Table of Content

25 June 2021, Volume 28 Issue 3

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Geologic Exploration

Sedimentary Facies of Member 3 of the Upper Triassic Baijiantan Formation in the Western Slope Area of Mahu Sag and Its Significance for Hydrocarbon Exploration

Wu Xin, Hu Xiaoyun, Han Lei, Xu Xin, Peng Xuehong, Liang Tao, Zeng Yulan, Li Weifeng

2021, 28(3):  1-8.  DOI: 10.3969/j.issn.1006-6535.2021.03.001

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In order to fill the gap in sedimentology of Baijiantan Formation in the western slope area of Mahu Sag, the sedimentary facies of Member 3 of Baijiantan Formation were studied with core, logging, and analytical and test data. The results showed that the target layer was of the braided river delta facies, two subfacies (delta front and prodelta) and five microfacies (underwater distributary channel, inter-tributary bays, channel mouth bar, distal bar, and prodelta mud) were identified; under the background of shallow-water deposit, there were braided river delta-front lobes developed in two provenance directions in northwest and northeast in the study area; during the period of deposition from T₃b₃⁴ sublayer at the bottom to T₃b₃¹ sublayer at the top, the front lobe continued to accumulate towards the center of the lake basin; during the deposition period of T₃b₃² and T₃b₃¹ sublayers, underwater distributary channel and underwater distributary channel were widely distributed in the study area and could be used as the primary targets for subsequent oil and gas exploration in the study area due to their excellent internal storage reservoir physical properties and external structural traps and hydrocarbon charging conditions. The study results can provide strong theoretical support for future oil and gas exploration of Baijiantan Formation in the study area.

Prediction Method Optimization for S-wave in Mahu Area and Its Influence on Calculation of Rock Mechanics Parameters

Wu Shunwei, Gao Yang, Hu Jun, Hu Haisheng, He Jinyu, Wang Gang

2021, 28(3):  9-14.  DOI: 10.3969/j.issn.1006-6535.2021.03.002

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In view of the absence of S-wave velocity, an important geophysical parameter and the low accuracy of empirical formula in actual production, taking the Mahu area as an example, the Xu-White model was finally selected by screening and analyzing the theoretical model of S-wave prediction, the geological depositional setting and burial depth were considered, S-wave velocity curve was calculated according to mineral composition, porosity and fluid composition curves, and the influence of the accuracy of S-wave velocity prediction on the calculation results of rock mechanics parameters was studied. After verification with measured dipole acoustic data, indoor core mechanical measurement data, and fracturing operation data, compared with the results calculated by conventional empirical formula, the accuracy of Xu-White model was greatly improved. The model was generally applicable to the glutenite stratum in the Baikouquan Formation, Mahu area. This technology has proven to be highly effective in the accurate calculation of rock mechanics parameters and the fracturing scheme design of glutenite tight oil reservoir. It is of great significance to the study on the geology-engineering integration in the development of tight oil in Mahu area.

Analysis of Influencing Factors on Distribution of Hydrothermal Dolomite of Member 3 of Maokou Formation in Fuling Area

Pan Lei, Tang Dehai, Li Rangbin, Zou Yutao, Zhang Wenrui

2021, 28(3):  15-24.  DOI: 10.3969/j.issn.1006-6535.2021.03.003

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In view of the strong heterogeneity of hydrothermal dolomite distribution, the relationship between basement rift and sedimentary evolution of the Member 3 of Maokou Formation was studied, the relationship between rift mode and dolomite distribution was analyzed, and the sedimentary evolution model was established to predict the distribution of dolomite. According to the study, the Member 3 of Maokou Formation was divided into 5 layers, 1 to 3 layers were the main period of dolomite development, 4 and 5 layers were the platform homogenization period, and no dolomite was not developed;15-1, 15-2 and 16 basement rifts controlled the sedimentary landform of the early "platform-sag" facies, the high geomorphic layer near the rift was favorable for the development of bioclastic beaches, which provided the material basis for the development of dolomite; 15-1 and 15-2 basement rift were flower-shaped, and the surrounding bioclastic beaches were highly dolomitized, which was the most favorable area for the development of dolomite; the 16 basement rift was upright, with low dolomitization in surrounding area, which was relatively favorable for the development of dolomite. The study results can provide a guiding basis for further exploration of hydrothermal dolomite.

