Table of Content

25 February 2023, Volume 30 Issue 1

Previous Issue    Next Issue

Summary

Development Status and Prospect of EOR Technology in Low-Permeability Reservoirs

Wang Zhe, Cao Guangsheng, Bai Yujie, Wang Peilun, Wang Xin

2023, 30(1):  1-13.  DOI: 10.3969/j.issn.1006-6535.2023.01.001

Asbtract ( )   PDF (1320KB) ( )  

References | Related Articles | Metrics

Low-permeability reservoirs are rich in reserves, with great commercial value, but they are defective in poor porosity and permeability, high reservoir heterogeneity, poor water absorption capacity, etc., increasing the technical difficulties in development. To address these defects, the technology of enhancing oil recovery in low-permeability reservoirs was discussed based on extensive reference. The study results show that low-permeability reservoirs (10.0-50.0 mD) were principally developed by polymer flooding, polymer-surfactant binary flooding, microbial flooding and in-depth profile control and surfactant flooding, extra-low-permeability reservoirs (1.0-10.0 mD) chiefly developed by surfactant flooding, foam flooding and nano-material flooding, and ultra-low-permeability reservoirs (0.1-1.0 mD) primarily developed by imbibition, CO₂ flooding, N₂ flooding and air flooding, etc. It is the development trend of low-permeability reservoir development in China to gradually improve the oil-displacement mechanism of the replacement medium, develop economical and efficient environment-friendly oil displacement system and promote its application in the field practice. This study provides technical support for efficient development of low-permeability reservoirs.

Review of Remaining Oil Research Methods

Wang Yang, Huang Yanming, Tong Xin, Ge Zhengting, Chen Jun, Wu Di, Ji Shaowen, Xiao Fei

2023, 30(1):  14-21.  DOI: 10.3969/j.issn.1006-6535.2023.01.002

Asbtract ( )   PDF (1194KB) ( )  

References | Related Articles | Metrics

In order to better understand the remaining oil research methods, a comprehensive summary of remaining oil research methods and applications in the world was conducted by means of investigation and research. The result shows that the analysis methods of sedimentary micro-phase, micro structure and reservoir flow unit take the basic geological research as the starting point and are the basis for remaining oil research; the core analysis method, micro-seepage simulation, physical simulation and nuclear magnetic imaging technology are important tools for micro-remaining oil research and describe the characteristics of remaining oil distribution from the micro perspective; the material balance method and numerical simulation technology are important tools for macro-remaining oil research and are also the basic data for oilfield development adjustment; the logging technology, chemical tracer monitoring method, four-dimensional seismic method and other methods are useful supplements to remaining oil research methods; for the dynamic analysis method, the data obtained from multiple disciplines need to be synthesized and applied, debunked, and verified against each other to obtain accurate remaining oil research results. This result provides reference for the study of the remaining oil in the middle and late stages of development.

Geologic Exploration

Method for Predicting the Favorable Site of Overlying Oil and Gas Reservoir Formed by Fault Conduit and Its Application

Xiao Lei

2023, 30(1):  22-28.  DOI: 10.3969/j.issn.1006-6535.2023.01.003

Asbtract ( )   PDF (1787KB) ( )  

References | Related Articles | Metrics

In order to clarify the distribution law of overlying oil and gas reservoirs formed by fault conduit in hydrocarbon-bearing basins, based on the study of the conditions required for the formation of overlying oil and gas reservoirs by fault conduit, a set of prediction methods for the favorable site of overlying oil and gas reservoirs formed by fault conduit were established by determining and overlapping the distribution area of underlying oil and gas reservoirs, the area not sealed by the fault-caprock matching of underlying oil and gas reservoirs, the area sealed by the fault-caprock matching of overlying oil and gas reservoirs and the favorable site for oil-gas migration through faults, and applied to the prediction of the favorable site for the formation of hydrocarbon reservoirs from the fault-conducted Nantun Formation to the Damoguaihe Formation in the Hodomol Area of the Beier Sag in the Hailar Basin. The result shows that the favorable site for the formation of hydrocarbon reservoirs from the fault-conducted Nantun Formation to the Damoguaihe Formation in the Hodomol area of the Beier Sag in the Hailar Basin is mainly located within the 3 local areas of the nucleus of the Hodomol nasal structure, which is conducive to the formation of overlying oil and gas reservoirs from the fault-conducted Nantun Formation to the Damoguaihe Formation in the Hodomol Area of the Beier Sag, which coincides with the current distribution of discovered oil and gas in the Damoguaihe Formation in the Hodomol Area of the Beier Sag, indicating that the method is feasible for predicting favorable sites of overlying oil and gas reservoirs formed by fault conduit. The research method has important guiding significance for the exploration and development of overlying oil and gas reservoirs formed by fault conduit in hydrocarbon-bearing basins.

