pore characteristics，wettability，laminae，and imbibition flooding potential of Jimsar shale oil reservoirs and analyzing the existing methods used and characteristics of shut-in time determination. It is concluded that the Jimusar shale oil reservoir provides strong imbibition and diffusion ability，and well shut-in after fracturing contributes to the displacement of oil. The shut-in time can be determined comprehensively in accordance with the required equilibrium time of the wellhead pressure，imbibition，and production fluid salinity. To determine the post-fracturing shut-in time for Jimsar shale oil reservoirs，the synergy of micro-fracture fluid charging and matrix imbibition should be taken into consideration. Specifically，with the second turning point of wellhead pressure decline taken as the lower limit and the turning point for the stable rising of salinity as the upper limit，the optimal shut-in time is determined，considering the imbibition equilibrium. The shut-in time after fracturing for Well Q was optimized based on laboratory experiments and field data. The suggested shut-in time for Well Q is about 55 days. This study provides an important reference for optimizing the shut-in time after fracturing.

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Micro-Scale Oil and Water Migration Characteristics of Water-Injection Huff and Puff in Ultra-Low Permeability Reservoirs

CUI Pengxing, HOU Binchi, MENG Xuangang, DANG Hailong, WANG Chenchen

2023, 19(1):  8-15.  DOI: 10.12388/j.issn.1673-2677.2023.01.002

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Water injection huff and puff has become one of the key technologies for developing ultra-low permeability reservoirs in China. To understand the characteristics of oil and water migration in the process of water-injection huff and puff in ultra-low permeability reservoirs，the influence of time and pressure on the huff and puff effect was tested using the natural core of Chang6 reservoir in Nanniwan and the simulated sand pack tube model，and the affected range and micro fluid migration characteristics of dynamic imbibition of water-injection huff and puff was investigated. The analysis found that the effect of the first and the third cycles of huff and puff got better with increase of the time of shut-in，but the effect of the second cycle of huff and puff got worse，while the increase of shut-in pressure led to enhanced huff and puff effect. The range of dynamic imbibition positively correlates with the imbibition time. The difference of oil saturation changes gradually decreases with the increase of imbibition distance. Permeability and pore size affect the sweep of water in the process of huff and puff and the second migration of crude oil in large and small pore channels，therefore，it is necessary to expand the sweep range of injected water as much as possible in the development practices. At the same time，it is also important to pay attention to the secondary migration of oil and water in the pores with different sizes.

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Controlling Factors of Particle Migration in Loose Sandstone and Performance Characteristics in Oilfield

LIU Chao, SHEN Chunsheng, LIU Jianhua, LIU Siyuan, PANG Weihao

2023, 19(1):  16-20.  DOI: 10.12388/j.issn.1673-2677.2023.01.003

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In the development of loose sandstone reservoirs，the problem of particle migration blockage is very common. When the particle migration is blocked，the fluid produced is greatly reduced，which constrains the development of this type of reservoir. To understand the mechanism and main controlling factors of particle blockage，the microscopic pore throat characteristics were observed from PX oil field cast thin sections，and a microscopic pore structure model was prepared using laser etching to simulate the migration and blockage mechanism of particles with different particle sizes，viscosity，flow rate，and concentration. The effects of particle size to throat ratio，fluid viscosity，solid phase particle concentration，and flow rate on particle migration/blockage were systematically evaluated. It was found that the particle concentration，particle size，pore throat size，fluid viscosity and displacement velocity were the main controlling factors affecting particle migration. When the ratio of particle size to throat diameter is greater than 2/3，large-scale blockages are easily formed. The factors influencing particle migration at different water content stages in the oilfield vary，and the fluid viscosity，fluctuation in fluid production，rising water cut，and adjustments to the production system can all cause particle migration blockage.

