Table of Content

25 April 2022, Volume 29 Issue 2

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Summary

Current Status and Prospect of Study on Supercritical CO₂ Fracturing Characteristics

Li Xiaogang, Ran Longhai, Yang Zhaozhong, He Yuting, Liao Zijia, Cao Wenyan

2022, 29(2):  1-8.  DOI: 10.3969/j.issn.1006-6535.2022.02.001

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Previous studies on the characteristics of supercritical CO₂ fracture initiation, propagation and conductivity were summarized in order to enhance the understanding of the fracture characteristics of supercritical CO₂ fracturing and guide the development of supercritical CO₂ fracturing technology. The results showed that the fracture initiation pressure in supercritical CO₂ fracturing was lower than that of both liquid and water fracturing, which was mainly caused by that the low viscosity and high diffusivity of supercritical CO₂ increased the pore pressure and reduced the fracture initiation pressure; the influencing factors of fracture propagation were complex, mainly dominated by CO₂ phase change, rock weak surface structure and the weak surface structure of the rock, but the specific mechanism was not yet clear, and it was necessary to develop experimental devices and establish a three-dimensional model of fracture propagation for more microscopic and detailed study; compared with water fracturing, the roughness, tortuosity and length of fractures in supercritical CO₂ fracturing were greater, but the fracture width was smaller and the fracture effectiveness was insufficient; in the supercritical CO₂ fracturing, natural and artificial fractures could be sheared in a staggered manner, and CO₂ could enter the micro-fractures and pores to destroy the cementation of rock and minerals, causing rock and minerals to fall off to generated unpropped fractures that were conductive, but a study was required for the formation mechanism and maintenance mode. This study provides a reference for the study of fracture characteristics of supercritical CO₂ fracturing.

Geologic Exploration

Difference in Oil and Gas Transport between Lower-Source and Upper-Reservoir and Upper-Source and Lower-Reservoir Oil Source Faults

Sha Zixuan, Yu Dan, Fu Guang

2022, 29(2):  9-15.  DOI: 10.3969/j.issn.1006-6535.2022.02.002

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In order to study the characteristics and regularity of hydrocarbon distribution of different source-reservoir-cap assemblages, two assemblages (lower-source and upper-reservoir model and upper-source and lower-reservoir model) were studied for the difference in oil and gas transport characteristics of oil source fault on the basis of the analysis on hydrocarbon migration and accumulation pattern and transport channels and the comparison on characteristics of hydrocarbon distribution and transport channels in oil source fault. The results showed that the characteristics of oil and gas transport were mainly different in the following three aspects. 1) Difference in the plane distribution range of oil and gas transport: the oil and gas were transported within the hydrocarbon expulsion zone of lower-source and upper-reservoir oil source faults, while the oil and gas in upper-source and lower-reservoir oil source faults were transported downwards only when the overpressure value of the source rock was greater than the minimum overpressure required for the downward transport of oil and gas. 2) Difference in the end point and maximum distance of oil and gas transport: The upward transport of oil and gas in the lower-source and upper-reservoir oil source faults was ended at the closed regional caprock, and the distance between the bottom of closed regional caprock and the top of source rock was the maximum distance of downward oil and gas transport of the oil source fault; the downward transport of oil and gas in the upper-source and lower-reservoir oil source faults was ended at the site where the transport power was equal to the resistance, and the distance between such site and the source rock bottom was the maximum distance of downward oil and gas transport of the oil source fault. 3) Difference in horizons for lateral layered sandbody migration in oil and gas transport: The horizon of lateral layered sandbody migration in oil and gas transport of lower-source and upper-reservoir oil source faults was at the layer with high sandstone thickness/ formation thickness ratio under the closed regional caprock; the horizon of lateral layered sandbody migration in downward oil and gas transport of lower-reservoir and upper-source oil source faults was at all sandbodies above the end of its downward transport of oil and gas. The results of the study can provide a theoretical basis for oil and gas exploration in different source-reservoir-cap assemblages.

Optimal Retrieval Method for Mineral Constituents of Shale Oil Reservoirs in Jiyang Sag

Lai Fuqiang, Li Shichao, Wang Min, Liu Yuejiao, Zhong Lulu, Huang Zhaohui, Wang Haitao

2022, 29(2):  16-23.  DOI: 10.3969/j.issn.1006-6535.2022.02.003

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To address the problems of complex and diverse mineral constituents in shale oil reservoirs, inconsistent mineral volume and content models, and difficulties in accurate quantitative evaluation of mineral constituents, the organic framework was introduced to build a petrophysical volume model of "dual-framework" mineral constituents in shale oil reservoirs based on the experimental data of core analysis by X-ray diffraction on all minerals in the rock and thin slice identification of continental shale oil reservoirs in Jiyang Sag, and the optimal retrieval method with least-squares and singular value decomposition was used to calculate the volume and content of mineral constituents of organic and inorganic framework in shale oil reservoirs after the correction of reservoir triple porosity. The research shows that the correlation between the mineral volume content calculated by the optimal inversion method and the X-ray diffraction measurement results is more than 0.60, which has been verified and applied in actual wells. The study results provide strong support for the accurate evaluation of shale oil reservoirs.

