Table of Content

25 August 2022, Volume 29 Issue 4

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Summary

Progress in Leakage Risk Study of CO₂ Geosequestration System

Bai Mingxing, Zhang Zhichao, Bai Huaming, Du Siyu

2022, 29(4):  1-11.  DOI: 10.3969/j.issn.1006-6535.2022.04.001

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CO₂ geosequestration technology is an important method to mitigate the greenhouse effect, and the evaluation of leakage risk in geosequestration system is a prerequisite to ensure the safe and efficient sequestration of CO₂. To address the risk of CO₂ leakage, the influence of wellbore and caprock factors on the risk of CO₂ leakage in CO₂ geosequestration system was systematically discussed, including the quality of cementing, CO₂ corrosion and damage to the wellbore assembly by alternating stress, as well as the influence of caprock-formation ratio, caprock thickness and lithology on low-speed seepage and high-speed leakage of caprock. Finally, the wellbore leakage risk evaluation method, the caprock leakage risk evaluation method and the CO₂ sequestration system leakage risk evaluation method based on the combined action of the above influencing factors were discussed, and the advantages and disadvantages of different evaluation methods were pointed out. The study provides theoretical support for site selection, formation selection and leakage risk evaluation in CO₂ geosequestration works.

Logging Evaluation Technology and Further Development of Tight Reservoirs

Liu Meicheng

2022, 29(4):  12-20.  DOI: 10.3969/j.issn.1006-6535.2022.04.002

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Tight oil and gas fields play a very important role in the oil and gas fields in China, and the oil and gas stored in tight oil reservoirs account for more than 70% of the proven reserves in China. Oil and gas fields in tight oil reservoirs are distributed widely and continuously, making exploration extremely difficult. Tight reservoir logging evaluation is a core technology in reserves evaluation, well deployment and other exploration work. The future development trend is to integrate big data methods with neural network methods to comprehensively evaluate logging evaluation related parameters such as fluid type and pore structure of tight reservoirs. Most of the existing tight reservoir logging methods and tools are based on conventional methods and means such as neutron, acoustic wave and density. There is a lack of new technologies and innovations such as imaging logging, nuclear magnetic logging and logging while drilling, and there is still no systematic and effective tight reservoir logging evaluation technologies. Therefore, on the basis of extensive literature investigations at home and abroad, this paper systematically summarized the geological characteristics of tight oil reservoir and expounded the differences between conventional logging evaluation techniques (such as neutron, acoustic wave and density) and new technologies and methods (such as imaging logging, nuclear magnetic logging and logging while drilling) in the evaluation of tight oil reservoirs to develop a set of systematic and standardized methods for tight reservoir logging evaluation. Lithological modelling and NMR technology should be deeply developed for tight oil reservoirs so as to effectively improve the logging evaluation technology and enhance the accuracy and reliability of reservoir prediction and fluid detection. The study results have certain reference values to the logging evaluation of tight reservoirs at home and abroad.

Geologic Exploration

Diagenetic Evolution of Deep K₁g₃ Sandstone and Distribution of High-quality Reservoirs in Jiudong Oilfield

Tang Haizhong, Yang Nan, Zhou Xiaofeng, Feng Wei, Li Tao, Lei Fuping, Zhao Wei, Hu Dandan

2022, 29(4):  21-29.  DOI: 10.3969/j.issn.1006-6535.2022.04.003

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In view of the unclear distribution pattern of in deep high-quality K₁g₃ sandstone reservoirs in Jiudong Oilfield, Jiuquan Basin, the diagenetic characteristics, diagenetic evolution, diagenetic facies and high-quality reservoir distribution of sandstone were studied according to casting slice, scanning electron microscope, physical properties and other data. The results showed that the deep K₁g₃ sandstone in Jiudong Oilfield had three types of diagenetic characteristics, and the sandstone with Type Ⅱ and Ⅲ diagenetic characteristics was developed from Type Ⅰ iron-bearing dolomite cemented tight sandstone under the differential action of acidic dissolution fluid. There were three stages of acid dissolution fluid. The fluid was atmospheric freshwater in the first two stages, and was organic acid fluid in the third stage. The atmospheric freshwater then became a acidic fluid that contributed the most to sandstone dissolution. K₁g₃ sandstone could be divided into 4 types of diagenetic facies and 2 diagenetic facies belts. Type B diagenetic facies were high-quality reservoirs with high porosity and permeability, Type D diagenetic facies were reservoirs with medium porosity and low permeability, and Types A and C diagenetic facies were ankerite-bearing cemented tight and heterogeneous reservoirs. The main oil-producing area to the west of Chang2 Fault was a Type B diagenetic facies band, the expanded-margin area to the east was a Type D diagenetic facies band, and Types A and C diagenetic facies were not developed in general. The study results are of providing important reasons for the development plan adjustment and expanded-margin exploration and deployment of Jiudong Oilfield.