Study on the Exploration Method of Shale Gas in Permian Gufeng Formation, Xuancheng Area, Lower Yangtze Block

Zhang Xu, Gui Herong, Hong Dajun, Sun Yankun, Liu Hong, Xiao Wanfeng, Chen Kefu, Yang Zhicheng

2023, 30(1):  29-35.  DOI: 10.3969/j.issn.1006-6535.2023.01.004

Asbtract ( )   PDF (2271KB) ( )  

References | Related Articles | Metrics

In view of great difficulties in the exploration of Permian shale gas under complex geological conditions in Xuancheng Area, Lower Yangtze Block, an effective shale gas exploration method under complex geological conditions is explored by applying a joint exploration with high-accuracy gravity prospecting, high-precision magnetic method and complex resistivity method (CR method) based on rock property testing. The study shows that The shale of Gufeng Formation in Xuancheng Area is characterized by "low magnetic intensity, low density, medium low resistivity and high polarization", the carbonaceous siliceous shale characterized by low resistivity and high polarization, and the intrusive rock (granite porphyry) that mainly affects Gufeng Formation characterized by "low magnetic intensity, low density, low resistivity and low polarization". In the shale gas exploration at Gufeng Formation, Weidun Belt, Xuancheng Area, high-accuracy gravity prospecting and high-precision magnetic method are applied to identify the areas with low magnetic intensity and low gravity and to deduce the distribution of rock mass. Then, CR profile is arranged in the area where magmatic rock is not developed, and wells are drilled for verification at the locations with low resistivity (less than 1 000.00 Ω·m) and high polarisation (more than 4.00%). A total of 50.89 m thick carbonaceous siliceous shale and siliceous mudstone of Gufeng Formation are drilled, achieving excellent application effect. This study provides an important guide to the identification of organic-rich shale formations and the selection of shale gas "sweet spot" in Xuancheng Area and even in the area with complex geological conditions in Lower Yangtze Block.

Geological Modeling Method and Its Application Based on Embedded Multi-Scale Fracture Model

Tang Shenglai

2023, 30(1):  36-40.  DOI: 10.3969/j.issn.1006-6535.2023.01.005

Asbtract ( )   PDF (1591KB) ( )  

References | Related Articles | Metrics

Fractured reservoirs are developed with pores, fractures and caves in reservoir bed, and it is difficult to accurately characterize the reservoir. In order to accurately describe the spatial distribution characteristics of fractured reservoirs, the geological and petrophysical models of embedded multi-scale fractured reservoirs of key wells were established according to logging and drilling data and petrophysical test data; a study was made on the multi-medium connectivity and conductivity and the geological modeling technology of embedded fractures, and the model was used to numerically simulate the fractured reservoirs in the lost oil field. The study results show that the geological modeling based on the multi-scale embedded fracture model can be used for detailed description and numerical simulation of large-scale fractures such as structure and fault, as well as small-scale fractures based on the equivalent principle, and the fitting rate of single-well dynamic indicators was more than 90%. The numerical simulation study of Liuhua Oilfield proves that the reservoir will maintain the current fluid recovery rate of each well for continuous development, most of the wells will not experience serious water flooding, and the wells with higher risk are mainly located near the fault on the northeast edge of the work area. This study provides a reference for geological modeling, numerical simulation and development for similar reservoirs.

Study on the Characteristics of Siliceous Rocks and Their Influence on Reservoir Karstification in Longnyusi Area of Central Sichuan

Lin Yi, Han Shaorui, Xia Maolong, Zeng Deming, Jia Song, Liao Mingguang

2023, 30(1):  41-49.  DOI: 10.3969/j.issn.1006-6535.2023.01.006

Asbtract ( )   PDF (6955KB) ( )  

References | Related Articles | Metrics

The siliceous rocks are commonly developed in the upper sub-section of the Fourth Member, Sinian Dengying Formation, Anyue Gasfield in central Sichuan, and their influence on reservoir karstification is still unclear, so it is necessary to conduct a corresponding study. For this reason, based on lithology, logging response characteristics, the cores and slices were described in details through observations, the study of the influence of siliceous rocks on reservoir karstification in the upper sub-section of the Fourth Member, Dengying Formation, in Longnyusi Area of Central Sichuan was carried out using basic characteristics of siliceous rocks, reservoir comparison diagram and siliceous plan, and the results show that The siliceous rocks in the study area are mainly algal laminated siliceous rocks, pure siliceous rocks and dolomitic siliceous rocks; the siliceous bed is divided into 2 sections in the upper sub-section of the Fourth Member, Dengying Formation, and the reservoirs above and below the siliceous bed are in good conditions, and the thickness of the siliceous rocks can be seen on the plane to be thinned to the northeast as well as to the southeast; the siliceous rocks are fractured by the Tongwan movement and suffer from dissolution enlargement, which cannot block the karst fluid infiltration; the fault cutting through the siliceous bed has no effect on the stimulation of the karst reservoirs. Therefore, siliceous rocks have less effect on the reservoir karstification. The research results have laid a foundation for finding favorable areas for reservoir development in the Longnyusi area within the platform.