Sedimentary Characteristics and Models of Sublacustrine Fan in the Skip-shaped Fault Depression of Tongbomiao Formation in Urxun Northern Sub-sag

Nan Jinhao

2022, 29(2):  24-33.  DOI: 10.3969/j.issn.1006-6535.2022.02.004

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Urxun Northern Sub-sag in Hailar Basin is a dustpan-shaped fault depression, faulting to the west and overlapping to the east, and the developed steep and gentle slopes control the deposition and reservoir distribution. In order to determine the characteristics of upper high-yield sand body sedimentary reservoirs in Sand Group I (TⅠ) in Tongbomiao Formation and clarify the distribution rules of high-quality sand bodies, a systematic study was conducted on the sedimentary type, sedimentary characteristics and sedimentary model of upper sand body of Oil Group I (TⅠ) in Tongbomiao Formation according to lithofacies, logging facies, seismic facies characteristics, grain size analysis, etc. The results of the study showed that the upper sand body of Tongbomiao TⅠ in the study area was mainly developed with sublacustrine fan deposition, and two sedimentary patterns, namely gravel-rich sublacustrine fan and sand-rich gravel bearing sublacustrine fan, were established through the study of the palaeogeomorphic characteristics, source supply background and triggering mechanism. During the strong tectonic movement in the late period of Tongbomiao Formation, the gravel-rich sublacustrine fan was developed with steep slope and controlled by faulting, while the sand-rich gravel bearing sublacustrine fan was developed with gentle slope and controlled by faulting and gravity. According to the existing exploration evaluation, the gravel-rich sublacustrine fan was considered to be the main target area, and the reservoir accumulation mechanism should be further studied to optimize the targets for the sand-rich gravel bearing sublacustrine fan. The research results have effectively promoted the optimization of favorable reservoirs in the Tongbomiao Formation of Urxun Northern Sub-sag, as well as the deployment of well positions. After further evaluation and optimization of the two types of sublacustrine fans, the available reserve is expected to be 500×10⁴t. There is much for reference of the study results for further oil and gas exploration and development of Tongbomiao Formation.

Sedimentary Model and Its Architectural Characteristics of Delta under the Control of Fault-Rupture-Sag Coupling in Wushi Sag

Wang Yu, Zhang Hui, Yang Chaoqiang, Qi Zhi, Ma Huashuai, Wang Meng, Chen Jian

2022, 29(2):  34-41.  DOI: 10.3969/j.issn.1006-6535.2022.02.005

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In view of the problems of complex fault structure and unclear understanding of flagstone distribution and connectivity of the reservoirs in Member 2, Liushagang Formation, Wushi Oilfield Cluster, the deposition patterns and architecture characteristics of delta in Wushi Sag were more understood on basis of comprehensive interpretation and application of core, well logging and seismic data. It was found in the study that the sedimentary development in the study area was affected by multiple factors such as base level change, fault development, and paleo-geomorphology, and mainly develops the delta sediment was mainly formed by fault-rupture-sag coupling under the control of base level; constrained by the sedimentary model, the characteristics of typical sedimentary microfacies were identified, and it was determined that the base level has experienced the lacustrine-delta front-delta shrinking sediment in the process of first falling and then rising; it was clarified that the delta sand body in Member 2 of Liushagang Formation was characterized by the lateral superposition of multiple underwater distributary channels, with such superposition styles as lateral, docking and isolated superposition; finally an architecture model suitable for the study area was established, and the influence of various environmental factors on sandbody distribution was determined. The results can effectively guide the analysis of sandbody connectivity. The results of the study lay a foundation for the efficient development of Wushi Oilfield Cluster, and can be used as a reference for the study of sedimentary models and internal structures of similar complex block-faulted oil and gas fields.