Fracture Development Characteristics and Main Controlling Factors of Carboniferous Volcanic Reservoir in Hongshanzui Oilfield

Zhang Xingyong

2021, 28(3):  25-32.  DOI: 10.3969/j.issn.1006-6535.2021.03.004

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Carboniferous volcanic reservoir in Hongshanzui Oilfield is a typical pore-fractured dual media reservoir. Fracture is an important factor affecting hydrocarbon migration, accumulation, concentration and high yield, and also a key to restricting volcanic reservoir exploration in the study area. In order to achieve the efficient development of Carboniferous volcanic reservoirs, the main controlling factors affecting fracture development were identified based on the analysis of fracture characteristics of volcanic reservoirs, in combination with core, slice, and imaging logging data. The results showed that The fractures of Carboniferous volcanic rocks were mainly tectonic fracture, followed by diagenetic fracture and weathered fracture. Among tectonic fractures, high-angle fracture and low-angle oblique fracture were most developed. There were three groups of fractures in nearly east-west, northwest, and north-north east directions, dominated by small fractures and micro fractures, which were generated by different tectonic movements. The formation and distribution of fractures were controlled by lithology, weathered crust, faults and diagenesis. The difference in mineral composition of different lithological volcanic rocks resulted in different fracture types and pore-fracture combination modes. The difference in weathering intensity controlled the formation of weathered fracture and the development of dissolution fractures in the weathered crust. Fault activity affected the strike and distribution of associated fractures. The closer to the fault, the higher the density of fractures was. The early primary fractures were filled and reconstructed under the action of diagenesis, intensifying the fracture heterogeneity of volcanic reservoir. The study results play a guiding role in the effective development of Carboniferous volcanic reservoir in the northwestern margin of Junggar Basin.

Analysis of Hydrocarbon Accumulation and Exploration Potential of Chang₆-Chang₈ Pay Zones of Yanchang Formation in North Jiyuan Area

Shen Zhicheng, Zhao Huchun, Wang Weilin, Jing Wenping, Cao Pengfu, Tian Yaming, Zhang Jianxin

2021, 28(3):  33-39.  DOI: 10.3969/j.issn.1006-6535.2021.03.005

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In view of the relatively weak exploration and poor understanding of the exploration potential of the Yanchang Formation in the northern Jiyuan area, the hydrocarbon source rock conditions, reservoir conditions, accumulation mode and reservoir characteristics of the Chang₆-Chang₈ pay zones of Yanchang Formation in the northern Jiyuan area were analyzed and studied with drilling, analysis and laboratory data. It was found in the study that hydrocarbon source rock was developed in the Chang₇ pay zones of Yanchang Formation in the northern Jiyuan area, the dark mudstone at the bottom of Chang₇³ was effective hydrocarbon source rock; the organic carbon content was generally greater than 2%, the average content of chloroform bitumen "A" was 0.189%, the average of hydrocarbon generation potential S₁+S₂ was 13.01 mg/g, the organic matter abundance was high, the organic matter was dominated by Type I with basic source for petroleum generation; the average sand thickness of Chang₆ and Chang₈ pay zones was more than 10m, and the pore-throat combination was mainly small pore + micro-throat, micro pore + micro throat, locally medium pore + medium throat, and the porosity was mainly 8% to 12%; because of the longitudinal and transverse migration of the river channel, favorable reservoir-capping assemblage was formed, constituting lithologic and physical traps; the reservoir distribution was controlled by superposition of hydrocarbon source rock spreading, sand facies distribution and reservoir development. It was generally considered that this area had great oil exploration potential, and Wellblocks Feng 201 and Feng 11 were identified as the most favorable stacked exploration target areas in the area. The study is of guiding significance for the next oilfield exploration and development in the Yanchang Formation, the northern Jiyuan area.

Prediction of Favorable Reservoir Distribution on the Top of Badaowan Formation in Wellblock Chepai 7, Northwestern Margin, Junggar Basin

Zhang Shangming, Cheng Zhongjiang, Jin Ping, Peng Licai, Zeng Qingzi

2021, 28(3):  40-46.  DOI: 10.3969/j.issn.1006-6535.2021.03.006

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Due to the poor understanding of favorable reservoir distribution and oil-water relationship in the top oil-gas-producing interval of the Badaowan Formation in the Wellblock Chepai 7, northwestern margin, the Junggar Basin, it is difficult to make progress in the evaluation of reservoir expansion. Based on logging, well testing and seismic data, the sedimentary facies and favorable reservoir distribution in the study area were carefully studied by means of sedimentary facies division, comparison of sand facies in continuous wells, seismic attribute analysis, seismic wave impedance inversion, stratigraphic slicing, etc. The results showed that there was fan prodelta sedimentary subfacies developed on the top of the Badaowan Formation, three relatively independent fan delta underwater distributary channel sand facies developed on the top of the Badaowan Formation from northwest to southeast, two of which were favorable oil and gas reservoirs. The sand facies of Wells Che 5027 and 369 were two independent disconnected sand facies. The sand facies of Well Che 5027 and Well Chepai 7 could be expanded in direction of southeast, southeast and northeast respectively. The study results play a guiding role in the further development of the Badaowan Formation in the study area.