Hydrocarbon Accumulation Law and Favorable Target Selection in Damiao Sag, Erlian Basin

Qiu Wenbo, Cai Qinqin, Zhang Xuerui, Jiang Shaolong, Guo Long, Yuan Ziqi

2023, 30(1):  50-56.  DOI: 10.3969/j.issn.1006-6535.2023.01.007

Asbtract ( )   PDF (2031KB) ( )  

References | Related Articles | Metrics

In view of poor understanding of the tectonic development pattern and hydrocarbon accumulation law in Damiao Sag, Erlian Basin, the tectonic development pattern, reservoir development mode, and hydrocarbon accumulation law and high yield of Damiao Sag, Erlian Basin were studied based on the sedimentary facies study and logging-seismic joint inversion technology, so as to determine the resource potential and favorable target areas of Damiao Sag, Erlian Basin. The study results show that alluvial fan - fan delta - lake sedimentary system is mainly developed in the early stage of Damiao Sag; the glutenite in the alluvial fan, the fine sandstone in the remote distal bar and the glutenite in the shallow lake are developed with excellent reservoirs, and the semi-deep and deep lake mudstone is developed with good source beds; the favorable hydrocarbon accumulation is mainly distributed around hydrocarbon-rich sags, and Ai′ershan Formation and Member 1 of Tengge′er Formation are selected as the favorable exploration targets in Damiao Sag, Erlian Basin, with an estimated resource of 150.44×10⁴t, one well deployed, and an expected production capacity of 10 t/d. The study results are of great significance for the development of replacement areas of favorable oil and gas resources in Erlian Basin.

Application of Volcanic Rock Reservoir Classification Method to Carboniferous System in Kebai Fault Area 1

Luo Xudong, Deng Shikun, Feng Yun, Tang Bin, Peng Licai, Li Xiang

2023, 30(1):  57-64.  DOI: 10.3969/j.issn.1006-6535.2023.01.008

Asbtract ( )   PDF (1565KB) ( )  

References | Related Articles | Metrics

In view of the great difficulty in classifying Carboniferous volcanic rock reservoirs in Kebai Fault Area 1 and the inconsistent classification standards, eight important parameters affecting the classification of volcanic rock reservoirs in this zone are analyzed according to the drilling, logging, testing and other data. The parameters such as lithology, lithofacies, matrix porosity, fracture porosity, permeability, reservoir space type, lithofacies thickness and volcanic mechanism facies zone are assigned according to the reservoir characteristics of the research area and related reservoir classification data are calculated. Combined with the reservoir classification results of each single well, the classification method and classification standard of Carboniferous volcanic rock reservoirs in the research area are obtained. The study results show that according to the classification indicators of volcanic rock reservoirs, the Carboniferous volcanic rock reservoirs in Area 1 can be divided into three types: Type I (0.6≤RCI<1.0), Type II (0.4≤RCI＜0.6), Type (III 0.0≤RCI<0.4), among which Type I reservoirs are the best, Type II reservoirs are the better and Type III reservoirs are the worst. The research results are applied to the reservoir classification of 16 wells that are not involved in the formulation of the standard, and the accuracy rate reaches 93.8%, indicating that the classification standard is suitable for the research area. The research results have important guiding significance for the classification and prediction of Carboniferous volcanic reservoirs in this zone.

Sedimentary Facies and Favorable Rock Assemblages of Jurassic Da′anzhai Member, Central Sichuan

Huang Dong, Zeng Deming, Wang Xingzhi, Xie Shengyang, Zhang Rui, Zhang Shaomin, Guo Yihao

2023, 30(1):  65-73.  DOI: 10.3969/j.issn.1006-6535.2023.01.009

Asbtract ( )   PDF (3499KB) ( )  

References | Related Articles | Metrics

In view of the imprecise sedimentary facies division, unclear favorable rock assemblage and undefined favorable exploration area of Jurassic Da′anzhai Member in Central Sichuan, a study was conducted on the rock type, sedimentary facies type, sedimentary facies distribution, sedimentary model, rock assemblage and favorable exploration area in the study area by the core description of three fully cored wells and the observation results of six field profiles in combination with thin slice identification, logging interpretation and organic geochemical analysis methods. The study results show that Rock was divided into 10 types. The sedimentary facies was divided into 3 subfacies (shore lake, shallow lake and fairly deep lake) and 10 microfacies (including fairly deep lake mud, organic bank and gravity flow). Gongshanmio-Lianchi-Yingshan line is the sedimentary center developed in a fairly deep lake environment, and three rock assemblage types (C, D and E) were identified. Nanchong-Quxian-Yilong line was circularly developed in a shallow lake environment, and three rock assemblage types (A, B and F) were identified. The study results were applied from conventional tight oil to shale oil exploration. According to the TOC, porosity, permeability, fracturing effect and other evaluation indicators, it was considered that Type A rock assemblage was a favorable combination for tight oil carbonate rock exploration under the matching of fractures and cracks, and Type F was the most favorable combination for shale oil exploration, which was mainly distributed in the shallow lake facies at Sub-member 1 to Sub-member 2a of Da′anzhai Member. The study results are of great significance for shale oil exploration in the future.