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A Method for Determining Effective Injection-Production Well Spacing for Low-Permeability Reservoirs and the Application

LING Haochuan, WU Zheng, WANG Jijun, SUN Qiang, GENG Hongliu

2023, 19(1):  23-26.  DOI: 10.12388/j.issn.1673-2677.2023.01.004

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To make full use of the actual oilfield production test data to determine the effective injection-production well spacing for low-permeability reservoirs，the parametric equation of mobility function with the oil productivity index and the starting pressure was obtained by considering the low-permeability starting pressure gradient. The equation and the production test data can be used to get the mobility and drainage radius of the tested reservoir intervals. The regression analysis found that there is a semi-logarithmic relationship between the effective injection-production well spacing of low-permeability reservoirs and the physical property. Based on the relationship curve，the effective well spacing for directional well pattern development for low-permeability reservoirs can be determined. The application shows that the worse the reservoir properties，the smaller the effective well spacing；the effective well spacing of low-permeability reservoirs is 2 times the drainage radius，which means the valid producing coefficient has to reach 78.5% to ensure high efficiency between the producers and injectors. Using this method，the effective well spacing map of Bohai B Oilfield at different mobility was obtained. It’s suggested that the well spacing should be set between 300 m and 450 m at physical property range of 5 mD  to 20 mD.

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Effect of Hydraulic Fracture Conductivity on Deep Shale Gas Production

JIANG Ming, LI Zhiqiang, DUAN Guifu, YANG Jingjia, SHI Yangzhi, SHI Hanqi

2023, 19(1):  35-41.  DOI: 10.12388/j.issn.1673-2677.2023.01.006

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It is difficult for deep shale fracturing to create complex fractures and the fracture conductivity fails quickly，resulting in rapid decline in production. To clarify the impact of hydraulic fracture conductivity on deep shale gas production，a propped fracture conductivity computational model and a mathematical model for predicting the productivity of deep shale gas were established based on the test data on the conductivity of deep shale fractures，while also considering the effects of closure stress，proppant concentration and particle size on the conductivity. The production data of deep shale gas in the southern Sichuan were used to conduct historical matching and prediction on the model，which verified the accuracy of the model. The effects of proppant concentration，closure stress and proppant particle size on the production of deep shale gas were studied and analyzed. The results show that the stable production time and  Estimated Ultimate Recovery（EUR） of deep shale gas wells can be improved by increasing the proppant concentration and selecting proppants with smaller particle size，with the optimal proppant concentration falling between 1-2 kg/m²；when the closure stress was increased from 80 MPa to 110 MPa，the stable production time was reduced by 40%；the optimum proppant particle size is 40/70 mesh due to the combined effect of proppant particle size and the half-length of propped fracture. The results provide a theoretical basis for the fracture conductivity design and production forecast of deep shale gas reservoirs.

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Numerical Simulation of Fracture Propagation Pattern in the Presence of Gravel

WANG Tao, CHENG Leiming, XIANG Yuankai, CHENG Ning, WANG Bo, ZHOU Hang

2023, 19(1):  42-48.  DOI: 10.12388/j.issn.1673-2677.2023.01.007

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Large-scale hydraulic fracturing is the essential technology for cost-effective and efficient development of tight sandy conglomerate reservoirs. Gravel parameters are considered the key factors that influence the hydraulic fracture geometry. The existence of gravels can make it even harder to complete fracturing stimulation. The complex fracture geometry，high tortuosity，and shorter supporting fracture length make it difficult to achieve the designed fracture conductivity. In this research，the continuous-discontinuous element method （CDEM） was applied to establish a 2D full fluid-solid coupling fracture propagation model to explore the influence of stress difference，gravel content，and flow rate on the fracture propagation geometry. The numerical simulation results show that：the multi-phase media hydraulic fracturing model based on the CDEM method can accurately simulate the overall fracture propagation geometry under the influence of gravel；the fractures will divert and generate a tortuous fracture when meeting high strength gravel；in reservoirs with high stress，hydraulic fractures tend to pass around the gravel and then divert to the direction of the maximum horizontal principal stress；in the presence of gravel，the fracture propagation will shape a high-pressure zone and generate more micro-fractures，thus increasing the stimulated reservoir volume. This study lays a theoretical basis for optimization of the fracturing design of conglomerate reservoirs.