Analysis of reservoir characteristics and their effect on productivity of overseas carbonate reservoirs

Lu Zhiming, Xu Shipeng, Aini Maimaiti, Wang Chenglin, Gao Liqun, Yang Zhigang, Yan Chao, Huo Jinjie

2021, 28(3):  47-53.  DOI: 10.3969/j.issn.1006-6535.2021.03.007

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A comprehensive and detailed analysis of reservoir characteristics is urgently needed to address the problems of complex and diverse lithologies and space types, difficult identification of favorable reservoirs, and poor understanding of distribution characteristics of fracture zones and effect on productivity in the Karabulak Oilfield (a carbonate reservoir), the South Turgay Basin, Kazakhstan. By applying core-conventional logging-seismic data calibration step by step, centered on sensitivity curve and sensitivity parameter optimization, four lithologies were identified, mainly tuff, biotuff, breccia tuff and mud tuff. Reservoir space types were dominated by fracture-cavity type, fracture-karst breccia type, fracture type and cavity type. According to the results of formation testing and pilot production, the reservoirs were divided into Types Ⅰ,Ⅱ, and Ⅲ, and favorable reservoir development areas were identified, including biological limestone development area, fractured limestone development area, and argillaceous limestone and karst breccia development area. fracture development areas are mainly concentrated near the northern fault zone of the central area, with great contribution to productivity of the oilfield. This study provides important ideas for the study of the characteristics of overseas carbonate reservoirs and an important reference for efficient development of similar reservoirs.

Main Controlling Factors and Modes of Tight Oil Accumulation in Sanzhao Area

Bai Junhui

2021, 28(3):  54-61.  DOI: 10.3969/j.issn.1006-6535.2021.03.008

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In view of the differences in the characteristics and scale of tight oil reservoirs in different tectonic units in Sanzhao area, tight oil accumulation mode of Fuyu oil-bearing formation in each tectonic unit was established by analysis of tight oil accumulation conditions, residual pressure in the accumulation period, fault distribution, sand distribution and physical property characteristics. The results showed that the main driving force of tight oil charging and accumulation in the late period of the Mingshui Formation was the residual pressure formed by hydrocarbon generation and pressurization when the hydrocarbon source rocks matured on a large scale; as an important channel of lateral migration, the three-dimensional conductor composed of fault and sand was a necessary condition for the formation of quasi continuous hydrocarbon accumulation; the local “sweet spot” reservoir under the background of tight oil was a favorable area for tight oil enrichment and high production. Three accumulation modes were established: “overpressure driving and near-source oil and gas backflow” in the northern sedimentary center of the sag, “fault-sand matching and near-source lateral migration and accumulation” in the peripheral slope area, and “fault transmission and distant-source lateral migration and accumulation” in the southern uplift. Accumulation modes and tight oil enrichment rules were different in different regions. This study may provide a geological basis for the selection of tight oil exploration targets in different regions.

Reservoir Engineering

Numerical Simulation Based on Microseismic Discrete Fractures and Automatic History Matching

Qu Xuefeng, Xie Qichao, Lan Zhengkai, Zhao Guoxi

2021, 28(3):  62-68.  DOI: 10.3969/j.issn.1006-6535.2021.03.009

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In view of the detailed description of complex fracture network, complex characterization, cumbersome history matching of numerical simulation, and strong uncertainty, which make it difficult to achieve accurate numerical simulation of unconventional reservoirs, a comprehensive numerical simulation technology was developed by three means: microseismic complex seam network inversion, detailed description of discrete fracture network and ensemble Kalman filter (EnKF) to realize accurate numerical simulation of unconventional reservoirs under complex fracture network conditions. The results showed that the difference between the results respectively obtained by the complex fracture network inversion method in the paper and the direct interpretation was small, with an error of 2% to 6%, but the method presented in this paper could directly reflect the distribution and propagation of underground artificial fractures; the unstructured network based on artificial fracture network could be used to characterize the flow in fractures in detail; the automatic history matching technology based on EnKF could reduce artificial matching errors and improve matching efficiency. Field tests show that the average matching rate between the matched daily oil production and the actual production of 28 single wells in the study area was as high as 91%, realizing accurate simulation of the complex seepage field in oil and gas reservoirs. This study can provide a reference for the production prediction of complex fracture network of unconventional reservoir.

