Table of Content

10 October 2021, Volume 43 Issue 5

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A Special Issue on Unconventional Oil and Gas Development

Geology and Engineering Integration Application in the Whole Life Cycle of Shallow Shale Gas Wells

LIANG Xing, SHAN Chang'an, JIANG Pei, ZHANG Chao, ZHU Douxing

2021, 43(5):  1-18.  DOI: 10.11885/j.issn.1674-5086.2021.03.15.01

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Mountain shallow shale gas in Taiyang Area of Zhaotong National Demonstration Zone, as the first large-scale integrated shallow shale gas field developed for industry in China, has entered the stage of large-scale commercial development at present, which proves that shallow shale gas in the complex structural area of the strong reconstruction outside the Sichuan Basin has a good exploration and development prospect, and has important enlightenment significance for the development of shale gas in China. Based on the efficient development innovation practice of geology and engineering integration in shallow shale gas field, this paper systematically summarizes the core connotation of geology and engineering integration, and forms the key technology working method of geology and engineering integration suitable for mountain shallow shale gas exploration and development. Exploration and development practice experience shows that based on the comprehensive evaluation of geology and engineering integration concept, through the integrated evaluating platform, the integration of synergy to the whole life cycle of shale gas well quality of "4Q":reservoir quality (RQ), drilling quality (DQ), completion quality (CQ), production quality (PQ) are assessed and production system is optimized, to achieve well quality, engineering effect, single well production.

Application of Improved Residual Neural Network-based Machine Learning Method in the Prediction of Shale Gas Sweet Spot

HUI Gang, CHEN Shengnan, WANG Hai, GU Fei

2021, 43(5):  19-32.  DOI: 10.11885/j.issn.1674-5086.2021.02.27.01

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The great success of the North American shale gas revolution has posed a profound impact on the global energy market, attracting great interest from both industry and academia. Accurate prediction of sweet spots is essential to determine the well location and enable a high after-stimulation productivity for the fractured wells. However, there exist in the traditional approach to the shale gas sweet spot prediction. In this study, Fox Creek, a commercially developed shale gas producing area in Canada, is taken as an example to investigate the geological and engineering factors which can be utilized to identify the sweet spot area of shale gas reservoirs. A modified residual neural network approach is proposed to determine the main controlling factors and establish a prediction model for the sweet spot area. Results show that the main controlling factors affecting the sweet spot area of shale gas formations are porosity, permeability, shale content, burial depth, formation pore pressure, shale brittleness index and fracturing parameters (horizontal length, number of fracturing stages, total placed proppant and total fluid injection). The gas production reached 0.94 and 0.85 in the modified residual neural network algorithm in the test and training respectively. The distribution of shale sweet spots has been contoured based on the prediction model of the modified residual neural network. It is shown that the shale sweet spots locate along the Duvernay boundary in the west and south and deteriorated toward the northeast. This prediction model of shale gas sweet spot area provides a reliable foundation for the subsequent efficient development of shale gas.

The Horizontal Well Exploitation Practice of Jimsar Shale Oil

WU Chengmei, XU Changfu, CHEN Yiwei, TAN Qiang, XU Tianlu

2021, 43(5):  33-41.  DOI: 10.11885/j.issn.1674-5086.2021.01.21.01

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Shale oil field of Lucaogou Group Jimusar Sag in Junggar Basin development test shows that horizontal wells in different areas at the same sweet spot layer greatly in production, and that sigle well productivity and mayor controlling EUR factor are not clear and have brought difficulties to reservoir development scheme establishment, reservoir reconstruction mode choice and benefit evaluation has brought many difficulties. Therefore, through integrated researches of seismic, logging, analysis and laboratory testing, the geological characteristics of the high-frequency interbed of source and reservoir are defined. The source and reservoir configuration and preservation conditions are the congenital factors affecting the oil bearing of the target reservoir. Using special logging, microseismic and fluid production profile monitoring, we find that the length of horizontal section and complex fracture network are important factors affecting productivity. Based on the laboratory model test and the comprehensive analysis of reservoir production performance, the reasonable drainage and production system of horizontal well after fracturing is preliminarily determined. According to the research, the sweet spot of shale oil has strong heterogeneity, and the high quality sweet spot penetration rate and the maximum complexity of fracture network reconstruction are the goals that must be pursued to improve the productivity of horizontal wells, and a reasonable drainage and production system is conducive to giving full play to the production capacity of horizontal wells.