Method for Determining Formation Period of Associated Traps of Oil Source Faults and Its Application

Zhu Huanlai, Chen Yan, Wang Weixue, Fu Guang, Gong Jiangping

2022, 29(4):  30-37.  DOI: 10.3969/j.issn.1006-6535.2022.04.004

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In order to study the distribution law of oil and gas near oil source faults in petroliferous basins, based on the study of formation mechanism and period of associated traps of oil source faults, the initial formation period of associated traps of oil source faults is determined by the fracture initiation period and segment growth connection period reflected by the fault offset-displacement curves of oil source faults in different geological periods. The formation period of lateral sealing of oil source fault is determined by the relationship between displacement pressure of oil source fault rock and displacement pressure of oil and gas migration disk reservoir rock with time. A set of methods for determining the formation period of associated traps of oil source fault is established by superimposing the two methods, and it is applied to the determination of the formation period of associated traps of Dazhangtuo fault in the Es₁^x formation in Qikou sag, Bohai Bay Basin. The results show that the associated trap formation period of Dazhangtuo fault in Es₁^x formation is 2.35 Ma, although it is later than the period when the source rocks of the Es₃ formation discharge a large amount of oil and gas, but it can still capture a large amount of oil and gas discharged from the source rocks of the Es₃ formation, which is more conducive to the accumulation of oil and gas discharged from the underlying source rocks of the Es₃ formation in Es₁^x formation near Dazhangtuo fault. It is consistent with the oil and gas distribution found in the Es₁^x formation near Dazhangtuo Fault, which indicates that this method is feasible to determine the formation period of associated traps of oil source faults.

Comprehensive Determination of Lateral Migration Routes and Exploration of Migration Patterns of Hydrocarbons in Nantun Formation, SW Beier Sag, Hailar Basin

Sun Tongwen, Wang Fang, Wang Yougong, Li Junhui, Yao Shihua, Li Bingni, Cheng Yina, Liu Minhua

2022, 29(4):  38-46.  DOI: 10.3969/j.issn.1006-6535.2022.04.005

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SW Beier Sag is currently a key exploration block with high oil reserves in Hailar Basin. In order to identify the influence of hydrocarbon migration on hydrocarbon accumulation, a "four-in-one” comprehensive determination method of hydrocarbon migration path, which was based on hydrocarbon source analysis, with hydrocarbon distribution characteristics as an indicator, migration numerical simulation as a constraint and geochemical tracing as a supporting evidence, was adopted to study the hydrocarbon migration paths and patterns of Nantun Formation in the study area. The results indicated that there were three hydrocarbon migration paths in Nantun Formation. One path was to migrate laterally from NW Beier Sub-sag to West Beier Slope along its short axis; the second path was to migrate from SW Beier Sub-sag to Huhenuoren Tectonic Belt along its short axis; and the third path was to accumulate hydrocarbon from NW and SW Beier Sub-sags to Huhenuoren Tectonic Belt and migrate to the southwest along the strike of tectonic ridge and fault. On the basis of the identification of migration paths, three types of lateral hydrocarbon migration patterns were summarized, including the migration along the strike of tectonic ridge and fault, the "stepped" migration along synclinal fault and the "toothbrush-like” migration along reverse fault. There were significant differences in the hydrocarbon accumulation sites and reservoir types controlled by the various migration patterns. The results of the study are of some significance for the next selection of favorable zones in the study area and for oil and gas exploration in similar areas.

Sedimentary Characteristics of Paleogene Shallow Braided River Delta in Chunguang Prospect Area, Junggar Basin

Fan Xiaoyi

2022, 29(4):  47-54.  DOI: 10.3969/j.issn.1006-6535.2022.04.006

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Chunguang Prospect Area is located in the northwestern margin of Junggar Basin, with major breakthroughs made in Paleogene exploration in recent years, demonstrating great exploration potential. However, the Paleogene strata are severely denuded, with low well control intensity and unclear sedimentary system and sedimentary characteristics. To this end, core, logging, seismic, analytical and test data were integrated to quantitatively recover the Paleosedimentary environment, clarify the sedimentary characteristics and sedimentary evolution process, and establish the sedimentary model. As found in the study, the Paleogene strata in Chunguang Prospect Area, Junggar Basin were gentle in topography, with shallow water bodies and a dry-hot climate, conducive to the development of shallow water deltas; the sediment grain size was relatively coarse, and deposits were developed in front of shallow braided river delta, further divided into submerged distributary channels, beach dams and distant sand dams, and locally developed estuary dams; the sand bodies were stacked in various forms, the multi-phase migrating stacked sand bodies were favorable oil and gas migration channels in the longitudinal direction, and shallow lacustrine mudstone at the top was favorable for blocking, which was prone to the formation of lithological and fault-lithological reservoirs, expressing profitable exploration prospect. The study provides guidance for the fine exploration and development of Chunguang Prospect Area.