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Numerical Simulation for Vertical Propagation Pattern of Hydraulic Fractures in Sand-Shale Interbedded Reservoirs

LUO Yao, KONG Hui, XU Keshan, Tursonjone MAMUTY, ZHENG Heng

2023, 19(1):  49-56.  DOI: 10.12388/j.issn.1673-2677.2023.01.008

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Hydraulic fracturing is one of the main technologies to realize the efficient development of shale gas，and bedding plane is the key factor affecting the distribution of the three-dimensional geometry of hydraulic fractures. At present，scholars at home and abroad have explored the impact of shale reservoir bedding on the vertical propagation of hydraulic fractures，but there is less understanding on the vertical propagation pattern of hydraulic fractures in sand-shale interbedded reservoirs. Based on the theory of linear elastic fracture mechanics，a multi-bedding hydraulic fracture propagation model of coupled stress - damage - filtration loss is established in this study，and the impacts of change in reservoir stress field，formation dip angle and tensile strength of bedding plane on the vertical propagation of hydraulic fractures are analyzed. Compared with the microseismic monitoring results，accuracy of the model can reach more than 95%. The simulation results show that propagation of hydraulic fracture can be divided into three stages in the process of penetrating through the bedding plane of sand-shale interbedding，and the propagation direction of hydraulic fracture in the third stage is determined by the change in reservoir stress field，formation dip angle and tensile strength of bedding plane. Reservoirs with low stress difference and low dip angle are favorable to the opening of bedding plane，while reservoirs with high stress difference and high dip angle are favorable to the vertical propagation of hydraulic fracture. As the tensile strength of bedding plane decreases，the opening degree of bedding plane increases. This is mainly because that the lower the tensile strength of bedding plane is，the less the energy consumption for opening the bedding plane is.

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Evaluation of Fracability of Heterogeneous Ultra-Heavy Oil Loose Sandstone Reservoirs

ZHANG Runxue, , LIN Botao,

2023, 19(1):  57-64.  DOI: 10.12388/j.issn.1673-2677.2023.01.009

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At present，there is no standard method for evaluating the fracability of ultra-heavy oil loose sandstone reservoirs in China. On the basis of the study exploring the fracability of heterogeneous ultra-heavy oil reservoirs in Fengcheng，Xinjiang，the Lorenz coefficient method was used to evaluate the heterogeneity of reservoirs and define the concept of fracability of ultra-heavy oil reservoirs. Multidimensional geological engineering parameters were selected as indicators to evaluate the fracability of heterogeneous ultra-heavy oil reservoirs in Fengcheng，Xinjiang，the gray correlation method was used to guide the establishment of the judgment matrix when selecting parameter weights，and the gray correlation-hierarchy analysis method was used to establish the fracability evaluation model of this type of reservoir. The fracability indexes of eight layers of two blocks of the Xinjiang Fengcheng Oilfield before reservoir stimulation were calculated，which showed that the reservoir fracability index is negatively correlated with heterogeneity. When the reservoir fracability index is greater than 0.7，the corresponding Lorenz coefficient is less than 0.5，and larger tensile dilatancy can be achieved through microfracturing reservoir stimulation. This fracability evaluation method can help assess the fracability of heterogeneous ultra-heavy oil reservoirs，which provides guidance for on-site microfracturing stimulation，and helps oilfields to improve the final oil recovery of wells.

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Research Progress and Application of Chemical Plugging Materials and Method for Carbon Dioxide Flooding

ZHU Daoyi, SHI Chenyang, ZHAO Yanlong, CHEN Shengen, ZENG Meiting

2023, 19(1):  65-72.  DOI: 10.12388/j.issn.1673-2677.2023.01.010

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Carbon Capture，Utilization and Storage （CCUS） technology is an important tool for the energy sector to enable efficient oil and gas production under the dual-carbon goal. Injecting CO₂ into oil reservoirs can significantly enhance oil recovery. However，its mobility differs greatly from that of the crude oil，and there’s clear differentiation with oil and water，which results in a limited sweep efficiency of CO₂. Therefore，it is urgent to develop efficient CO₂ plugging materials and corresponding plugging control technologies to improve reservoir recovery and CO₂ storage efficiency. This article explains the characteristics of plugging in the CO₂ flooding process and gives an overview of the commonly used CO₂ plugging materials and methods. It also describes their applications in oil fields across the world，and their potential for improving CO₂ recovery and storage in Xinjiang Oilfield. This study is inspiring for the global research and development of plugging materials in the process of CO₂ flooding in oilfields worldwide，and highlights the future direction of CO₂ plugging technology in Xinjiang oilfields.