Evaluation on In-situ Gas-bearing Characteristic of Shale Based on Process Analysis Method

LI Junqian, LU Shuangfang, LI Wenbiao, CAI Jianchao

2021, 43(5):  42-55.  DOI: 10.11885/j.issn.1674-5086.2021.02.01.03

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In order to determine the total gas content, adsorbed/free gas contents and their ratios in shale, the process analysis method, a new quantitative method of evaluating the in-situ gas-bearing characteristic of shale was established. This method divides the whole process of drilling coring and field desorption into five stages, and evaluates the amount of gas (adsorbed and free gas) released in different stages in turn. After obtaining a series of data including drilling coring, reservoir physical property, adsorption/diffusion, gas characteristic and field analysis etc., this method can be used to obtain the gas-desorbed amount during the whole process, and obtain the in-situ total gas content, adsorbed/free gas contents and their ratios. This method is used to evaluate the gas-bearing characteristic of marine shale in the Wufeng Formation-Longmaxi Formation of Well JY182-6 in Jiaoshiba Block. Total gas content obtained with the process analysis method is 0.8~5.4 times (average 2.0 times) of the results of USBM direct method; the difference between the two methods is -1.27~1.58 m³/t (average 0.39 m³/t), and it decreases with the increasing gas-adsorbed ratio. Adsorbed gas content and its ratio are primarily controlled by total organic carbon content (positive correlation). Free gas content is controlled by porosity (positive correlation) and water saturation (negative correlation), and is affected by clay mineral content (weak positive correlation).

Study on Gas Loss Characteristics of Shale Based on Gas Diffusion Model

TIAN Zhenhua, ZHOU Shangwen, LI Junqian, CAI Jianchao

2021, 43(5):  56-65.  DOI: 10.11885/j.issn.1674-5086.2021.02.27.02

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The commonly used lost gas calculation models of shale use different assumptions or simplified conditions, and result in the uncertainty of the lost gas content of shale. In this paper, the characteristics and deficiencies of the conventional unipore diffusion model are specified. A modified unipore diffusion model is established considering the time-dependent gas diffusion coefficient and time-dependent gas concentration at core boundary. The analysis indicates that the initial gas concentration, gas diffusion coefficient, gas concentration at core boundary, and core size are the key parameters affecting the shale gas loss process. USBM method may misestimate the lost gas content when the gas diffusion coefficient is too large, or the lost time is too long. Compared with the piecewise linear decline mode, the exponential decline mode of boundary gas concentration may be closer to the actual situation. The decline rate of boundary gas concentration mainly controls the total time of gas diffusion in the core, while the change rate of gas diffusion coefficient mainly affects the characteristics of gas diffusion at the early stage. The modified unipore diffusion model established in this paper can better reveal the gas loss characteristics of shale from the gas diffusion perspective, but the gas flow process under pressure difference should be further integrated into this mathematical method and its key parameters still need to be optimized based on the experimental data, so as to improve the calculation accuracy of lost gas content of shale.

Effect of Wetting Hysteresis on Flow Resistance for Two-phase Fluid System in Shale Reservoirs

GAO Yanling, WU Keliu, CHEN Zhangxing, TIAN Weibing, LI Jing

2021, 43(5):  66-72.  DOI: 10.11885/j.issn.1674-5086.2021.03.15.05

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The mechanism of the wetting hysteresis effect on threshold pressure and flow resistance was revealed, and the threshold pressure model and the flow resistance model after the movement of the bubble/droplet were established for a twophase fluid system based on the static wetting hysteresis equation and the dynamic contact angle equation, respectively. Based on the experimental data in the literature, the threshold pressure at different temperature and pressure, and the flow resistance at different pore size, viscosity and surface tension were calculated, by using the established models. The results show that the threshold pressure and the flow resistance caused by static wetting hysteresis and dynamic contact angle hysteresis cannot be ignored in nano-scale pores of shale. The flow resistance caused by dynamic wetting hysteresis is greater than the threshold pressure caused by static wetting hysteresis, and with the increase of flow velocity, the flow resistance continues to increase, but the degree of the growth rate gradually decreases. This study provides a mathematical model for the accurate characterization of the threshold pressure and flow resistance of two-phase fluid in shale reservoirs, which will provide some theoretical basis for accurate numerical simulation of shale gas development and geological storage of CO₂ in shale reservoirs.