Pressure Characteristics and Its Influence on Hydrocarbon Accumulation of Lower Cretaceous Formation in Longfengshan Area, Changling Faulted Depression

Song Hao, Jiang Youlu, Hou Shuai, Chen Xingxia

2022, 29(2):  42-50.  DOI: 10.3969/j.issn.1006-6535.2022.02.006

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Longfengshan Area in Changling Faulted Depression is abundant in Lower Cretaceous hydrocarbon resources, and the hydrocarbon distribution is obviously controlled by abnormal pressure, so it is important to study the characteristics of formation pressure and its influence on hydrocarbon. The measured formation pressure and logging data were used to analyze the pressure characteristics of Lower Cretaceous Formation in Longfengshan Area and explore the causes of the overpressure in Shahezi Formation. The evolution of formation paleopressure was restored by the inclusion homogenization temperature-salinity method in combination with the basin modeling technology to determine the influence of formation pressure evolution on hydrocarbon accumulation. The results showed that the bottom-up pressure of Lower Cretaceous Formation in the study area was normal pressure, overpressure and normal pressure, and Shahezi Formation was under overpressure due to pressurization during hydrocarbon generation; the northern subsag belt was at the center of overpressure in the study area, and the formation pressure transited to normal pressure in all directions; the evolution of formation pressure experienced five stages: pressurization during early hydrocarbon generation, initial pressure release, pressurization during late hydrocarbon generation, secondary pressure release, and slow pressure accumulation; the overpressure generated in hydrocarbon generation of source rocks of Shahezi Formation was the main driving force of hydrocarbon migration, and the hydrocarbon migrated along the direction of the remaining formation pressure drop and mainly accumulated in the southeast gentle slope belt. The study results have a certain guiding significance for the in-depth exploration and development of Longfengshan area, Changling Faulted Depression.

Calculation Method and Its Application of Organic Carbon Composition of Source Rock Based on Rock Pyrolysis Data

Li Yonghui, Liu Gang, Gao Liang, Xiang Juan, Song Haiqiang, Hu Yuanwei, Wang Qing

2022, 29(2):  51-56.  DOI: 10.3969/j.issn.1006-6535.2022.02.007

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The abundance and composition of organic carbon in source rocks continue to change with the increase of thermal evolution. In order to study the change rule of organic carbon composition, the concept of “organic carbon composition” was proposed, and a method was developed to calculate the relative contents of residual effective carbon, residual ineffective carbon, original effective carbon and original ineffective carbon in source rocks based on rock pyrolysis parameters. Based on low-cost rock pyrolysis analysis, this method can calculate the organic carbon composition of various source rocks in a fast and quantitative manner. This method was applied to the study of organic carbon composition of low-mature Mesozoic and post-mature Paleozoic source rocks in Yin′gen-Ejinaqi Basin, and achieved outstanding results. The results showed that for the low-mature source rocks, the residual organic carbon composition was not changed much compared with the original organic carbon composition, and the proportion of effective carbon only decreased slightly, while the proportion of ineffective carbon only increased slightly, indicating that the hydrocarbon conversion rate of low-mature source rocks was low, and only a small amount of effective carbon was converted to hydrocarbons; for the post-mature source rocks, the hydrocarbon conversion rate of effective carbon was extremely high, and most of the residual organic carbon was non-pyrolysable “dead carbon”, while only a very small proportion of effective carbon was converted to hydrocarbons. This study has realized the improvement of studies on organic carbon composition of source rocks from qualitative to quantitative, and can provide a basis for the study of thermal evolution characteristics of organic carbon in source rocks.

Accumulation Pattern and Favorable Reservoir Prediction of Paleozoic Gas Reservoirs in Ordos Basin

Li Hao

2022, 29(2):  57-63.  DOI: 10.3969/j.issn.1006-6535.2022.02.008

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Natural gas in Yanchang Gas Field Ordos Basin was explored relatively late. Paleozoic gas reservoir is buried deeply and difficult to explore. In order to explore the accumulation pattern of gas reservoirs in this area, the accumulation characteristics and enrichment pattern of Paleozoic gas reservoirs in the south of Yanchang Gas Field were studied in terms of stratigraphic distribution, tectonic features, sedimentary facies and reservoir controlling factors based on sedimentological principles. The study showed that the relatively high-quality reservoirs in Yanchang Gas Field were the key to natural gas formation and enrichment, and the reservoir size determined the scale of the gas reservoir; the development of high-quality reservoirs was mainly controlled by paleo-geomorphology, rock type and late diagenesis; high-quality reservoirs were mainly developed in deltaic distributary channels and estuary dams, and the quartz-rich sedimentary system was high in natural gas enrichment. There is much for reference of the study results to the exploration and development of Paleozoic gas reservoirs in Yanchang Gas Field.