Study on Fracture Development Mode and Horizontal Well Development Optimization in Ebano Oilfield

Wang Xixian

2021, 28(3):  69-75.  DOI: 10.3969/j.issn.1006-6535.2021.03.010

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To address the poor understanding of fracture connectivity in the Ksf and Kan formations in the Ebano Oilfield, the fracture connectivity in the longitudinal and planar directions was studied with core analysis, PLT testing, imaging logging data, reservoir numerical simulation and seismic coherent attribute technologies. It was found in the study that the Ebano Oilfield was dominated by semi-open fractures which included high-angle tectonic fractures in the near north-south direction and horizontal bedding fractures in the near east-west direction, and the high-angle fractures and horizontal fractures formed a complex network system of fractures; the fracture connectivity of the Ksf and Kan formations was divided into three types: excellent top-bottom connectivity, normal top-bottom connectivity, and top-bottom disconnection; fracture and crude oil viscosity were the main controlling factors to determine the productivity of oil wells, and the length of the horizontal interval had little effect on productivity. The study results were applied to short horizontal section development tests in the southeastern of Ebano Oilfield, and achieved better development results. The average initial daily oil production of a single well in 2020 was 141% of the average initial daily oil production of a single well from 2012 to 2014. There is much for reference of the results of the study to different types of fracture development.

Binomial apparent permeability formula based on multiple migration mechanism of shale gas

Yuan Yingzhong, Yan Wende, Qi Zhilin, Li Jiqiang, Huang Xiaoliang

2021, 28(3):  76-80.  DOI: 10.3969/j.issn.1006-6535.2021.03.011

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The binomial formula of apparent permeability and average pressure reciprocal based on multiple migration mechanisms of shale gas was obtained by using theoretical derivation combined with experimental data analysis to address the problem that the poor matching between the apparent permeability formula of shale gas and the experimental data fails to well reflect the multiple migration mechanisms of shale gas such as viscous flow, slip flow, Knudsen diffusion and surface diffusion. This formula took into account the change of the velocity gradient with the distance of the pore wall and the apparent permeability of surface diffusion related to the square of pressure reciprocal. The study results were applied to analyzing the apparent permeability test data of shale gas, and the results showed that the change of velocity gradient led to negative curvature in the relationship curve between apparent permeability and average pressure reciprocal, and surface diffusion led to positive curvature. The binomial parameters a and b were obtained based on curve regression to calculate the apparent permeability and surface diffusion coefficient caused by surface diffusion. The study results explained the existing experimental data more effectively, with great significance for studying the multiple migration mechanism of shale gas and analyzing the development performance.

Vertical Well Assisted SAGD Dilation and Coupled Numerical Simulation of Geomechanics and Thermal Recovery

Zhao Rui, Sang Linxiang, Chen Lunjun, Xu Bin, Luo Chihui, Meng Xiangbing

2021, 28(3):  81-86.  DOI: 10.3969/j.issn.1006-6535.2021.03.012

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In order to solve the problem of uneven production in horizontal interval after the start of SAGD dilation of dual horizontal wells in heterogeneous reservoir, a new composite dilation technology of vertical well assisted SAGD dilation in horizontal well was proposed from two aspects of improving seepage conditions and optimizing driving mechanism. By coupling the geomechanical finite element method with the numerical simulation model of thermal recovery in oil reservoir, the changes of physical parameters and fluid flow behavior of the geomechanical dilation reservoir of loose sandstone were analyzed, and the development effect of thermal recovery with steam injection after dilation by the new technology was predicted. The study results showed that the vertical well assisted SAGD dilation should be conducted in the order of horizontal well first and vertical well later, so as to prevent local channeling in the dilation position caused by vertical well dilation first, which was conducive to the formation of uniform composite dilation zone; the width of dilation zone of vertical well was sensitive to the angle between horizontal well track and in-situ stress direction, and the width of dilation zone was the largest when the horizontal well track was parallel to the maximum horizontal stress; whether vertical well connected to the dilation zone of horizontal well was not directly related to the angle between horizontal well track and in-situ stress direction; the greater the distance between the vertical well and the SAGD horizontal well, the more difficult it was to connect the dilation zone. Compared with the traditional SAGD technology, after the vertical well assisted dilation, the gravity drainage of the SAGD horizontal well and the steam huff and puff of vertical well could work together, and the effect of increasing production was significant. The study results can provide guidance for the on-site implementation of SAGD dilation.