Reconstruction of 3D Shale Digital Rock Based on Generative Adversarial Network

YANG Yongfei, LIU Fugui, YAO Jun, SONG Huajun, WANG Min

2021, 43(5):  73-83.  DOI: 10.11885/j.issn.1674-5086.2021.01.15.02

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The pore structure of shale oil reservoir is complex, and the shale cores are hard to acquire. Accurately characterizing the pore structure of shale reservoir is the key to the study on the fluid seepage law in shale reservoir. Based on the three-dimensional focused ion beam scanning (3D FIB SEM) images of real shale cores, the structure of the original generative adversarial network model is redesigned. At the same time, to ensure that the reconstruction results can fully reflect the pore structure information of the shale core, the size of the training sample is increased, and the model is trained to generate three-dimensional shale digital rock. The porosity of the reconstructed digital rock and the original core are compared, and the pore network model is extracted from the reconstructed digital rock, then the pore structure properties are analyzed. The porosity, pore and throat sizes, connectivity, and coordination relationship of the reconstructed digital rock are highly in agreement with the original cores, which verifies that the generative model can generate high-quality three-dimensional shale digital rock. Finally, several digital rocks are generated, and the mean value and variation range of various pore structure parameters are calculated. It is proved that the generated digital rocks have stable pore space characteristics, and the trained generative model has good stability.

Integrated Simulation Approach for Fracture Network Propagation and Gas Flow in Shale Gas Reservoirs

SHENG Guanglong, HUANG Luoyi, ZHAO Hui, RAO Xiang, MA Jialing

2021, 43(5):  84-96.  DOI: 10.11885/j.issn.1674-5086.2021.02.28.04

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The distribution of natural fractures in shale gas reservoirs is complex, and the reservoir heterogeneity is strong. Hydraulic fracturing of horizontal wells is a necessary way for its development. Establishing an integrated simulation method for fracturing network propagation simulation and flow simulation in shale gas reservoirs has important practical significance for formulating production plans and evaluating the quality of hydraulic fracturing. In this paper, the fracture propagation calculation method based on lightning simulation is used to simulate the multi-branch fracture network pattern of shale gas reservoirs. On this basis, the embedded discrete fracture model (EDFM) is further used to quantitatively characterize the complex flow mechanism between the organic matter-inorganic matter-fracture network of shale gas reservoirs, so as to realize the integrated simulation of fracture network propagation and gas flow in shale gas reservoirs. Based on this method, a 200 m×200 m geological model was established to simulate fracture morphology and flow characterization. The fracture network distribution is obtained by the fracture network propagation simulation method, and the flow simulation is carried out based on the embedded discrete fracture model. The gas saturation distribution and gas production are obtained. At the same time, based on this model, the influence of parameters such as fracturing fluid injection pressure, fractal probability index, fracturing fluid viscosity and fracture simulation accuracy on fracture network, gas saturation distribution and shale gas production is analyzed. Research shows that:the higher the fracturing fluid injection pressure is, the smaller the fractal probability index is, the smaller the fracturing fluid viscosity is, the larger the fracture propagation range will be, the greater the gas saturation reduction range will be, and the higher the single well production will be; the fineness of the fracture grid will significantly affect the production. This model can simulate the shale gas reservoir fracture network pattern, and the complex flow of multiple media on a large scale, which provides effective help for evaluating the hydraulic fracturing of shale gas reservoirs and predicting production.