Classification and Evaluation of Bedrock Reservoirs in Xinglongtai Buried Hill

Guo Zinan

2022, 29(2):  64-71.  DOI: 10.3969/j.issn.1006-6535.2022.02.009

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The reservoir space of bedrock oil reservoir is dominated by fractures, and the effect of exploration and development depends on the precision of fracture-developed interval prediction. In view of much difficulties in reservoir prediction and other problems due to strong heterogeneity of bedrock reservoirs and multiple main controlling factors of fracture development, based on a study case of Xinglongtai buried hill in Liaohe Oilfield, this paper briefly analyzed comprehensively the drilling, logging, testing and seismic data, to identify the geological, seismic and productivity characteristics of fracture-developed zones. The results showed that the reservoirs of inner buried hill were divided into three types: acid intrusive rock and migmatitic granite were the most dominant lithology in the inner buried hill, with the most developed fractures and a certain stratification, followed by migmatitic gneiss and neutral intrusive roc, and next by gneiss. Basic intrusive rocks and amphibole were non-reservoirs.On the basis of fracture identification, the three-dimensional distribution pattern of favorable reservoirs was accurately characterized, which could effectively improve the reservoir penetration rate and production effect of development wells. The study results are an important reference for the development of similar reservoirs at home and abroad.

Reservoir Engineering

Influence of Top Water Intrusion on SAGD Production Efficiency and Prediction of Downward Channeling Rate of Top Water

Jiang Qi, Wang Zhongyuan, Gong Yuning, Zheng Aiping, Sun Hongan, Liu Jiali, He Jie, Huang Siyuan

2022, 29(2):  72-76.  DOI: 10.3969/j.issn.1006-6535.2022.02.010

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In response to the risk of downward channeling of top water in SAGD development of oil reservoirs in Guantao Formation, Block Du84, Liaohe Oilfield, the influence of the downward channeling of top water on the SAGD development effect was studied in combination with numerical modeling and theoretical studies to discover the changes in the development degree of steam chamber, cumulative oil production, oil-steam ratio and steam chamber pressure after the steam chamber is connected to the top water zone. On the basis of numerical modeling study, a theoretical model was established for predicting the channeling rate of the top water according to the principles of multiphase fluid seepage and heat transfer in oil reservoirs. The results of the study showed that the cumulative oil production and oil-steam ratio in SAGD production were decreased significantly after the steam chamber was connected to the top water zone, and the higher the pressure of the top water zone, the greater the influence on the production effect of SAGD; the most effective method of reducing the influence of top water on the later stage of SAGD was to maintain a certain isolator thickness between the steam chamber and the top water zone; therefore, the minimum isolator thickness is recommended to be 20 m between the steam chamber and top water zone under existing operating conditions. This study provides a theoretical basis for determining the technical limits of SAGD operation in heavy oil reservoirs with top water.

A Calculation Method for Material Balance of Shale Gas Reservoirs under Abnormally High Pressure Considering Modified BET Adsorption

Zhang Chengwei, Cheng Shiqing, Zhou Wen, Zhang Teng, Jiang Ke, Zhu Lang, Xu Hao

2022, 29(2):  77-82.  DOI: 10.3969/j.issn.1006-6535.2022.02.011

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Langmuir isothermal adsorption equation is usually used to characterize the amount of adsorbed gas in the material balance equation of shale gas, while the application conditions of Langmuir isothermal adsorption equation are not suitable for shale gas reservoirs under abnormally high pressure. To address the problems about the calculation of single-well recoverable reserves in shale gas reservoirs under abnormally high pressure, based on the basic principle of the material balance equation, a modified BET adsorption model was introduced to characterize the adsorption characteristics of shale gas with consideration of the triple effects (multilayer adsorption, supercritical adsorption and abnormally high pressure) of shale gas, and a material balance equation was established for shale gas reservoirs under abnormally high pressure considering the modified BET adsorption factor. The application of the study results to the analysis of single wells in actual blocks proved that the linear correlation coefficient of the model established in this paper was higher, and the model can not only calculate the controlled reserves of gas wells, but also calculate the free gas content and adsorbed gas content in the gas release range. According to the calculation results of this equation and the geological conditions of the actual reservoir, the construction conditions considered by the model in this paper are closer to the actual reservoir conditions. The study results play an important guiding role in the production management of shale gas reservoirs under abnormally high pressure.