Quantitative Evaluation of Main Controlling Factors of Capacity and Working Gas Volume Pf Volcanic Gas Storage With Bottom Water

Gao Tao

2021, 28(3):  87-93.  DOI: 10.3969/j.issn.1006-6535.2021.03.013

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In view of the special geological conditions of the Shengping gas storage that was reconstructed from a volcanic gas reservoir with bottom water, the effective gas-bearing pore volume was calculated by the gas saturation respectively of pure gas zone, transition zone and water flooded zone, a three-zone storage capacity parameter model of gas storage was established under consideration of effect of water invasion, stress sensitivity, rock and bound water deformation, a calculation method was optimized and designed to iteratively calculate the maximum working gas volume and the relevant storage capacity in different operating pressure intervals, and a quantitative evaluation was conducted on the effect of water invasion, stress sensitivity, rock and bound water deformation and other factors on the storage capacity and working gas volume. The results showed that the loss of gas-bearing pore volume was the largest in the transition zone, followed by the pure gas zone and then the water flooded zone; in terms of the loss of gas-bearing pore volume by different factors, water invasion was the dominant controlling factor, and rock and bound water expansion and stress sensitivity were non-dominant controlling factor and resulted in less loss of gas-bearing pore volume. With the established storage capacity parameter model, the maximum working gas volume was 25.61×10⁸m³ under the upper operating pressure limit of 32 MPa, and the storage capacity is 64.74×10⁸m³ corresponding to the optimal lower operation pressure limit of 18 MPa. The study results can provide reference for the reconstruction of gas storage in similar volcanic gas reservoirs with low permeability and bottom water at home and abroad.

Numerical Simulation on Fracturing in Tight Conglomerate Reservoir of Mahu Oilfield

Lu Wenting, Wang Liang, Yang Shengfeng, Liu Congping, Ma Junxiu, Tang Lin, Li Yunzhe

2021, 28(3):  94-98.  DOI: 10.3969/j.issn.1006-6535.2021.03.014

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In order to fully understand the conditions of tight conglomerate reservoir in the Mahu Oilfield, reduce the interference of inter-well fractures, achieve precise fracturing and complete productivity prediction, a three-dimensional numerical model was established with the simulation of geology, in-situ stress, and fracturing coupling. Taking the experimental area of the Mahu tight oil reservoir as an example, a single well in-situ stress model was completed according to the existing geological data, an accurate three-dimensional in-situ stress model was established on the in-situ stress model, and an artificial fracture model was loaded. With the coupled fracturing model, the rule of in-situ stress changing with time and space after the fracturing was completed in the study area was analyzed and compared with the artificial fracture morphology under static geological conditions. It was found in the study that the production indicators obtained by fitting the three-dimensional numerical model were highly accurate, with practical significance. The three-dimensional numerical model was used to obtain the engineering parameters of Well X in the experimental area of the Mahu tight oil reservoir. After the reservoir was put into production, the average daily oil produced was 23.4 t/d within 300 days, the average oil pressure was 22.3 MPa, and the stable production duration was long. This study will be in favor of optimizing the fracturing design and reducing the interference of stress shadow.

Study on Automatic Reservoir History Matching Based on ES-MDA Algorithm

Wang Zelong, Liu Xiangui, Tang Haifa, Lyu Zhikai, Liu Qunming

2021, 28(3):  99-105.  DOI: 10.3969/j.issn.1006-6535.2021.03.015

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To address the shortcomings of common history matching methods such as large amounts of computation, abnormal update of reservoir parameters, and distortion of reservoir model corrections, ensemble smoother algorithm was adopted to repeatedly assimilate the same data by multiple iterations in the ensemble Kalman filter (EnKF) algorithm to derive the core formula of the ES-MDA algorithm (ensemble smoother with multiple data assimilations) and write automatic reservoir history matching software. In a case study of marine sandstone reservoir of Brent Oilfield in the North Sea, the automatic history matching program of the reservoir based on the ES-MDA was applied to the reservoir to conduct history matching for water injection, oil production and development of the oilfield. The results showed that the predicted data obtained from the numerical modeling of the reservoir matched the actual measured data by more than 90%, and characterized the porosity distribution of the real reservoir more accurately. The ES-MDA algorithm is advantaged by stable algorithm, high operation efficiency and accurate model updating. The research results are of great significance for realizing computer-based automatic reservoir history matching and real-time optimization of reservoir production.