Hydrocarbon Transmission System Characteristics of Buried Hills in West Sag, Liaohe of Depression

Ju Juncheng

2022, 29(4):  55-61.  DOI: 10.3969/j.issn.1006-6535.2022.04.007

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To address the problems of unidentified characteristics of the hydrocarbon transmission system and unclear direction of on-scale reserve stimulation and exploration of hydrocarbon transmission system in Buried Hills, West Sag, Laiohe Depression, the buried hill in West Sag were classified as intra-source, source-edge and extra-source types by the analysis method of tectonic characteristics and evolutionary history, the studies on typical buried hill reservoirs, and the contact relationship between buried hills and mature source rocks, and hydrocarbon transmission model of different types of buried hills was established. The study results showed that, the intra-source buried hills in West Sag were developed with complex hydrocarbon transmission conditions, such as fractured reservoir, fault and nonconformity, and the transmission system was the most favorable, with weathered crust and internal reservoirs developed; source-edge buried hills were laterally developed with fault plane or unconformity as main transmission channel; the hydrocarbon content and amplitude of the buried hill were controlled by the size of oil supply window and the development degree of buried hill reservoir; in extra-source buried hills, source-connected fault served as hydrocarbon migration channel while the unconformity served as the horizontal migration channel, and weathered-crust buried hill reservoir was mainly developed. The results of the study are of great significance to the next exploration trend and the selection of favorable targets in the buried hills in West Sag.

Genesis of Calcite Veins in 8# Coal Bed of Benxi Formation on Eastern Margin of Ordos Basin

Wang Chengwang, Xu Fengyin, Zhen Huaibin, Chen Gaojie, Ning Bo, Cao Zheng, Chen Cen

2022, 29(4):  62-68.  DOI: 10.3969/j.issn.1006-6535.2022.04.008

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In view of the unclear genesis of calcite veins in 8# Coal Bed of Benxi Formation on Eastern Margin of Ordos Basin, the calcite vein development stages were analyzed to determine the source and formation time of vein-forming fluids by micro petrography, isotope geochemistry, fluid inclusion and other methods. The study results indicated that calcite veins (C1 and C2) in Stage 2 were developed in 8# coalbed in the study area, the diagenetic fluids of C1 calcite veins were mainly stratigraphic brine and biogas-rich organic fluids from surrounding rock and parent rock, the diagenetic fluids of C2 calcite veins were mainly liquid hydrocarbon fluids formed by the decarboxylation of organic matter, and meanwhile the formation of C1 and C2 calcite veins was affected by deep hydrothermal fluid formed by Early Cretaceous tectonic thermal events. Combined with the analysis of the hydrocarbon formation and burial history in the study area, it was clear that C1 calcite veins were formed from Late Triassic to Early Jurassic and C2 veins were formed from Late Jurassic to Early Cretaceous. Production of 8# coalbed in the study area, the calcite vein development area had a high degree of CBM enrichment, indicating bright prospects for exploration and development. The study results provide an important reference for the exploration of CBM-rich areas.

Early Cretaceous Stratigraphic Evolution and Exploration Potential of Luxi Sag, Kailu Basin