Analysis of Asphaltene Deposition Characteristics and Influencing Factors of CO₂ Flooding in Shale Reservoirs

Sun Ting, Shi Haidong, Zheng Jianjun, Zhong Xiaogang, Watheq J, Al-Mudhafar

2022, 29(2):  83-90.  DOI: 10.3969/j.issn.1006-6535.2022.02.012

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In order to clarify the mechanism of CO₂ flowing in the nano-pores of shale reservoirs and its influence on asphaltene deposition, a nano-filtration experiment was conducted with self-developed high-temperature and high-pressure filtration vessel and composite nano-filtration membrane to simulate the CO₂ flooding process under the action of single (multi)-layer rock slices, and to study the influence of reservoir parameters and injection parameters on CO₂ flooding effect and asphaltene deposition. The results showed that CO₂ flooding caused asphaltene deposition, resulting in the asphaltene content in the remaining much higher than that in the produced oil; the asphaltene content in the produced oil increased with the increase of CO₂ injection pressure and filter membrane pore size, but decreased with the increase of temperature, shut-in duration, membrane thickness and heterogeneity; the influence degree of reservoir parameters and injection parameters on asphaltene deposition was as follows: membrane thickness (40.63%), injection pressure (20.74%), heterogeneity (16.84%), temperature (10.86%), membrane pore size (7.37%), and shut-in duration (3.56%). The study results provide reference and basis for enhancing the recovery efficiency of shale oil reservoirs by CO₂ flooding.

Evaluation Method of Water-flood Stimulation Effect of Horizontal Wells in Tight Oil Reservoirs

Di Shiying, Cheng Shiqing, Dai Li, Li Wangdong, Miao Li′nan, Liu Qi

2022, 29(2):  91-97.  DOI: 10.3969/j.issn.1006-6535.2022.02.013

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In view of poor water-flood stimulation effect in tight reservoirs, the reservoir engineering method was applied, taking into account the geological characteristics, fracturing technologies and water-flood stimulation system, to quantitatively characterize the degree of development of the complex fracture network formed by natural and fractured fractures in tight reservoirs based on the fracture fluid flowback rate and fracturing stimulation multiplier, and to work out a method for calculating the fracture network development coefficient. The nine-scale method was used to establish weight set of evaluation indicators for fuzzy calculation and type identification. The study results were applied to the evaluation of water-flood stimulation effect in Block M, Santanghu Basin, 10 evaluation indicators were established, and the value of each evaluation indicator were divided into three categories, and the value limit of each category were determined. The results showed that the proportion of Class I wells was 45.1%, and the accuracy rate was 86.21% compared with actual production. This study on development effect evaluation provides a reference for water-flood stimulation in tight reservoirs.

Research and Application of Steam Flooding Technical Limit for Super Heavy Oil in Liaohe Oilfield

Zhao Hongyan, Ge Mingxi, Zhang Hong

2022, 29(2):  98-103.  DOI: 10.3969/j.issn.1006-6535.2022.02.014

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Super heavy oil exceeds the viscosity limit of steam flooding and is generally considered unsuitable for steam flooding development. In fact, the steam flooding for super heavy oil has a threshold temperature, and steam flooding can be implemented when the reservoir temperature exceeds the threshold temperature. Aiming at the unclear understanding of the steam flooding technical limit for super heavy oil in Shu-1 block of Liaohe Oilfield, a threshold temperature model for steam flooding was established using laboratory experiment and numerical simulation methods. And a forecasting formula of the lowest oil production limit under different oil prices was also established using economic benefit method. The research results show that the threshold temperature for steam flooding in the Shu-1 block ranges from 80 ℃ to 100 ℃; at an oil price of 2 248 yuan/t, the minimum oil production limit is 2.5×10⁴t, and the minimum oil layer thickness limit is 14-18 m. Based on the pilot test, the limits of the maximum liquid production and the minimum steam injection rate of a single well were determined, and the well pattern for steam flooding was optimized to be inverted nine-spot pattern with a well spacing of 70 m. At present, 436 steam flooding well groups have been optimally deployed in the Xing Ⅱ-Ⅴ oil layer group in Shu-1 block, and the recovery rate after steam flooding is predicted to be 62.1%. This research is of great significance to the development of similar reservoirs.

Testing Method and Prediction Model of Elemental Sulfur Solubility in Sour Gas Reservoirs

Wu Yajun, Wang Ning, Zhang Guangdong, Zhang Mingdi, Mo Chaoping

2022, 29(2):  104-109.  DOI: 10.3969/j.issn.1006-6535.2022.02.015

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To address the problem of low accuracy in measuring the solubility of elemental sulfur in sour gas reservoirs, an experimental device and experimental method for testing the elemental sulfur solubility in sour gas reservoirs were established based on the solvent dissolution principle to determine the solubility of elemental sulfur in sour gas sample of a gas reservoir. The results of the study showed that the solubility of elemental sulfur in sour gas reservoir was 0.001 to 0.968 g/m³ under standard conditions at a formation temperature of 40.0 to 98.9 ℃ and a formation pressure of 15.0 to 49.8 MPa; the solubility of elemental sulfur was positively correlated with temperature and pressure, specifically increasing with the increase of temperature and pressure; based on the Chrastil semi-empirical model, a new model was established to calculate the solubility of elemental sulfur; the comparison of various models indicated that the new model was more accurate, with an average error of 1.79%. The study results provide important basic data and research method for the phase state and sulfur deposition control of sour gas reservoirs.