Reservoir Engineering

A New Method for Calculating the Theoretical Tectonic CO₂ Storage Volume Based on Material Balance Equation

Cui Chuanzhi, Li Anhui, Wu Zhongwei, Ma Siyuan, Qiu Xiaohua, Liu Min

2023, 30(1):  74-78.  DOI: 10.3969/j.issn.1006-6535.2023.01.010

Asbtract ( )   PDF (1382KB) ( )  

References | Related Articles | Metrics

To further improve the evaluation accuracy of CO₂ storage potential in saline layer, a new method for calculating the theoretical tectonic CO₂ storage volume was proposed based on the material balance equation of CO₂ tectonic storage process and the accurate calculation of underground volume of CO₂ storage. As found in the results, the error of theoretical tectonic CO₂ storage volume calculated by the new method was smaller than that of area method and volume method, which was only about 10%; the new method can predict the theoretical tectonic storage volume under both CO₂ pressurized and pressure-retaining underground storage conditions; both theoretical tectonic CO₂ storage volume and formation pressure showed a trend of increasing with the increase of injection time or injection-production ratio. The new method is of great significance to the study of CO₂ tectonic storage and real-time dynamic control.

Cores Pore Structure Characteristics and Relative Permeability Analysis in Steam Flooding Based on CT Scanning

Li Aifen, Gao Ziheng, Jing Wenlong, Fu Shuaishi

2023, 30(1):  79-86.  DOI: 10.3969/j.issn.1006-6535.2023.01.011

Asbtract ( )   PDF (2664KB) ( )  

References | Related Articles | Metrics

In order to identify the effect of steam flooding on the pore structure characteristics of heavy oil reservoirs in unconsolidated sandstone, in a study case of LDB Oilfield, CT technology is applied to scan the cores in different steam flooding stages, a three-dimensional digital core model is constructed and a pore network model is extracted to obtain the core porosity, absolute permeability, pore structure characteristics and other parameters at different steam flooding stages, as well as working out the relative permeability curve by flow simulation and performing quantitative statistics and analysis. The result shows: as the steam flooding progresses, the pore space of the core becomes larger, leading to increase in average pore radius, average throat radius, porosity and permeability, and enhancing the permeability and improving the pore structure. The study results provide technical support for the design of heavy oil reservoir development with steam flooding.

Laboratory Test of Microbial Chemical Compound Flooding to Enhance Recovery Efficiency of High Condensate Oil Reservoirs

Wen Jing, Xiao Chuanmin, Guo Fei, Yang Can, Ma Jing, Li Xiaofeng, Yi Wenbo

2023, 30(1):  87-92.  DOI: 10.3969/j.issn.1006-6535.2023.01.012

Asbtract ( )   PDF (1847KB) ( )  

References | Related Articles | Metrics

In view of the problems of high condensate oil reservoir, cold damage caused by wax precipitation and low recovery efficiency by water flooding, were the microbial high throughput sequencing analysis and experimental evaluation method for chemical flooding and used the core physical simulation and CT scanning and other means to propose the enhanced high pour-point oil recovery technology through microbial + chemical compound flooding combination and research the microbial-chemical compound flooding formula. The system has the advantages of chemical flooding greatly improving the oil displacement efficiency and microbe reducing the waxy composition of crude oil. Finally, the slug combination of microbial and chemical flooding formula is optimized by physical model experiment. The experimental result shows that: The microbial + chemical compound flooding can improve the oil displacement efficiency by 35.19% than the water flooding, and if compared with the single chemical compound flooding, it can improve the oil displacement efficiency by 7.27%, and the oil increment increases by1.16 t/t. This research provides an effective replacement technology for the mode conversion and enhanced oil recovery in the late development stage of high condensate oil reservoir.