Liang Zhiguo, Ye Qing, Zhang Dan, Cheng Junsheng, Lyu Dehong, Ni Youli

2022, 29(4):  69-75.  DOI: 10.3969/j.issn.1006-6535.2022.04.009

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Luxi Sag, Kailu Basin has experienced multiple periods of tectonic movements and is tectonically complex and diverse. In view of the unclear pattern of tectonic evolution in this area, the early Cretaceous fault system, tectonic evolution process and hydrocarbon accumulation pattern of Luxi Sag were clarified with tectonic analysis, stratigraphic stratigraphy and other research methods, seismic profile analysis and coherence slicing technology. The study results showed that, since the Early Cretaceous, the tectonic styles of Luxi Sag mainly included half-graben structure, rollover anticline and fault block. The tectonic evolution was divided into four periods according to the formation time of tectonic style, including the initial rifting period (the sedimentation stage of lower Jiufotang Member), the subsidence and depression period (the sedimentation stage of upper Jiufotang Member), the stable subsidence period (the sedimentation period of Shahai Formation), and the backward shrinkage period (the sedimentation period of Fuxin Formation). As indicated by the results of the study, the fault-block traps formed in the early stage and the compression-shear tectonic movement in the late stage were the main controlling factors for the hydrocarbon accumulation in tectonic traps. Periodic tectonic movements are favorable for oil and gas migration and the formation of large-scale structural oil and gas reservoirs. The multi-stage fan developed in the subsidence and depression period provided reservoir space for hydrocarbon accumulation, and the multi-stage tectonic movement was conducive to oil-gas migration and the formation of large tectonic oil-gas pools. The results of the study provide a basis and guidance for determining the favorable exploration targets for East Slope, Luxi Sag.

Application of Zero-Incidence-Angle Seismic Data to Thin Reservoir Prediction in HX Area

Wu Zeyun

2022, 29(4):  76-83.  DOI: 10.3969/j.issn.1006-6535.2022.04.010

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The clasolite reservoirs in the Upper Sub-member of Third Member of Shahejie Formation in HX Area are favorable reservoirs, but it is difficult to effectively identify them with conventional superimposed seismic data under the shielding effect of igneous rocks, which seriously restricts the exploration process in this area. To address this problem, wedge model was used to verify the advantages of zero-incidence angle seismic data in thin reservoir prediction. Based on the newly acquired seismic data on "two widths and one height" in HX Area, a procedure was developed for extraction and application of zero-incident-angle seismic data. According to log curve preprocessing, shear wave velocity prediction and pre-superimposing CRP gather optimization and analysis, the zero-incidence seismic data was extracted to predict for the thin sand shale reservoir in Upper Sub-member of Third Member of Shahejie Formation. The study results proved that the zero-incidence-angle seismic data overcame the inherent defects of the superimposing results, thus obtaining the information on vertical reflection and fidelity of the stratigraphic interface, achieving a higher profile resolution, a better well-seismic coincidence and a more accurate reservoir prediction. The capability to characterize thin reservoirs was particularly outstanding. According to the results of the reservoir prediction, the predicted favorable reservoir was drilled in Well H34 located in HX Area, with high production obtained in oil production test, and more than 10 million tones of new increased oil geological reserves. The study results provide support for subsequent well deployment and reserves reporting in this area.

Reservoir Engineering

Study on Preparation of Nanoparticles from Produced Water of Heavy Oil and Its Foam Flooding

Tang Xiaodong, Ling Sihao, Xiang Chengxin, Li Jingjing

2022, 29(4):  84-89.  DOI: 10.3969/j.issn.1006-6535.2022.04.011

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On account of intractable treatment of produced fluid in oilfield and high cost of nanoparticle preparation, rhombic-spherical mixed calcium carbonate nanoparticles were synthesized from produced fluid of Lukeqin heavy oil. Foam stability test and core displacement test were conducted to study the foam stabilization performance of calcium carbonate nanoparticles and the oil displacement effect of the foam system. The results showed that the synthesized calcium carbonate nanoparticles effectively enhanced the foam stability; when the mass fraction of nanoparticles was 0.2%, the salinity of the system was 5 000 mg/L and the temperature was 80 ℃, the foaming volume of nanoparticles was 530 mL, and the foam drainage half-life was 528 s; the foam system had excellent salt and temperature tolerance and adsorption resistance; the water flooding in the reservoirs (water content up to 80%) was converted to foam flooding, and the nanoparticle foam had a stable flooding pressure difference of about 3 MPa, and the recovery rate was increased from 39.84% to 80.16%. Calcium carbonate nanoparticles were stably synthesized by using oilfield produced fluid, which can be used as foam stabilizer to improve foam stability, and can be used in field flooding test to improve foam flooding effect.

Sweep Characteristics of CO₂ Miscible Flooding with Injection-Recovery Coupling in Low Permeability Reservoirs and Quantitative Classification of Gas Channeling Stages

Cui Chuanzhi, Su Xinkun, Yao Tongyu, Zhang Chuanbao, Wu Zhongwei, Zheng Wenkuan, Zhang Yinghua, Li Hongbo