Numerical Modeling Method of Low-permeability Reservoir Based on Stress Sensitivity and Matrix Shrinkage Effect and Its Application

Wan Xiaolong, Wang Siyi, Guo Xifeng, Lan Zhengkai

2022, 29(2):  110-114.  DOI: 10.3969/j.issn.1006-6535.2022.02.016

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In low-permeability reservoirs, stress sensitivity effect is often considered while matrix pore shrinkage effect is ignored, resulting in great errors in the evaluation results of reservoir permeability and productivity. To address the above problems, a mathematical model considering the effects of both stress sensitivity and matrix shrinkage was established with reservoir engineering methods, to explore its feasibility in predicting production performance in the Ansai Oilfield, in combination with a permeability evolution model based on fractal theory. The study showed that under the effective stress below 5 MPa, if the matrix shrinkage effect was ignored, the reservoir permeability was underestimated, which affected the later adjustment of the development plan; the theoretical model established in this paper matched the actual production data by 92%, indicating that the model can better predict the production performance of oil wells in the study area. The study results can be used as an important reference for the late tapping potential and adjustment of similar low-permeability reservoirs in Changqing Oilfield.

Adsorption and Retention Law of ASP Flooding

Fu Qingchun

2022, 29(2):  115-121.  DOI: 10.3969/j.issn.1006-6535.2022.02.017

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To solve the problem that it is difficult to determine the process parameters during the field implementation of ASP flooding in Daqing Oilfield, based on the reservoir physical parameters in the east of Block Bei 2, the mass concentration of each component, shear viscosity reduction and interfacial tension change in the process of ASP flooding was studied through the laboratory displacement experiment with sand filling model, and the adsorption and retention law of each component under the dynamic condition of ASP flooding was studied by numerical modeling. The experimental results showed that the mass concentrations of each component of ASP flooding decreased with the increase of migration distance, and increased with the increase of injected amount; the loss of solution viscosity was about 60% at 20% migration distance; the oil-water interfacial tension was higher than 10^-2 mN/m at the displacement front. As indicated by the results of numerical modeling, the adsorption and retention of the mass concentration of each component of the ASP flooding solution were mainly concentrated in the near-well zone, and the losses of surfactant, alkali and polymer were 80%, 25% and 18% respectively at 20% migration distance; the lower the reservoir permeability, the more serious the adsorption and retention loss. This study provides data basis and theoretical guidance for the adjustment of ASP flooding technology in the development of in Block Bei 2, Daqing Oilfield.

Steady Productivity Evaluation Method of Fractured-porous Carbonate Gas Reservoirs

Liu Ronghe, Zhang Wenbiao, Leng Youheng

2022, 29(2):  122-127.  DOI: 10.3969/j.issn.1006-6535.2022.02.018

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Since conventional gas reservoir productivity equation is difficult to accurately evaluate the productivity of fractured-porous carbonate gas reservoirs, Kazemi model was adopted to simplify the seepage model of fractured-porous carbonate gas reservoirs, the dual-medium complex seepage was decomposed into the linear seepage in substrate layer and the radial seepage in horizontal fractures according to the different flow states of gas in fracture and substrate layer, the steady productivity equation of fractured-porous carbonate gas reservoirs was established with consideration of fracture permeability, fracture opening, fracture number and channeling coefficient, and the productivity sensitivity of gas wells was analyzed. The results showed that the open-flow capacity increased with the increase in the permeability, openness and number of fractures, presenting a positive linear relationship; the open-flow capacity of gas wells increased with the increasing channeling coefficient, and remained unchanged when the channeling coefficient was greater than 5×10^-9. This study provides a new solution for steady productivity prediction of fractured-porous carbonate gas reservoirs.