Quantitative Characterization Model of Shale Oil Horizontal Well Production Change

CHEN Yiwei, ZHOU Yuhui, LIANG Chenggang, XU Tianlu, HE Yongqing

2021, 43(5):  97-103.  DOI: 10.11885/j.issn.1674-5086.2021.03.01.07

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The production performance of shale oil horizontal wells is complex, and it is difficult to predict the production performance of the whole life cycle through conventional methods. Therefore, taking the shale oil horizontal well of Lucaogou Formation in Jimsar as an example, the production process is divided into four stages by analyzing the production performance curve of a typical horizontal well in the blowout period, including soaking stage, up production stage, production decline stage and low and stable production stage. The quantitative characterization model of shale oil horizontal well is deduced and established. Combined with SPSA algorithm, the whole life cycle production performance curve fitting, prediction and parameter interpretation inversion are realized. The results show that the peak oil production and average decline rate have a great influence on the production performance curve, while the oil breakthrough time and peak time have little influence. Finally, the application of the quantitative characterization model and curve fitting optimization algorithm is carried out to prove the applicability of the model; it also shows that the model can be used as a practical and reliable method to predict the production performance of shale oil horizontal wells.

Simulation and Prediction of Gas Injection Strategy for the Bakken Formation in Southeast Saskatchewan

DENG Xiaohan, CHEN Tian, ZHAO Jia, JIA Na

2021, 43(5):  104-112.  DOI: 10.11885/j.issn.1674-5086.2021.03.14.01

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The Bakken formation is an extremely tight oil reservoir with characteristics of low porosity and permeability. In this study, a ten-well numerical simulation model was built by using the reservoir and fracture properties of middle Bakken tight formation to represent the characteristics of the Viewfield pool in southeast Saskatchewan. Pilot tests have been carried out to determine the reliability and feasibility of gas injection for improving tight oil recovery. To begin with, a history matching has been performed to verify the validity of the existing model with the actual field production data and pressure variation within the pilot area and determine the sensitivity of parameters. Meanwhile, this study has different recovery schemes such as the water flooding process, CO₂ flooding process, CO₂-water-alternating-gas (WAG) process, and methane flooding process were simulated to comparatively evaluate their respective effects on oil recovery. It was found that relative oil-water permeability (K_row) and connate water saturation (S_wcon) were the most sensitive parameters towards the cumulative oil productions. The simulation results indicated other important parameters which considerably affect the oil recovery factor are CO₂ injection rate, number of cycles, injection times and soaking time. Amidst the different injection methods, 2-year period of CO₂-WAG has the best performance in terms of oil recovery factor, which brings up the additional oil recovery factor to 5.033%. This work provides fundamental knowledge of evaluating the potential gas injection strategies and the optimum operating conditions for enhancing the recovery of southeast Saskatchewan tight oil formation.

Transient Pressure Analysis of Vertical Well with Multi-wing Fractures

ZHANG Shoujiang, QIAO Hongjun, ZHANG Yongfei, CHEN Yiming, ZENG Fanhua

2021, 43(5):  137-146.  DOI: 10.11885/j.issn.1674-5086.2021.04.12.02

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The complex fracture network formed by hydraulic fracturing destroys the flow characteristics of a single linear fracture, which brings great challenges to the dynamic prediction of oil wells. In order to study the transient pressure characteristics of vertical wells with multi-wing fractures, the reservoir system is divided into two subsystems based on the source function theory and the superposition principle, and a semi-analytical model of transient pressure analysis is established using the discrete coordinate method. The identification curves of each flow stage in the reservoir are drawn by Laplace transform and Stehfest inversion algorithm. On this basis, the sensitivity analysis of the complex fracture network is carried out by changing the parameters such as the number of fractures, the length of the fracture, the angle of the fracture, the fracture distribution form and the fracture conductivity. The research results show that the reservoir flow in vertical wells with multi-wing fractures has gone through 4 stages. Among them, the number and length of fractures have a greater impact on the linear flow in the reservoir; the distribution of fractures has a large and complicated influence on the bilinear flow in the reservoir and the linear flow in the formation; the fracture conductivity has obvious influence on the bilinear flow in the reservoir; the fracture angle has little effect on the dynamic pressure characteristics of each flow stage in the reservoir.