Consistency Test Method for Phase State Test of Formation Oil and Gas at High Temperature

Song Jiabang, Yu Haiyang, Wang Songchen, Liu Jinbo, Hu Jiang, Wang Yang, Zhao Libin

2023, 30(1):  93-99.  DOI: 10.3969/j.issn.1006-6535.2023.01.013

Asbtract ( )   PDF (1742KB) ( )  

References | Related Articles | Metrics

Since the PVT test consistency test method is inapplicable to high-temperature reservoirs, a systematic test method was proposed for the consistency of phase state test results in high-temperature hydrocarbon reservoirs, in which the equilibrium constant calculation method at high temperature was used to modify the material balance method, Hoffman method and equilibrium constant method, and to test the consistency between the component data of the phase state test and the constant-volume depletion test data with such two methods and the component verification method, so as to judge the test results more accurately. A consistency test was conducted between the component data and the constant-volume depletion test data of two fluid samples taken from high-temperature hydrocarbon reservoir, namely Condensate Gas Sample A from Well Bozi 104 and Volatile Oil Sample B from Well Bozi 7 in Tarim Oilfield. The results verified the validity and reliability of the method in this paper. This study is important to clarify the phase characteristics of formation oil and gas, especially volatile oil and condensate gas at high temperature.

Experimental Study on In-situ Emulsification Enhanced Oil Recovery of Glutenite Oil Reservoir

Luo Qiang, Li Ming, Li Kai, Ning Meng, He Wei, Du Daijun

2023, 30(1):  100-106.  DOI: 10.3969/j.issn.1006-6535.2023.01.014

Asbtract ( )   PDF (1968KB) ( )  

References | Related Articles | Metrics

In view of the strong heterogeneity of the glutenite oil reservoir, an in situ emulsification enhanced oil recovery technology was proposed. The emulsification performance, interfacial tension reduction performance and oil displacement performance of the new W/O emulsification system (DMS) were studied, and at the same time the results were compared with the polymer/surfactant binary system used in the oil field. The experimental result shows that under different water contents, DMS can emulsify with crude oil to form W/O emulsion. With the increase of water content, the viscosity of emulsion increases. When the water content is 70%, the viscosity reaches the maximum value, which is 9 times of the viscosity of crude oil, much higher than the viscosity of binary system, and the fluidity control ability is stronger. DMS can be directionally adsorbed on the oil-water interface and reduce the oil-water interfacial tension to 0.12mN/m. Under the influence of DMS, oil and water are emulsified in situ to form W/O emulsion with a particle size of 0.5-6.0μm. In the glutenite core, DMS flooding and subsequent water flooding can improve the recovery by 18.6%. Under the permeability max-min ratio of 10, dual flooding and subsequent water flooding can improve the recovery by 24.0%, while DMS flooding and subsequent water flooding can improve the recovery by 35.3%, showing better fluidity control and the ability to improve the water absorption profile. The research result will provide theoretical support for enhanced oil recovery of glutenite oil reservoir

Study and Application of Polymer Flooding for Enhanced Oil Recovery in Shallow Ordinary Heavy Oil Reservoirs

Wang Fengjiao, Xu He, Liu Yikun, Wang Yongping, Wu Chenyu, Li Gaiyu

2023, 30(1):  107-113.  DOI: 10.3969/j.issn.1006-6535.2023.01.015

Asbtract ( )   PDF (2193KB) ( )  

References | Related Articles | Metrics

Block J-XC is a common heavy oil reservoir with high porosity and permeability, shallow reservoir burial, and thin thickness. Due to high viscous resistance in the water flooding process, small effect range of water flooding, low reservoir productivity and low recovery rate by water flooding, it is necessary to change the development method and employ polymer flooding method to enhance the oil recovery. On the basis of polymer injectivity evaluation, the injection parameters and injection-production relationship of polymer flooding were optimized by core flow test and numerical simulation, including the mass concentration of polymer injection, injection volume, injection rate, well pattern, well spacing, injection-production ratio, so as to obtain the best injection parameters and injection-production relationship. The result shows that the injectivity and high utilization efficiency of the polymer were actualized under the conditions of 2 100×10⁴ relative molecular mass of the polymer, 1 500 mg/L injection mass concentration and 0.400 times of pore volume; the optimal reservoir engineering parameters were a five-spot pattern, a reasonable injection-production well spacing of 150 m, an injection rate of 0.070 times the pore volume per year, and an injection ratio of 1.1 to 1.2 for different thicknesses of oil reservoirs according to their optimal single-well daily injection volumes. The pilot test in the field proves the significant effect of increasing oil and decreasing water cut in the target well cluster. As of June 2021, the cumulative injection rate of polymer is 0.228 times the pore volume, and the cumulative oil increase is 5.06×10⁴t, the recovery factor is enhanced by 6.75 percentage points and the water cut is decreased by 15.8 percentage points. There is much for reference of the results to the optimization of polymer flooding parameters and reservoir engineering design in shallow ordinary heavy oil reservoirs.