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Effect of Siloxane-Based Thickener on Properties of Carbon Dioxide Fracturing Fluid

LI Qiang, , WANG Fuling, , ZHOU Chang , Chen Jiashuo , LI Qingchao, , Wang Yanling

2023, 19(1):  73-80.  DOI: 10.12388/j.issn.1673-2677.2023.01.011

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To address the problem of the low viscosity of pure liquid CO₂ and poor fracturing effect at low viscosity，a siloxane polymer that significantly thickens CO₂ was prepared based on the ring opening polymerization and hydrosilylation. The viscosity of the CO₂ fracturing fluid that contains this thickener was measured at different pressure and temperature. The thickening process of siloxane as a thickening agent was analyzed；and fracturing simulation of the CO₂ fracturing fluid containing thickener was performed based on extended finite element （XFEM）. The results show that the viscosity of the CO₂ fracturing fluid containing thickener can reach up to 1.65 mPa·s （20℃） when the concentration of the thickening agent is 5 wt%. The viscosity of the fracturing fluid decreases with the increase of temperature and increases with the increase of pressure and thickener content. The fracturing simulation analysis of the thickening effect of liquid CO₂ based on XFEM shows that the thickened CO₂ fracturing fluid can increase the fracture half-length to 38 m，which provides better fracturing effect compared with the pure CO₂ fracturing fluid. The thickening test and fracturing effect simulation provide a benchmark for the design of thickeners used for CO₂ dry fracturing. 

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Experimental Study on Film Permeability and Stability of Nanofiber Enhanced Foam

CHEN Shengen, WANG Rui, YI Yonggang, ZHANG Xin, XU Jinshan, SHANG Jin

2023, 19(1):  81-89.  DOI: 10.12388/j.issn.1673-2677.2023.01.012

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Foam can effectively address the fluid channeling problem caused by gas-liquid mobility difference and fractures in gas flooding in tight reservoirs，and increase gas flooding sweep efficiency. However，the foam is a thermodynamically sub-stable system，and its long-term stability is limited. Therefore，based on the nanofiber （NCF） enhanced foam system，the influence of NCF on gas permeability through film in N₂ foam and CO₂ foam was analyzed，and the micromorphological changes of the two kinds of NCF enhanced foam system under different oil content were observed. Furthermore，the paper also explored how the nanofiber improves the foam stability and the relationship between the foam system stability and the permeability of the foam film. It was found the nanofiber can reduce the permeability of the film. The permeability of the N₂ and CO₂ bubbles was reduced by about 89% and 65% respectively by 0.1 wt % NCF，while the defoaming time was increased by 2.7 times and 11.3 times respectively. The results showed that NCF can inhibit bubble instability by reducing the permeability of the film，and the thickness of the NCF-enhanced N₂ foam is higher than those of the CO₂ foam，while the diameter of the NCF-enhanced N₂ foam is smaller. The instability trend of NCF enhanced CO₂ foam is stronger under different oil content，which shows that NCF can enhance the stability of N₂ foam better. The nanofiber can be used to improve the foam performance，optimize foam system，thus enhancing foam stability. Research in this field has proved to be helpful for improving the recovery factor of gas flooding reservoirs.

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Construction and Performance Evaluation of Nano Microemulsion Oil Displacement System#br#

ZHENG Cunchuan, ZHANG Liwei, XU Jinshan, ZEN Meiting, FU Gaofeng, FU Yulong

2023, 19(1):  89-94.  DOI: 10.12388/j.issn.1673-2677.2023.01.013

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Microemulsion flooding is an effective technology to improve oil recovery. Microemulsions were prepared using dodecyl betaine，isopropanol and 90 ~ 120 petroleum ether. The impact of Km，the ratio of cosurfactant to surfactant，on microemulsion was studied using the pseudo-ternary phase diagram method. The results show that with the increase of Km，the area of microemulsion formed increased first and then decreased，and reached the maximum when Km = 2. The nano-microemulsion oil displacement agent was prepared using the microemulsion dilution method. The particle size distribution and interfacial tension were measured by laser scattering system and spinning drop interface tensiometer，respectively. The results show that the average particle size is 149.0 nm when the concentration is 0.25 %，and the minimum interfacial tension is 1.780 44 mN/m when the concentration is 0.3 %. The properties of the nano microemulsion oil displacement agent were evaluated in the laboratory. The results show that it had good dispersion stability at different temperatures. The maximum foam height is 140 mm when the concentration is 0.5%；the maximum emulsification efficiency is 55.0% when the concentration is 0.3%；the maximum oil displacement efficiency is 88.39% when the concentration is 0.2%；when the concentration is 0.3%，the total oil recovery factor is 86.78%.