Research on Production Conditions of Film Remaining Oil

Xia Huifen, Wang Lihui, Han Peihui, Cao Ruibo, Liu Lili, Zhang Siqi

2021, 28(3):  106-111.  DOI: 10.3969/j.issn.1006-6535.2021.03.016

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In view of the unclear producing conditions of the film remaining oil, Polyflow software analog computation and micro-visual displacement experiment were used to study the effect of the interfacial tension of the ASP flooding system on the film remaining oil production, and compare and analyze the critical rupture conditions of the film remaining oil under different conditions. The results showed that when the capillary force of the oil film was less than the normal force of the displacement fluid on the oil film, the oil film would rupture. For the same oil film, the larger the number of capillaries in the flow field, the higher the deformation rate of the oil film. When the number of capillaries is less than 0.10, the deformation range of oil film was small; when the number of capillaries was 1.00, the deformation of oil film was increased significantly. At the same oil film length, the smaller the oil film height, the smaller the oil film volume, the more the capillaries on the critical surface, and the lower the critical interfacial tension. At the same oil film height, the smaller the oil film length, the larger the oil film volume, the less capillaries on the critical surface, and the higher the interfacial tension of oil film rupture. The microscopic oil displacement images and numerical simulation results showed that when the interfacial tension reached the order of 10^-2 mN/m, the film remaining oil attached to the pore wall could be used. This study is of guiding significance for the study of microcosmic remaining oil production.

Study on Injection Mode of CO₂ Flooding Based on Physical Model of Fracture Radial Flow

Shi Lihua, Wang Weibo, Wang Chengjun, Chen Longlong

2021, 28(3):  112-117.  DOI: 10.3969/j.issn.1006-6535.2021.03.017

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Aiming at the optimization of different injection methods of CO₂ flooding after water flooding, based on the physical model of fracture radial flow, indoor experiment was conducted on CO₂ compound flooding in single fracture and complex fracture in five-spot well pattern (one well in injection and four other wells in production) to study the effect of CO₂ flooding with different injection processes after water flooding in low-permeability fractured reservoir. The results showed that: after the water flooding of the single fracture model, different injection processes, such as continuous CO₂ flooding, modified starch gel injection and ethylenediamine injection, were implemented successively, the recovery percent of the reservoir increased firstly and then decreased, and finally the recovery efficiency could be increased by 65.7% on the basis of the single-fracture water flooding; after water flooding of complex fracture model, different injection processes, different injection processes such as continuous CO₂ flooding, modified starch gel injection, ethylenediamine injection and water alternate gas, were implemented successively; the effect of water alternate gas on improving CO₂ flooding effect was the best and the recovery efficiency could be increased by 28.89% on the basis of single-fracture water flooding. The study results play a guiding role in CO₂ flooding after water flooding in low-permeability fractured reservoirs.

Experimental Study on Improving Recovery Efficiency of Tight Oil Reservoirs with Supercritical Carbon Dioxide Flooding

Zhou Xiang, Zhou Dan, Deng Jiasheng, Deng Jingyi, Ray Rui, Jiang Zheren

2021, 28(3):  118-123.  DOI: 10.3969/j.issn.1006-6535.2021.03.018

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In view of rapid decline in oil recovery rate in the late stage of natural depletion of tight oil reservoirs in the Mahu area, a study design of developing tight oil reservoirs with supercritical CO₂ displacement was put forward. The experiments on tight oil extraction with supercritical CO₂, minimum miscibility pressure and long core displacement were conducted to study the mechanism, development characteristics and influence factors of improving recovery efficiency of tight oil reservoirs with supercritical CO₂ displacement, and optimize important operating parameters such as gas injection rate and CO₂ injection occasion. The experimental results show that the capacity of light component after CO₂ extraction decreased with the increase of extraction times; the gas injection rate had a greater impact on the final recovery efficiency, and the optimal gas injection rate was 0.10 cm³/min; the minimum miscibility pressure of crude oil and supercritical CO₂ was 34.18 MPa; the current pressure in the reservoir was the best occasion for CO₂ injection. The study results play a guiding role in the efficient development of tight oil reservoirs.

Experiment on Injection Parameter Optimization for Air Foam Flooding in Low-permeability Heterogeneous Reservoir

Huang Wei, Wen Rou, Pang Jin, Sun Yajun, Yang Wenjun

2021, 28(3):  124-129.  DOI: 10.3969/j.issn.1006-6535.2021.03.019

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To address the difficulty of optimizing the injection parameters of different permeability reservoirs in the process of air foam flooding in low-permeability heterogeneous reservoir, in a case study of natural core from Change₆³ Formation in Ansai Oilfield, experiments on injection parameter optimization for air foam flooding were performed with one-dimensional core flow experimental equipment to optimize the gas-liquid ratio, foam slug volume, injection pressure, injection rate and injection time to obtain the best injection parameters, and analyze the optimization law of injection parameters for air foam flooding in different permeability reservoirs. The results showed that with the increase of gas-liquid ratio, foam slug volume, injection pressure and injection rate, the recovery percent of the same group of cores increased, and when the injection parameters reached a certain level, the recovery percent increment increased or decreased and there was an optimal value for each injection parameter; different injection parameters greatly affected the recovery percent, especially sensitive to the reservoirs with low permeability; there was a good exponential decreasing relationship between the permeability and the optimal injection gas-liquid ratio, injection volume, injection pressure and injection rate, and air foam injection at low water cut resulted in a recovery efficiency. The study results provide a theoretical basis for regional layered and fine injection of air foam flooding in low-permeability reservoir.