Study on Enhancing the Oil Recovery of Tight Oil Reservoirs by Surfactant Combined with Low-Salinity Water Flooding

Li Ting, Xie An, Ni Zhen, Liu Yongping

2023, 30(1):  114-119.  DOI: 10.3969/j.issn.1006-6535.2023.01.016

Asbtract ( )   PDF (1517KB) ( )  

References | Related Articles | Metrics

To explore the mechanism of enhancing the oil recovery of tight oil reservoirs by surfactant combined with low-salinity water flooding, in a study case of a tight sandstone reservoir in Xinjiang Oilfield, the effects of low-salinity water flooding, surfactant flooding and their combination on the recovery efficiency at different injection rates and solvent ratios are studied with self-made test equipment. The result shows: The surfactant combined with low-salinity water flooding can effectively play the synergistic advantages to improve the recovery efficiency of tight oil reservoirs. When the injection rate is too low, the surfactant can effectively modify the pore throat interface, but the energy of water flooding is insufficient. When the injection rate is too high, it is easy to induce the coning of oil-water interface, and the effect of surfactant on modifying the pore throat interface is limited, leading to oil displacement efficiency increasing first and then decreasing with the increase of injection rate. At the injection rate of 0.3 mL/min, the highest oil displacement efficiency of 89.79% is achieved with a 7∶3 mass ratio of low-salinity water (0.1% NaCl mass fraction) to sodium dodecyl-benzene sulfonate anionic surfactant (0.4% mass fraction), which is at least 29.83% higher than that of single-fluid flooding. The field application shows that the surfactant combined with low-salinity water flooding can effectively enhance oil recovery and increase monthly production by about 47% in tight reservoirs where the production is severely depleted per well. The study results can be referred for efficient development of similar tight oil reservoirs.

Evaluation and Study of Injection Performance of Binary System of Anti-Salt Polymer and Surfactant

Zhou Quan, Zhang Shidong, Zhou Wanfu

2023, 30(1):  120-125.  DOI: 10.3969/j.issn.1006-6535.2023.01.017

Asbtract ( )   PDF (2242KB) ( )  

References | Related Articles | Metrics

To address the problems of poor physical properties, high heterogeneity and high salinity of the target reservoir in M Oilfield, the temperature and salt resistance of a new dialkyl glycerol ether-derived surfactant (diGE-EO) was studied in this paper, the injection performance was compared with Hall curve between the polymer and the polymer-surfactant binary salt resistance system, and the feasibility of polymer-surfactant binary displacement system to enhance oil recovery in the target reservoir of Minsk Oilfield was analyzed. The study results show that The diGE-EO can maintain high salt resistance at concentrations higher than 3 500 mg/L, and can reduce the oil-water interfacial tension to 5.73×10^-3 mN/m after being placed at 85 ℃ for more than 45 days, which is in the ultra-low interfacial tension range, meeting the requirements for the development of highly mineralized reservoirs. The injection performance of polymer-surfactant binary anti-salt system is also analyzed. The results show that when the mass concentration of polymer solution is up to 1 500 mg/L and the core permeability is lower than 200 mD, and it becomes more difficult to inject polymer alone; in the presence of surfactant, the injection performance is significantly improved. The test results provide a laboratory test basis for the scheme design and field implementation of binary composite flooding project in M oilfield.

Prediction Method and Application of Injection-Production Capacity of Gas Storage Converted from Deep Carbonate Gas Reservoir

Wang Rong, Li Longxin, Liu Xiaoxu, Luo Yu, Zhang Na

2023, 30(1):  126-133.  DOI: 10.3969/j.issn.1006-6535.2023.01.018

Asbtract ( )   PDF (1981KB) ( )  

References | Related Articles | Metrics

The gas storages converted from deep carbonate gas reservoirs are characterized by large high and low pressure variations, stress sensitivity, and strong heterogereity. Using conventional methods to calculate its injection-production capacity will lead to large errors in production capacity. In response to the above problems, stress sensitivity is considered. The binomial productivity equation was revised in view of the influence of stress sensitivity and gas physical property changes, and on this basis, a calculation method of injection-production capacity suitable for the gas storage converted from deep carbonate gas reservoirs was established. Example calculations are carried out in conjunction with the Shapingchang Carboniferous Gas Reservoir in the Sichuan Basin, the influencing factors are analyzed, and the results show that: for type Ⅰ and Ⅱ pore-fracture collocation model reservoirs, the reasonable gas production rate of gas wells is controlled by outflow dynamics under low pressure and limited by erosion flow under high pressure, while the reasonable gas injection rate is controlled by outflow dynamics under high pressure and limited by erosion flow under low pressure; for type Ⅲ pore-fracture collocation model reservoirs, the reasonable gas injection and production rates of gas wells are mainly controlled by the outflow dynamics. The influence of stress sensitivity on the maximum gas injection rate of the gas well is 0.81%~9.69%, and the influence of the change of gas physical parameters is 5.15%~35.29%; under the existing wellbore structure conditions, when the gas injection rate is 55×10⁴ to 70×10⁴ m³/d, the frictional pressure loss can reaches to 10 MPa; when the inner diameter of the tubing increases from 62.0 mm to 112.0 mm, the maximum gas injection volume increases to 2.6 times. The research results can provide technical support for the calculation of the injection-production capacity of deep carbonate gas storages, and have guiding significance for the construction and operation of such gas storages.