2022, 29(4):  90-95.  DOI: 10.3969/j.issn.1006-6535.2022.04.012

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As the sweeping characteristics of CO₂ miscible flooding with injection-production coupling are not clearly understood and the gas channeling stage cannot be quantitatively identified, numerical simulation was applied to analyze the sweeping characteristics of CO₂ miscible flooding with injection-production coupling and determine the characterization indicators and classification standard of the gas channeling degree. The results showed that, compared with CO₂ continuous gas flooding, the development with injection-production coupling expanded the sweeping range of the gas flooding, delayed the time of gas channeling and improved the final recovery percent of the reservoir through pressurization, energy storage, pressure release and energy release; the results of gas channeling stages calculated by the new method were consistent with the field monitoring data, which can be used as the basis for the identification of the gas channeling stage in the mine; the greater the reservoir porosity, the longer the gas-free oil production stage and the later the gas channeling development stage; the closer the production well was to the gas injection well, the earlier the gas breakthrough time was, and the duration of complete gas channeling was 3 148 d, 4 120 d and 5 610 d for the inverse nine-spot pattern, row pattern and five-spot pattern, respectively. The research results can provide theoretical guidance for the enhanced oil recovery of low permeability reservoirs under development by CO₂ miscible flooding with injection-production coupling.

Experiment on Influencing Factors of Natural Depletion of Fractured-Vuggy Condensate Gas Reservoirs

Li Aifen, Fan Xinhao, Gao Zhanwu, Chu Junfeng, Cui Shiti

2022, 29(4):  96-100.  DOI: 10.3969/j.issn.1006-6535.2022.04.013

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In order to investigate the influencing factors of the natural depletion effect of condensate gas reservoirs, a block of condensate gas reservoirs in Tarim Basin was selected as the study object, and experiments on the recovery efficiency of gas condensate and natural gas with different depressurizing rates and different fracture-vug locations were performed through artificial holes made in carbonate cores to analyze the changes in the gas-oil ratio and the components of produced gas. The experimental results showed that, the depressurizing rate was positively correlated with the recovery efficiency of gas condensate and natural gas; the recovery efficiency was the largest when the fracture-cavity was in the upper position of the target layer, the second in the lateral position, and the smallest in the lower position; the gas-oil ratio presented a trend of first decreasing and then increasing, and the pores of the carbonate fracture and vug caused the dew point pressure of the condensate system to rise; the methane content in the recovered gas was negatively correlated with the recovery efficiency of gas condensate. The study results are of important significance for guiding the selection of development methods of fractured-vuggy condensate gas reservoirs and the improvement of production effect.

Test on the Seepage Pattern in Injection and Production of Gas Storage in Bottom-water Gas Reservoir

Chen Xianxue

2022, 29(4):  101-106.  DOI: 10.3969/j.issn.1006-6535.2022.04.014

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In order to further study the gas-water seepage pattern of gas storage in bottom-water gas reservoir during multi-cycle injection and production, the reservoir core in S6 gas storage, Liaohe Oilfield was sampled to evaluate the stress sensitivity of permeability in multiple cycles of pressure boosting and relief, test the gas-water seepage characteristics in multiple cycles of injection and production simulation, and analyze the microstructure in combination with observation by scanning electron microscope. According to the results, the stress sensitivity of permeability in the study area was low, and the permeability was decreased to a low extent after multiple cycles of pressure boosting and relief; after gas-water mutual flooding was conducted for many times, the irreducible water saturation was decreased while the residual gas saturation increased, and then both gradually reached a balance; the multi-cycle injection and product caused micro-cracks and particle migration, the micro-cracks played a dominant role in enhancing seepage capacity, the gas saturation and gas permeability were gradually increased and tended to balance, which was consistent with the law of storage expansion at the early stage and gradual balancing in the later stage in the actual operation. The results of the study provide technical guidance for the reasonable configuration of injection and production parameters and the construction of new gas storage in the area.

Carbamide-assisted SAGD Technology for Enhanced Oil Recovery of Class Ⅲ Super-heavy Oil Reservoirs

Zhao Changhong, Wang Li, Wang Pan, Wang Lilong, Jiang Dan, Zhang Baozhen

2022, 29(4):  107-113.  DOI: 10.3969/j.issn.1006-6535.2022.04.015

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Class Ⅲ super-heavy oil reservoirs are featured by high crude oil viscosity, low permeability and well-developed interlayers. In the production with steam-assisted gravity drainage (SAGD), there are slow steam chamber expansion, high oil drainage resistance, low production and low oil-steam ratio. In order to solve these problems, a carbamide-assisted SAGD technology was proposed. Its working principle was discovered and key parameters were optimized by the combination of laboratory tests and numerical simulation. The study showed that the carbamide injected into the steam chamber could bed emulsified to reduce the viscosity, enhance oil displacement efficiency and improve water sensitivity. On the basis of the geological conditions and recovery percent, reservoir selection standards were developed and a test well cluster was selected for Well Block Z in Fengcheng Oilfield. An optimal design was developed, with carbamide injection concentration of 60%, injection temperature of 60-100 ℃, injected amount of 42 t, shut-in duration of 60min for injection well, and subsequent steam displacement slug of 10 t. SAGD was then conducted in the production well after 90 min shut-in. Compared with SAGD with pure steam, the average daily oil production increased by 3.8 t/d during the one-year period, the oil-steam ratio was increased by 0.04, the input-output ratio was 1∶5 at an oil price of 1 988 yuan/t in the calculation stage, and the predicted final recovery efficiency was increased by 9.4 percentage points to reach 55.7%. The study results are of great significance to improve the SAGD development effect of Class Ⅲ super-heavy oil reservoirs.