Drilling & Production Engineering

Rock Mechanical Properties of Deep Shale Gas Reservoirs and Their Influence on Fracturing Stimulation

Li Qinghui, Li Shaoxuan, Liu Weizhou

2021, 28(3):  130-138.  DOI: 10.3969/j.issn.1006-6535.2021.03.020

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The occurrence depth has a significant effect on the rock mechanical properties of shale reservoir. The deformation and failure mechanism of deep shale was studied to obtain the law of the effect of occurrence depth on the rock mechanical parameters and provide crucial basic parameters for shale oil and gas development. Rock mechanics experiments were conducted with shale rock samples at different depths to analyze the key mechanical properties of deep shale were analyzed and obtain the variation law of its strength parameters and deformation modulus. The results showed that deep shale was significantly different from shallow shale in terms of mechanical strength, resistance to deformation and failure, and fracture mode. With the increase of depth, the strength of the shale gradually increases and the brittleness gradually deteriorates, leading to more difficulties in fracturing stimulation. Most rock mechanical parameters were strengthened with the increase of confining pressure. Confining pressure, density, etc. are the key factors affecting the mechanical performance of deep shale. Changes in the mechanical properties of deep shale greatly affect the initiation, turning and other mechanical behavior of fracturing fractures. The fracture generation capability of deep shale gradually decreases with the increase of the occurrence depth. The research results provide important reference and theoretical basis for the evaluation of deep shale reservoirs and the practice of drilling and completion.

Study on the Effect of Shale Expansion Strain and Cementing Quality on Casing Deformation

Li Gao, Li Ze, Jian Xu, Li Hongtao, Yu Hao, Wang Tao

2021, 28(3):  139-143.  DOI: 10.3969/j.issn.1006-6535.2021.03.021

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The casing deformation in shale gas wells in Weirong area is a prominent problem, but the mechanism that causes casing deformation in this area is still unclear. In this paper, based on the physical and chemical properties of shale, the effect of shale expansion strain on casing stress was analyzed, and the relationship between cementing quality and casing deformation under the consideration of shale expansion strain was studied. It was found in the study that the shale in the Weirong area was hard and brittle, with high mechanical strength and insignificant strength changes after hydration and the combined action of shale expansion strain and cementing quality exerted a significant effect on the casing stress. When cement sheath was missing and micro-annulus existed, there was sufficient space for releasing expansion strain to reduce casing stress. When the expansion stress could not be released completely, it was necessary to ensure the structural integrity of wellbore assembly. High-density perforation had a positive effect on the release of expansion strain. High-density perforation based on reasonable perforation parameters was one of the effective measures to prevent casing deformation. This study provides a reference for the study of casing deformation mechanism in similar shale gas reservoir.

Development and Application of Supporting String for Composite Huff and Puff Technology of Heavy Oil Reservoirs

Lang Baoshan

2021, 28(3):  144-150.  DOI: 10.3969/j.issn.1006-6535.2021.03.022

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In the middle and later development stages of heavy oil reservoirs, there are more challenges such as uneven productivity, low pressure and low production, steam channeling, which have seriously affected the development efficiency of heavy oil reservoirs. In the field application of composite huff-puff technologies such as carbon dioxide and nitrogen assisted drainage, there are problems such as poor pertinence of measures, long construction period, and low production rate. In this regard, core tools such as ball injector, double-acting packer and reversible injection valve ball were developed, and the layered steam injection mechanical string was flexibly combined with the composite huff and puff technology to develop the supporting string technology for composite huff and puff in heavy oil reservoirs, realizing the purpose of quantitative injection of different media on demand. The field application indicated that this technology solved the problem of low application efficiency of conventional composite huff and puff technology and effectively improved the composite huff-puff effect and production rate of oil wells. This technology supports the scale application of the composite huff and puff technology in the later development stage of heavy oil reservoirs, with promising application and high potential.