Application of Numerical Simulation in Low Permeability Reservoirs Considering Viscosity

Li Hao, Feng Yufu

2023, 30(1):  134-138.  DOI: 10.3969/j.issn.1006-6535.2023.01.019

Asbtract ( )   PDF (1770KB) ( )  

References | Related Articles | Metrics

To address the problem of low prediction accuracy of remaining oil in low-permeability reservoirs, taking Chang 7 tight reservoir in Yanchang Formation in the Ordos Basin as an example, the reservoir numerical simulation theory is applied, and the viscous motion equation is introduced to describe the direction and magnitude of pressure propagation in low permeability reservoirs. The results were applied to the study of remaining oil, and the potential tapping wells were optimally deployed in the remaining oil-enriched areas. The research result shows: With the extension of production time, the recovery factor will be underestimated without considering the viscosity, and the tracer tracing situation confirms the influence of viscosity on production; the numerical simulation results of low-permeability reservoirs considering viscosity have a good production history fit, with a single well fit rate of 89%; the numerical simulation results show that the remaining oil-enriched area is mainly located on both sides of the waterline, which is the area difficult to sweep between wells or the area with imperfect injection and production. The initial daily oil production of the potential tapping wells deployed in the remaining oil-enriched area is 12.8 t/d, which is nearly 4 times higher than that of the adjacent wells. The potential tapping wells deployed in the region are expected to increase the recoverable reserves by 9.27×10³t. The research results have reference significance for the potential tapping and later adjustment of remaining oil in similar reservoirs.

Fractal Model of Micro-Nano Pore Seepage in Shale Considering the Multi-Layer Adsorption Induced Flow

Hu Shiwang, Zhang Sai, Wang Zhenyi

2023, 30(1):  139-146.  DOI: 10.3969/j.issn.1006-6535.2023.01.020

Asbtract ( )   PDF (1585KB) ( )  

References | Related Articles | Metrics

In view of the great difficulty of simulating the shale gas seepage process, fractal theory is applied to describe the microstructure of shale gas reservoir. Based on the multi-layer adsorption phenomenon of adsorption layer, the pressure sensitive effect and the real gas effect are taken into account, the mass flow expression of micro-nano shale gas is derived, and the micro-nano fractal apparent permeability model of shale gas is also established. The accuracy of the model is verified by comparing the numerical simulation with the actual production data of Well A1 in Zhaotong shale gas field. The result shows that the number of adsorbed gas layers on the pore surface is more sensitive to pressure change, but less sensitive to temperature change. Due to the pressure sensitive effect, as the diffusion resistance of shale gas increases, the apparent permeability decreases. With the increase of gas compression factor, the thickness of the adsorption layer increases and the section area ratio of the adsorption zone increases. Moreover, the pressure sensitive effect of the shale pore decreases the pore diameter, and the induced flow of the adsorbed gas decreases first and then tends to be gentle, thus reducing the overall apparent permeability of shale gas. The research results can provide part of the theoretical basis for the numerical simulation of shale gas and improve the recovery efficiency of shale gas fracturing by controlling the main control elements that affect the fractal permeability of shale gas.

Characteristics of Remaining Oil Distribution in Conglomerate Reservoirs after Water Flooding and Technical Countermeasures

Ren Mengyao, Shi Qiang, Xin Huazhi, Liu Zhiqiang, Zhou Zhiliang

2023, 30(1):  147-153.  DOI: 10.3969/j.issn.1006-6535.2023.01.021

Asbtract ( )   PDF (3020KB) ( )  

References | Related Articles | Metrics

In response to the problems of low water flooding control degree in conglomerate reservoirs and extremely imperfect well networks in Wellblock Bai 21, Baikouquan Oilfield in the Junggar Basin, the reservoir engineering method and reservoir geology are used as guidance to conduct fine research on reservoir architecture by applying dynamic and static data, analyze reservoir structure, sedimentation, reservoir in-homogeneous characteristics and oil and water distribution law, and improve the injection-production well patterns. The study results show that The idea of water injection optimization and adjustment “different strategies for different layer systems, adjustment and control by zone, classification by single well, and optimization of method” proposed in the article is very effective for the Baikouquan Oilfield. By carrying out the study on the distribution characteristics of the remaining oil and the reservoir injection and production well patterns in the Triassic system of Wellblock Bai 21, 56 dominant seepage channels were identified through comprehensive analysis by applying flowline simulation technology, and the submitted producing petroleum geological reserves were 975.00×10⁴t, and the accumulated oil increase was 16.60×10⁴t. This study has a reference effect for the improvement of injection and production well patterns and efficient tapping of similar reservoirs.