Effect of Horizontal Staged Fracturing on the Integrity of Cement Annulus

ZHANG Guangqing, ZHAO Zhenfeng, WANG Xiaoxiao

2021, 43(5):  147-154.  DOI: 10.11885/j.issn.1674-5086.2021.03.31.01

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Casing damage and the annulus integrity in horizontal multiple-staged fracturing becomes major concerns in the industry. More focus was placed on formation slippage from fracturing fluid leakage into the faults, and stress analysis of casing and annulus, but less on the effect of multiple staged fracturing. In this paper, a model is built up for analyzing the annulus integrity in multiple-staged fracturing, with FEM and DEM. FEM model being setup is employed to obtain the elastic and plastic regions during fracturing, a DEM model acquiring stresses and strains from FEM is carried out to calculate the number of micro-cracks, and both plastic region and micro-cracks of the cement annulus are combined to evaluate annulus integrity. The research shows that besides the effect of stiffness ratio between casing to annulus, casing eccentricity, the multiple stages affect the annulus integrity significantly. The annulus integrity improves as stiffness ratio between casing to annulus increases, and the casing eccentricity and defects deteriorates it. The annulus becomes less integrated as fracturing stage number rises.

Theory and Research Progress of Cryogenic Cracking with Liquid Nitrogen in Unconventional Reservoirs

HUANG Zhongwei, WU Xiaoguang, ZOU Wenchao, YANG Ruiyue, XIE Zixiao

2021, 43(5):  155-165.  DOI: 10.11885/j.issn.1674-5086.2021.03.01.01

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Liquid nitrogen (LN₂) fracturing is a promising waterless stimulation method, which could provide solutions for issues accompanying hydraulic fracturing in unconventional reservoirs, such as large water consumption, formation damage and environmental risks. Cryogenic cracking is the primary advantage for applying LN₂ in reservoir stimulation. Based on previous studies of LN₂ fracturing, this paper puts particular focus on the cryogenic cracking. Physical and mechanical property changes of rocks subjected to LN₂ cooling are elaborated, and the primary parameters influencing cryogenic cracking performances and corresponding mechanisms are analyzed in detail. Microscopic patterns and characteristics of rock damage are revealed from the perspective of mineralogy. Additionally, we also evaluate the applicability of LN₂ to rocks with various lithology, various primary pore structures and various in-situ states (high temperature, water saturation). The purpose of this paper is to help readers better understand the theory and research progress of cryogenic cracking with LN₂ and provide some theoretical guidance for future studies and applications of the LN₂ fracturing technique.

Enhanced Oil Recovery of Ultra-low Permeability Tight Reservoirs in North America

FU Jing, YAO Bowen, LEI Zhengdong, TIAN Ye, WU Yushu

2021, 43(5):  166-183.  DOI: 10.11885/j.issn.1674-5086.2021.02.04.01

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There are many significant breakthroughs in unconventional oil and gas development in North America in the past decade, among which is the combination of such as hydraulic fracturing and horizontal drilling. However, only a small amount of oil from unconventional reservoirs can be recovered by primary recovery, which means a large amount of oil is remaining in tight reservoirs. Therefore, it is essential to develop the enhanced oil recovery technology in unconventional reservoirs. The United States produces more than 90 percent of the world's tight oil production, and has an overwhelming advantage in unconventional tight oil exploration and production. Operators in North America have conducted several field pilots on enhanced oil recovery (EOR) technology in tight oil reservoirs with ultra-low permeability. The summary and evaluation of these field pilots in North American unconventional reservoirs are discussed. The main difficulties and challenges of the EOR development in unconventional reservoirs are also pointed out.