Analysis on the Thermal Efficiency of SAGD Development in Mid-deep Super Heavy Oil Reservoirs

Yang Lilong

2021, 28(3):  151-156.  DOI: 10.3969/j.issn.1006-6535.2021.03.023

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In view of the problems of high heat consumption and low heat utilization rate in SAGD (steam assisted gravity drainage) development of med-deep super heavy oil reservoirs, the causes and influencing factors of heat loss in each stage of SAGD development were analyzed with reference to the actual SAGD production data of Guantao formation reservoir of Block Du 84 of Liaohe Oilfield, and countermeasures to improve the thermal efficiency were put forward. The results showed that the heat loss in the whole SAGD development included the heat loss of steam injection boiler, the heat loss of steam-water separator, the heat loss of steam injection pipe, the heat loss of steam injection wellbore, the formation heat absorption, and the heat loss of production wellbore; the heat loss mainly occurred in the steam injection boiler, steam-water separator, steam injection pipeline and steam injection wellbore; the heat loss ratio reached 34.8%, and the formation heat absorption ratio was only 36.0%. Countermeasures to improve thermal efficiency were put forward for the main heat loss stage and implemented on site, and the comprehensive thermal efficiency was increased by 17.0 percentage points. This study provides technical reference for improving the development effectiveness and economical efficiency of SAGD in med-deep super-heavy oil reservoirs.

Study and Application of Fishing Electric Submersible Pump Technology Without Workover Rig

Yu Zhigang, Song Lizhi, Fan Yuanhong, Yu Dong, Dong Jiayong, Zhou Chongke

2021, 28(3):  157-161.  DOI: 10.3969/j.issn.1006-6535.2021.03.024

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In response to the challenges of high well workover costs, difficult resource coordination, slow resumption of production and high impact on production in workover operations of offshore marginal oilfield, a study was conducted on fishing electric submersible pump technology without workover rig. With the design and development of key tools such as electrical wet joint system, retracting cylinder system and suspension system, this technology achieves the purpose of replacing the electric submersible pump by steel wire (cable) fishing tool, and no workover rig is required in workover operation, greatly reducing the cost, shorten the shutdown time of oil wells, and improving the production rate. The field application demonstrated that this technology was well-developed and reliable, reducing the operating cost per well by about 70%. This technology may improve the development benefits of offshore marginal oilfields and win wider application range.

Study on Screen-through Deflagration Fracturing Technology

Sun Lin, Huang Bo, Zhang Jie, Wu Feipeng, Li Xuguang, Xiong Peiqi

2021, 28(3):  162-167.  DOI: 10.3969/j.issn.1006-6535.2021.03.025

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Aiming at the problem that conventional acid fracturing measures for oil wells with screen completion in offshore oilfields are limited by platform space, a screen-through deflagration fracturing technology was developed. The HY-1 propellant with a radial burning rate of 3.57 mm/s (ambient pressure of 6.0 MPa), an impetus of 669 kJ/kg, and a heat resistance of up to 178 ℃(48 h) has been developed with the optimization analysis method of propellant parameters; high-precision screen-completion deflagration fracturing simulation software was developed based on the screen pressure drop in wellbore and the well deviation model with pressurized liquid column; ground and downhole targeting tests were conducted and the results indicated that when the safe dosage of propellant was no more than 3.2 kg/m, and the downhole peak pressure was less than 46.8 MPa and the sum of formation pressure, the deflagration could fracture the reservoir without damage to the screen, and achieved remarkable effect in the two test wells by 2.7 times and 3.0 times of oil enhancement respectively. The screen-through deflagration fracturing technology indicates a new technical direction for the stimulation of oil wells with screen completion in offshore oilfields.

Fatigue Failure Analysis and Fatigue Life Prediction of the Long Round Thread of the Casing Under Multi-axial Alternate Load

Xie Shiyuan, Zhao Chaoyang, Guan Zhigang, Wang Hongfeng, Song Lin, Lin Tiejun, Zhang Qiang

2021, 28(3):  168-174.  DOI: 10.3969/j.issn.1006-6535.2021.03.026

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During casing running and fracturing, it is easy to cause fatigue failure to casing threads under multi-axial alternate loads, affecting the construction progress. To address this problem, a finite element model of long round thread of the casing was established by Abaqus software with finite element method, and an analysis was conducted on the stresses and strains of casing thread under multi-axial alternate loads such as tension, compression, and internal pressure after buckling, and the life of casing threads under multi-axial alternate load was calculated by the life assessment method based on the Mises yield criterion. It was found in the study that under the action of multi-axial alternate loads such as tension, compression, and internal pressure, the maximum stress on the casing thread acted at the bottom of the 5 teeth at the big end of the male buckle; under the action of alternate loads such as axial tension and compression, the fatigue life of the lower thread is only 1 298 times. When the internal pressure was 46, 66, and 100 MPa, the fatigue life of the thread was decreased with the increase of the internal pressure, 1 094, 1 050, and 901 times, respectively. The study results provide a reference for the analysis of casing thread failure during fracturing in tight oil and unconventional oilfields.