Study on Characteristics of Remaining Oil Distribution and Countermeasures for Potential Tapping in Well Block Xiayan 11

Duan Bolong, Li Yaoyin, Sun Zhixiong, Chang Zhiyong, Dang Sisi, Ma Yanqing

2022, 29(4):  114-119.  DOI: 10.3969/j.issn.1006-6535.2022.04.016

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In response to the problems of strong intra- and inter-reservoir heterogeneity, continuous decrease in production, unclear pattern of remaining oil distribution after development with water flooding, and poor capability of sustainable and stable production in Well Block Xiayan 11, Xinjiang Oilfield, the distribution pattern of different types of remaining oil in highly heterogeneous reservoir was studied by numerical simulation, reservoir engineering methods and dynamic monitoring, and countermeasures for further potential tapping were defined. The results of the study showed that, there were three types of remaining oil potential tapping areas in Well Block Xiayan 11, specifically, type Ⅰ was the remaining oil controlled by the imperfect injection-production well pattern, featured by high remaining oil saturation (more than 45% on average) and reservoir thickness of no less than 4.5 m and mainly developed with underwater distributary channels, and the potential tapping countermeasure was to improve the physical properties of low-permeability areas by reservoir stimulation; type Ⅱ was remaining oil restricted between wells, featured by high remaining oil saturation (20% to 45% on average) and reservoir thickness of 3.0 to 4.5 m and mainly developed with estuary dams, and the potential tapping countermeasure was to re-perforate the oil-water wells and improve the injection-production well pattern; type Ⅲ was remaining oil with high flooding level, and featured by low remaining oil saturation (less than 20% on average), reservoir thickness of no more than 2 m and scattered remaining oil distribution, and the potential tapping countermeasures included re-perforation of old wells, separate injection of water wells, profile control of water injection wells, and repeated fracturing and re-perforation of low-production wells. The study provides a reference for the development of similar heterogeneous reservoirs.

Study on Damage Mechanism of Water Flooding to Chang₄₊₅ Low-permeability Reservoirs, Nanliang Area

Yu Qichang, Niu Haiyang, Lyu Zeyu, Wu Beibei, Xin Yuandan, Zhao Tao

2022, 29(4):  120-127.  DOI: 10.3969/j.issn.1006-6535.2022.04.017

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In response to poor understanding of formation damage mechanism in the process of water flooding development of Chang₄₊₅ low permeability reservoirs, Nanliang Area, experimental methods such as electron microscopy scanning, casting slice, confocal imaging and XRD were utilized to analyze the pore structure and rock composition of reservoir cores before and after water flooding, determine the effect of water flooding development on reservoir pore characteristics, analyze the potential damage, real-time variation pattern of core permeability in water flooding process by comparison of the salinity and material contents between injected water and formation water, and summarize the mechanism of formation fouling and blockage. The results concluded that the damage of water flooding to Chang₄₊₅ low permeability reservoir, Nanliang Area mainly included salt sensitivity and scaling caused by the incompatibility among injected water, formation water and reservoir, as well as the blockage of mechanical impurities in the reservoir caused by the poor quality of injected water. The study results provide methodological and theoretical support for understanding the damage mechanism of water flooding to low permeability reservoirs.

Quantitative Evaluation Method with Ridge Regression for Injected Water Composition in Low-permeability Reservoirs