Influence of Young's Moduli of Micro and Nano Scale Dispersed Particle Gels on Plugging Performances

DAI Caili, ZHU Zhixuan, LI Lin, LIU Jiawei, CHEN Jia

2021, 43(5):  184-192.  DOI: 10.11885/j.issn.1674-5086.2021.03.18.01

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Under the long-term fracturing of tight/shale oil and gas, where preferential channeling migration pathway developed, the dispersed particle gels has excellent performance effects in the control of the flow channel and expansion of the sweeping. Dispersed particle gels have excellent effects in improving the heterogeneity of tight oil/shale oil and gas reservoirs. A close relationship lies between the mechanical strength of the dispersed particle gels and their macro plugging performances. However, currently there is no effective method for characterization of the mechanical strength of the dispersed particle gels. Tacking the chromium crosslinked dispersed particle gels have been chosen as the examples, We measured the Young's modulus of dispersed particle gels at the nano and micro scales by atomic force microscope, and the mapping relationship between them is established by evaluating its macroscopic plugging performances. The research results indicate that when the fixed mass fraction of polymer is 0.3% and the mass fraction of SD-107 increases from 0.4% to 0.7%, the strength of the bulk gels increases, and the Young's modulus of the corresponding dispersed particle gels also increase. When Young's modulus increases from 159 Pa to 633 Pa, the plugging rate can rise from 93.23% to 98.08%. In this study, the Young's moduli of micro and nano scale dispersed particle gels are adjusted to study the difference in plugging performances, which provides theoretical foundation for the efficient development of tight/shale oil and gas reservoirs.

Numerical Simulation Research on Hydrocarbon Gas Miscible Flooding Reservoir in Mahu Conglomerate Reservoir

TAN Long, WANG Xiaoguang, CHENG Hongjie, ZHANG Jigang, LIAN Guihui

2021, 43(5):  193-202.  DOI: 10.11885/j.issn.1674-5086.2021.03.02.01

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The depleted development vertical wells in the Mahu sag area have high initial production and rapid decline. Conventional water injection is not suitable. Through the conversion of hydrocarbon gas injection can greatly improve the recovery rate. The minimum miscibility pressure in the gas injection test area determined by the slim tube method is 41.71 MPa. Miscible flooding can generally be achieved under the current formation pressure in the Mahu area. According to the reservoir characteristics and geomechanical parameters of the Mahu area, natural fractures and artificial descriptions are also included in the simulation, and optimization of the fracture distribution shape; and a three-dimensional fracture network model is established. Based on the post-fracturing fracture network model, researches on well layout mode, gas injection rate and gas drive reservoir production law are carried out. The results show that the average fracture network of hydraulic fracturing has a major axis of 173.90 m, a longest axis of 846.90 m, and a minor axis of 6.44 m; the deployment well trajectory of oil production wells is 2/3 thicker from the top, and the gas spread is larger; the gas injection rate is optimized with the goal of maintaining miscibility In the first 10 years of the design, 55 000 cubic meters of gas per day were injected into horizontal wells, and 40 000 cubic meters per day in the next 10 years. The recovery rate of the test area can reach 22.5%; hydrocarbon gas will be preferentially displaced along the long pressure fractures of the production well after pressure, give priority to the use of crude oil in this area, resulting in uneven gas injection spread; with the injection of hydrocarbon gas, the viscosity of crude oil along the displacement front is greatly reduced. At the same time, because the injected hydrocarbon gas and crude oil are miscible, the gas is injected 5 years later. The viscosity of the remaining crude oil within the SRV range of the oil well increases significantly. Based on this research, it can effectively guide the formulation of technical policies for field development of the Mahu hydrocarbon gas injection enhanced oil recovery test.

Mechanism and Application Effect Evaluation of Nitrogen Flooding in Mahu Tight Conglomerate

LI Haonan, SONG Ping, ZHU Yating, TAN Long, ZHANG Jigang

2021, 43(5):  203-211.  DOI: 10.11885/j.issn.1674-5086.2021.03.23.02

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In order to solve the problem of rapid production decline caused by horizontal well + volume fracturing in Mahu tight conglomerate reservoir, nitrogen injection was carried out in laboratory and field to enhance oil recovery. The EOR potential of Block M is evaluated by gas drive phase behavior, miscibility and oil displacement effect. The experimental results show that the solubility of nitrogen in crude oil is small that the displacement mechanism mainly depends on its own expansibility, and that the minimum miscible pressure of nitrogen is 62.3 MPa, so it is difficult to achieve miscible flooding in Block M. A pilot test of nitrogen injection was carried out in Block M of Mahu Oilfield, and good results were obtained. The effective characteristics of oil production, oil pressure, gas oil ratio and nitrogen concentration were studied and evaluated; the change of production before and during gas injection for well group is analyzed. The increase of a total of 1 953 t of oil is obtained. Finally, based on the geological and engineering data, the main controlling factors affecting gas injection effect are systematically evaluated, which proves that horizontal well + volume fracturing nitrogen injection is a feasible technology to enhance oil recovery in tight conglomerate reservoir.