Classification Evaluation and Application of Heterogeneous Reservoirs Based on Improved Capillary Pressure Curve

Li Xinwen, Wu Hua

2022, 29(2):  128-134.  DOI: 10.3969/j.issn.1006-6535.2022.02.019

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In view of the strong heterogeneity of the fine reservoir development, taking reservoirs in Qianjiang Formation, Jianghan Basin as the study object, a classification evaluation system of reservoir quantitative indicators was established in combination with the characteristic parameters of improved capillary pressure curve and the basic core parameters, and the effective reservoir thickness was organically combined with logging curve to develop a new method of normalization of capillary pressure curve family. The results showed that the classification evaluation system of reservoir quantitative indicators based on the improved capillary pressure curve mainly included five quantitative indicators: permeability, starting pressure, transitional pressure, median pressure and proportion; the reservoirs in Qianjiang Formation were subdivided into Ⅰ, Ⅱ, Ⅲ, Ⅳ, Ⅴ and Ⅵ types; Types Ⅰ and Ⅱ were the reservoirs with the best permeability, accounting for 41.17% of the all reservoirs, Types Ⅲ and Ⅳ were mainly the reservoirs with medium and low permeability, accounting for more than 50.00%, Types V and VI were the reservoirs with extra (super) low permeability, accounting for only 7.77%; the normalization method of capillary pressure curve family based on effective thickness was simple in calculation and low in errors, providing a basis for the characterization and comparison of reservoir characteristic parameters after reservoir classification and evaluation.

Catalytic Oxidation Experiment of Transition Metal Cobalt Salt in In-situ Combustion for Heavy Oil

Han Xiaoqiang, Li Xiao, Peng Xiaoqiang, Ru Candong, Zhang Jizhou, Shi Hao, Li Zhongquan

2022, 29(2):  135-140.  DOI: 10.3969/j.issn.1006-6535.2022.02.020

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On account of the difficulties for the secondary heavy oil ignition in the in-situ combustion of Hongqian Pilot Test Area, Xinjiang, an experimental study on the catalytic oxidation of heavy oil by transition metal salt was conducted to evaluate the effect of transition metal salt in promoting the stable advancement of the front end of heavy oil in-situ combustion. A physical simulation experiment of in-situ combustion was conducted with one-dimensional combustion tube to analyze the effect of cobalt salt on the peak temperature and front edge advance of heavy oil in-situ combustion. A simultaneous thermal analyzer (TG-DTA) was used to measure the oxidation process of heavy oil, establish the kinetic equation of heavy oil catalytic oxidation, and calculate the activation energy and fingertip factor in the three stages (low-temperature oxidation, fuel deposition and high-temperature oxidation) of the heavy oil combustion. The results showed that after the addition of cobalt nitrate, the activation energy of low-temperature oxidation of heavy oil was reduced by 32%, the activation energy at fuel deposition stage was reduced by 31%, the high-temperature oxidation stage was advanced, and the peak temperature of heavy oil combustion was reduced by 50 ℃; the peak temperature difference at the front edge of in-situ combustion was reduced by 90 ℃, realizing the stable advance of the front edge of in-situ combustion. The study results can theoretically and technically support the secondary ignition process of oil recovery by in-situ combustion.

Drilling & Production Engineering

Study and Application of Fine Segmented Deep Acid Fracturing Technology for Horizontal Wells

Miao Juan, He Xusheng, Wang Dong, Chen Hongyuan, Xiao Zhenhua

2022, 29(2):  141-148.  DOI: 10.3969/j.issn.1006-6535.2022.02.021

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Carbonate gas reservoirs in Sinian Dengying Formation, Gaoshiti-Moxi Area, Sichuan Basin is geologically characterized by ultra depth, high temperature, low porosity, low permeability, and high heterogeneity, bringing new challenges for reservoir stimulation. The existing stimulation technologies need to be further optimized. With laboratory experiments and theoretical studies, the reservoir fracturability was evaluated quantitatively, the acidizing fluid system and acid fracturing technologies were selected preferably, and parameters, such as acidizing fluid injection, displacement and injection intensity, were optimized. The fine segmented deep acid fracturing technology for horizontal wells was developed and applied in the field. The results showed that the technology achieved good results by application to 32 wells in carbonate gas reservoirs in Dengying Formation, Gaoshiti-Moxi Area, the average daily gas production of single test well was 79.8×10⁴ m³/d, and there were 10 wells reaching a daily gas production of 1 million m³/d. This technical system has achieved obvious fracturing effect and can provide technical support for the efficient development of carbonate reservoirs with low porosity and permeability.