Zheng Xianbao, Wang Hongwei, Miao Zhiguo, Li Meifang

2022, 29(4):  128-134.  DOI: 10.3969/j.issn.1006-6535.2022.04.018

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Aiming at the problems of ineffective water injection in Putaohua reservoir, Block Chao 5, Daqing Oilfield, low calculation efficiency of conventional numerical simulation and complicated evaluation procedure, the composition of injected water was analyzed and a full stratigraphic geological model was established. Firstly, the composition of injected water was quantified with numerical simulation method, then a quantitative evaluation model for injected water composition in blocks with high injection-to-production ratio was constructed by ridge regression method on the basis of geological development factors affecting the injected water, and the prediction results of the model were compared with the results of numerical simulation, which proved that the model constructed by ridge regression was more reliable. The results of the study showed that, the water absorption ratio was 55% in the reservoir in Block Chao 5, 28% in the non-zoned reservoir interval and 8% in mud shale, and the water overflow was 12%; the established quantitative evaluation model for injected water composition could accurately characterize the injected water composition in Block Chao 5; compared with the numerical simulation, the ridge regression model could greatly improve the evaluation efficiency with little difference in calculation accuracy. There is much for reference of the study results for improving the water-flooding development effect of oilfields and guaranteeing oilfield development.

Drilling & Production Engineering

Identification of Main Controlling Factors of Coalbed Methane Fracturing Effect Based on Cluster Matching

Min Chao, Dai Boren, Shi Yongheng, Yang Zhaozhong, Li Xiaogang, Zhang Xinhui

2022, 29(4):  135-141.  DOI: 10.3969/j.issn.1006-6535.2022.04.019

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It is difficult to systematically analyze the nonlinear relationship between CBM fracturing effect and influencing factors from the perspective of mechanism, and a method based on cluster matching was proposed to identify the main controlling factors of fracturing effect. The method analyzed the connection between fracturing effect and influencing factors by tapping into the intrinsic connection of influencing factors based on data rather than by subjective judgment. Firstly, the data of gas production indicator after fracturing was taken as the object of study and the agglomerative clustering method was employed to classify and evaluate the effect of sample wells. Secondly, the influencing factors were classified and screened by K-means clustering algorithm in conjunction with information gain sequencing and correction analysis, from which 8 factors were selected: prepad fluid dosage, proppant-carrying fluid dosage, gas saturation, gas content, vertical stress, proppant dosage, fracturing pressure and proppant filling strength. Finally, the selected factors were clustered, and the clustering results were clustered and matched with the evaluation and classification results of fracturing effect, so as to identify the main controlling factors of fracturing effect. The effectiveness and operability of this method were verified by comparing it with other methods for identifying the main controlling factors. The study can provide technical support for optimizing the secondary fracturing plan.

Heat-Fluid Coupling Pattern in the Whole Interval of Heavy-oil Thermal Recovery Wells

Xia Boyi, Gao Qingchun, Sun Liwei, Lu Yuzhou, Ping Shanhai

2022, 29(4):  142-148.  DOI: 10.3969/j.issn.1006-6535.2022.04.020

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To address the problems of unclear coupling mechanism and imperfect optimization of production parameters in the process of steam injection in heavy-oil thermal recovery wells with multiphase flow, the influence of wellbore inclination was considered based on the theory of gas-liquid flow, a gas-liquid heat-fluid coupling model for whole interval of heavy-oil thermal recovery wells was established in combination of the distribution characteristics of fluid film in the wellbore, and the influence of different parameters on the thermal properties of wet steam in the wellbore was analyzed. The study indicated that, when the wellbore inclination angle was less than 45 °, the thermodynamic properties of wet steam were significantly affected by wellbore inclination; when the wellbore inclination angle was greater than 45 °, the influence on the thermodynamic properties of wet steam was gradually decreases; the pressure, temperature and dryness of the steam varied with the increase in well depth, especially in the horizontal interval. The optimization of injected steam volume and other parameters for three thermal recovery wells in Liaohe Oilfield resulted in a 15.3%, 16.6% and 14.7% reduction in injected steam volume under the expected well production conditions, greatly reducing the development cost of thermal recovery horizontal wells. The study is of great significance to guide the optimization of wellhead steam injection parameters and improve the thermal efficiency of steam injection.

Numerical Simulation of Rock Breaking by Triangular Prismatic Cutter in Conglomerate Formation Based on Discrete Element Method

Liu Xiaoao, Zou Deyong, Wang Qing, Liu Hongshan, Huang Yong, Chen Yahui

2022, 29(4):  149-155.  DOI: 10.3969/j.issn.1006-6535.2022.04.021

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Due to its strong resistance to impact and wear, triangular prismatic cutter grants PDC bit with better rock-breaking efficiency and longer service life when it is used in conglomerate formation, but the rock-breaking mechanism and rock-breaking effect in conglomerate formation are not clear, resulting in a lack of theoretical support for the design of the PDC bit with triangular prismatic cutter which is used in the conglomerate formation. A numerical simulation model of conglomerate breaking by triangular prismatic cutter was established based on the discrete element method to study the conglomerate breaking mode and process under the condition of different bonding strength between conglomerate and cement matrix, and to analyze the effect of diameter and back rake angle of triangular prismatic cutter on the cutting force of triangular prismatic cutter and the propagation of rock cracks during conglomerate breaking. The results showed that the conglomerate was directly stripped at a bonding strength difference of more than 70 MPa, while it was directly broken at a bonding strength difference of less than 40 MPa; the conglomerate cutting and breaking efficiency was maximized at a triangular prismatic cutter diameter of 16 mm and a back rake angle of 15 ° for both bonding strength differences. The study is theoretically significant for the design of PDC bit with triangular prismatic cutter.