Analysis of Policy and Enlightenment on Treatment of Fracturing Fluid in Shale Gas Production Between China and the United States

CHEN Xuezhong, LU Youchang, WU Yiyi, MA Lili

2021, 43(5):  212-219.  DOI: 10.11885/j.issn.1674-5086.2021.02.25.02

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Fracturing flowback fluid is complex in composition and difficult in treatment because it is rich in chemical additives and is affected by formation water and cuttings. Based on the comparison of relevant regulations on water environmental protection and fracturing flowback fluid treatment in shale gas development between China and the United States, we find out the following problems in the environmental supervision of shale gas development in China:the unified coordination organization for the environmental supervision of shale gas development has not yet been formed; the environmental regulations and standards related to shale gas development are not perfect; the basic scientific research is weak. Therefore, the countermeasures of shale gas fracturing fluid management in China are establishing on a sound regulatory system and carrying out the entire process environmental supervision, improving basic scientific research, and enhancing the technology and management system.

Review on the Characteristics of Pyrolysis During In-situ Conversion of Oil Shale

XU Jinze, CHEN Zhangxing, ZHOU Desheng, NIE Wancai, LI Ran

2021, 43(5):  220-226.  DOI: 10.11885/j.issn.1674-5086.2021.02.28.03

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Recently, the consumption of global energy gradually increases, and the oil shale is an important substitution for the conventional oil and gas. The oil shale reserves in China are abundant, which ranks the fourth in the world. As the main technology to develop oil shale reservoirs, the in-situ conversion utilizes pyrolysis to expand seepage pathways to obtain shale oil and gas. This paper reviews the characteristics of pyrolysis from four aspects:the stage of pyrolysis, the pyrolysis of kerogen, the impact of minerals and the evolution of pore structures assisted by pyrolysis:(1) thermophysical evolution and thermochemical reactions in different stages of pyrolysis reaction; (2) reaction mechanism of kerogen pyrolysis and its influencing factors; (3) promoting and inhibiting effects of mineral decomposition on pyrolysis; (4) the mechanism of pore structure evolution assisted by pyrolysis and its effects on fracture propagation. This paper is based on the pyrolysis which is the core technical challenge during the in-situ conversion. It will also provide some references for the application of in-situ conversion in oil shale and shale oil with low and medium maturities.

Research Progress on Fluids Flow Mechanism and Mathematical Model in Tight Oil Reservoirs

CAO Renyi, CHENG Linsong, DU Xulin, SHI Junjie, YANG Chenxu

2021, 43(5):  113-136.  DOI: 10.11885/j.issn.1674-5086.2021.02.25.01

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Tight oil reservoirs have great potential and wide distribution in China. Nowadays it has become an important guarantee for stable and high production of Changqing, Daqing, Xinjiang and Jilin oilfields in China, and it is also the hotspot and difficulty of global oil and gas development. Tight matrix is characterized by tight rock and its porosity and permeability are very low. The influence of micro-scale flow effect is significant due to its submicron main throat. The traditional fluids flow theory of oil and gas cannot accurately describe the flow law of this kind of reservoir. The exploitation of such reservoirs is accomparied by the difficulties in oil flow and flooding and low production. Generally, horizontal well and hydraulic fracturing are used to realize efficient development of tight oil reservoir. This paper expounds the latest research progress of fluids flow mechanism and mathematical models of tight oil reservoir:flow mechanism and mathematical model of micro-nano pore and throat; stress sensitivity and mathematical model of tight oil reservoir; nonlinear mathematical model for tight oil reservoir; pore network simulation and nonlinear flow law; coupled flow between tight matrix and fracture. We summarize the development trend of these key scientific problems, which has important theoretical significance for the scientific and efficient development of tight oil reservoirs.