Research and Practice of SRV Fracturing Technology for Inter-salt Shale Oil

Liu Honglei, Xu Shengqiang, Zhu Biwei, Zhou Linbo, Huang Yajie, Li Baolin

2022, 29(2):  149-156.  DOI: 10.3969/j.issn.1006-6535.2022.02.022

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The inter-salt shale oil reservoirs are characterized by unclear creep characteristics of the upper and lower salt rocks, susceptibility to interference with the upper and lower plastic rocks during fracturing, multiple lithological components, complex sensitivity, poor pore connectivity, and unclear dissolution pattern of soluble salts. There are more stringent requirements for SRV fracturing due to reservoir characteristics. For efficient development of inter-salt shale oil, Well BYY1HF in Paleogene inter-salt shale oil reservoir, Qianjiang Sag was tested with such technologies as CO₂ enhanced composite fracturing, acid-resistant fracturing fluid plus sanding, dense cutting plus forced-sanding fracturing, and temporary plugging fracturing with ball casting. CO₂ enhanced composite fracturing had the advantages of increased flowback capacity, improved matrix porosity and permeability, strong penetration, and high flowback rate. The acid-resistant fracturing fluid system could maintain stable performance, strong sand carrying capacity and low damage to reservoirs in acidic environment (pH 2-6). The dense cutting plus forced-sanding fracturing technology could eliminate the "agglomeration effect", promote the uniform opening and propagation of each cluster of fractures, and improve the SRV fracturing effect. The construction results showed that the technical system was advantaged by enhancing the flowback capacity, improving the porosity and permeability of the reservoir, promoting the rock capacity of fracturing initiation, fracture complexity, etc., and improving the oil supply capacity of the matrix to a certain extent. The test of fracturing technology is of great significance in reference for the large-scale fracturing transformation of inter-salt shale oil.

Evaluation Method of Fracture Complexity of Fracture Network Fracturing for Tight Sandstone Fractured Gas Reservoir

Xiao Yang, Liu Shouyu, He Yongzhi, Li Zhigang, Wang Jiahao, Yang Jinyuan, Ma Zhonghui

2022, 29(2):  157-163.  DOI: 10.3969/j.issn.1006-6535.2022.02.023

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Microseism is an effective method and means to evaluate the fracture morphology and geometry formed by fracture network fracturing in fractured tight sandstone oil and gas reservoirs, but constrained by its applicability conditions and high cost. Therefore, a rapid, economical and applicable method is needed to evaluate the fracture complexity in fracture network fracturing. Based on the pressure drop data after fracture pump shutdown, the reservoir seepage model was analyzed by seepage equation which was established for tight sandstone fractured reservoirs with apparent homogeneity, linear fracture and complex fracture, and the reservoir fracture morphology was analyzed with G function, so as to comprehensively evaluate the fracture complexity in the network fracturing and develop a method to quickly evaluate the fracture complexity of the network fracturing. The microseismic test results proved that this method was reliable. The study results can technically provide support for the network fracturing effect evaluation and productivity prediction of tight sandstone fractured gas reservoirs.

Analysis on Factors Affecting Water Control by Supersaturated Filling of Fractured Reef Limestone

Zhang Wei, Dai Zong, Gong Bin, Wang Yahui, Zhang Xiaolin, Shi Xin

2022, 29(2):  164-169.  DOI: 10.3969/j.issn.1006-6535.2022.02.024

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In order to clear up the mechanism of water control and shutoff by continuous packer filling and the main controlling factors of filling, a mathematical model of fracture filling was established to simulate the changes in natural fracture opening, conductivity, filling degree, and filling volume with pressure in the filling process, the main factors affecting the filling process were analyzed, and the effectiveness characteristics and reasons were summarized in conjunction with the actual oilfield conditions. Research shows that the initial fracture opening and fracture direction are the main geological factors that affect the water control construction process; whether the pumping pressure in the filling process, especially in the initial stage, reach the threshold of effective filling pressure has a significant impact on the fracture plugging effect. This study provides a reference for the optimization and effect evaluation of measure wells, and lays a foundation for the quantitative study of water control by supersaturated fracture filling.

Study and Application of Hotwork-free Flexible Technology of Online Flange Leak Sealing with Sealant Injection for Oil and Gas Gathering System

Yu Miao, Dou Chao, Zhang Jianbing, Qi Peng, Chen Ping, Shi Tao

2022, 29(2):  170-174.  DOI: 10.3969/j.issn.1006-6535.2022.02.025

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Flange seal failure is a common failure in oil and gas gathering process, which can lead to abnormal shutdown and maintenance of oil and gas gathering system, with huge economic losses. In order to improve the plugging efficiency against flange seal failure, a hotwork-free flexible technology of online flange leak sealing with sealant injection was developed. Specifically, a flexible clamp externally wraps the leaking flange to establish a new sealing structure, and a professional injection tool is used to inject the sealant into the gap between the flanges through the injection hole to seal the leak under pressure. This technology is characterized by excellent safety, convenience and efficiency, and can address the flange leak efficiently and quickly without changing the process parameters. The practical application has proved that it is significant in promotion and application.