Optimal Design of Improved Drainage and Production Device for Gas Recovery Wells with Foam Drainage

Huang Bin, Wang Siqi, Guo Yiwen, Ding Qi, Zhang Lu, Tang Boqiang, Guo Wei, Zou Che

2022, 29(4):  156-163.  DOI: 10.3969/j.issn.1006-6535.2022.04.022

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To address the problem of low efficiency of foam drainage and gas recovery technology in gas wells, a gas-foam flow coupling model in wellbore was established based on COMSOL software, and a liquid retention device and a secondary foaming device used in gas recovery wells with foam drainage were optimally designed. It was found in the study that in the wave-shaped retention device, the liquid was stabilized and not be carried downwards by gas, resulting in a relatively stable dynamic system with relatively low flow resistance and strong water storage capacity; foams were generated when the gas entered the liquid through the improved foaming structure, and the foaming performance of pulse trapezoidal foaming device was the best. The laboratory tests were conducted in gas recovery wells with foam drainage to compare and analyze the variation of liquid level in the wellbore with time before and after the improved drainage and recovery device was mounted and to verify the practicality of the improved drainage and recovery device. The improved drainage and recovery device can realize efficient foam drainage and gas recovery, with great significance to the efficient development of natural gas.

Preparation and Application of Cross-linked Starch as Filtrate Reducer with High Temperature Tolerance for Drilling Fluid

Li Jiaqi, Yang Haitong, Ge Bing, Yang Xiao, Jiang Hanqiao, Sun Mingbo

2022, 29(4):  164-168.  DOI: 10.3969/j.issn.1006-6535.2022.04.023

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In view of the poor high-temperature tolerance of conventional filtrate reducers for drilling fluid, a cross-linked starch as filtrate reducer with high temperature tolerance for drilling fluid was synthesized by cross-linking reaction method with corn starch taken as raw material and sodium trimetaphosphate as cross-linking agent. As found in the test results, the cross-linked starch prepared by using sodium trimetaphosphate as the cross-linking agent was highly tolerant to temperature; when the mass fraction of cross-linked starch in the drilling fluid was 1.5%, it was still effective in filtrate loss reduction at 160 ℃, with an API filtrate loss of 11.0 mL and a viscosity of 33.5 mPa·s; compared with carboxymethyl starch used as filtrate reducer, this filtrate reducer was distinctly effective in high temperature tolerance without viscosity increase. The results of its application on an appraisal well in Yuanba Block of Southwest Oilfield showed that it effectively reduced the filtrate loss of drilling fluid at 150 ℃, and at the same time controlled the drilling fluid viscosity and improved the overall temperature tolerance of the drilling fluid. The field application effect was excellent. The results of the study can serve as references for the preparation of cross-linked starch as filtrate reducer for drilling fluid.

Effects of Admixtures on Slag-fly ash Geopolymer Cementing Slurry

Wang Siyi, Yang Hao, Yang Shihan, Chen Jiebin, Wang Zhuoyinan, Sun Guiyi

2022, 29(4):  169-174.  DOI: 10.3969/j.issn.1006-6535.2022.04.024

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To address the problems of short setting time, high apparent viscosity and great filter loss of geopolymer cementing slurry, the effects of retarder, dispersant and fluid loss agent on geopolymer cementing slurry were studied based on the performance parameters such as setting time, apparent viscosity and filter loss. The results showed that, the retarders barium chloride and borax only had weak retarding effect, while sodium fluorosilicate had a good retarding effect and could improve the compressive strength of set cement; the dispersant sodium lignosulfonate and the naphthalene water reducer had a certain dispersibility, and the naphthalene water reducer had a better viscosity reduction effect than sodium lignosulfonate at the same injection rate, while the polycarboxylate water reducer showed a thickening effect; the fluid loss agents CMC and CMS were significantly effective in fluid loss reduction, CMS was superior to CMC in terms of fluid loss reduction at the same injection rate, and both of them could improve the compressive strength of cement set for 3 days, The study provides a reference for the selection of cement slurry used in well completion.