Drilling & Production Engineering

Evolution Characteristics of Shale Pore Structure Under Cyclic Impact Load

Wang Yu, Zhai Cheng, Shao Hao, Tang Wei, Shi Kelong

2023, 30(1):  154-160.  DOI: 10.3969/j.issn.1006-6535.2023.01.022

Asbtract ( )   PDF (2818KB) ( )  

References | Related Articles | Metrics

To study the pore structure evolution of shale gas reservoir under cyclic impact load, the shale of Wufeng Formation in Changning County, Sichuan Province, was taken as the study case, and the kinetic response characteristics of shale under cyclic impact load at low, medium and high velocity were worked out based on the Hopkinson bar experimental system and micron CT system, and the shale pore structure before and after impact was analyzed. The study shows that The dynamic impact stress to strain curves show that the dynamic elastic modulus modulus of rock samples under low-velocity cyclic impact increased with the increase of cyclic impact count, and the load-bearing capacity increased gradually; the rock samples were compressed first and then damaged under medium velocity and high velocity cyclic impact, with the increase of cyclic impact load, the surface area, volume and fractal dimension of shale connected fractures were increased and the absolute permeability increased, which indicates that increasing the cyclic impact load can form a complex pore network in the rock samples and enhance the permeability; medium velocity and high velocity cyclic impact could expand and penetrate the pores inside the rock samples, and the porosity of rock samples under medium velocity cyclic impact was doubled compared with the original rock samples, and the spatial dispersion of pore distribution was enhanced. This study can theoretically support the study related to multistage pulse combustion-explosion fracturing of shale gas reservoirs.

Study of Macroscopic Aggregation Mechanism of Oil Droplets and Microscopic Interactions Between Oil Film Molecules

Huang Bin, Nan Xiaohan, Wang Yizhu, Fu Cheng, Zhu Yueming, Zhang Lu, Guo Wei, Wang Siqi

2023, 30(1):  161-168.  DOI: 10.3969/j.issn.1006-6535.2023.01.023

Asbtract ( )   PDF (4031KB) ( )  

References | Related Articles | Metrics

In order to study the microscopic interactions between oil droplets in the process of oil droplet coalescence, the coalescence behavior of emulsified oil droplets in oil well recovery fluid was studied by finite element simulation method, in combination with the emulsion stability experiments and molecular dynamics simulation technology, and the influencing factors of oil droplet coalescence were analyzed. The study results show that the fluid flow rate is relatively high at the location of the liquid film during the coalescence of the 2 oil droplets, and reaches stability after the coalescence is completed. There is no obvious correspondence between the size of oil droplets and the coalescence time, and when the radii of 2 oil droplets are different, the larger droplets move less; at the initial moment, there is an obvious boundary between oil film and water phase; the longer the carbon chain, the more stable the emulsion; under the condition of the same number of carbon atoms, the influence of crude oil components on the stability of emulsion is from small to large for saturated hydrocarbons, carbon-carbon double bonds, carbon-carbon triple bonds, and cycloalkanes; the increase of asphaltene content is the main reason for the increase of emulsification capacity and emulsion stability of emulsion system. This study is of great significance to improve the oil-water separation efficiency of crude oil and reduce the cost of crude oil storage and transportation.

Research and Application of the Nano-injection Enhancing Technology in Tight Reservoirs

Jin Yonghui, Wang Zhifu, Sun Qingming, Li Yuanliu, Wang Bo, Chen Yizhe

2023, 30(1):  169-174.  DOI: 10.3969/j.issn.1006-6535.2023.01.024

Asbtract ( )   PDF (1207KB) ( )  

References | Related Articles | Metrics

In response to the problem of rapid rise of water injection pressure in the Weijialou tight reservoir, the nano-injection enhancing technology was introduced, and the principle and influencing factors of the nano-injection enhancing technology were analyzed through slim-tubes and core flooding experiment devices. The result shows that the nano-injection enhancer can change the wettability of rocks, which can change hydrophilic reservoir into neutral or oleophilic reservoir and reduce the thickness of water film formed on the surface of pore throat of hydrophilic reservoir; the nano-injection enhancer can also adsorb on the surface of pore throat to strip the hydration film on the surface of pore throat, so as to increase the effective radius of pore throat and reduce the fluid resistance, thus increasing the water absorption capacity of the formation. The slim-tube displacement experiments show that the nano-injection enhancing solution with a mass fraction of 0.010% has a better pressure reduction effect for slim-tubes with a diameter of 50-100 μm, with a maximum pressure reduction rate of 30.1%; the natural core flooding experiments show that the nano-injection enhancing solution has a better pressure reduction effect with a pressure reduction rate of 40.0% when the injection volume of the nano-injection enhancing solution is 1 times the pore volume and the adsorption time is greater than 36 h. The results of the field test of pressure reduction and injection enhancing in Weijialou Oilfield show that the nano-injection enhancer can reduce the injection pressure of water injection wells by 2.4MPa. The results of this study have good application value for high-pressure under-injection well governance in tight reservoirs;Weijialou oilfield