Injection Production Wells Research Articles

Adjustment of infill in transition zone to improve oilfield productivity

Affected by the high viscosity of crude oil, the large injection-production well spacing, the poor injection condition, and the low oil recovery rate, the overall development effect of transition zone is poor, besides, the low produced degree and the poor utilization of thin oil layer makes transition zone have some potential excavation. Under the condition that the current conventional measures to improve block development are not clear, it is necessary to further optimize the injection-production system. Based on the principle of “Well pattern rules, Well spacing optimization, Injection-production perfecting, Facilitation of adjustment”, layer combination is thus optimized. This paper analyzes the effect of encryption adjustment and tracking adjustment.

Technology and effect of small well spacing control decline in close well network

In order to further improve oil recovery, water flooding was adjusted for three times from 2009 to 2012. The spacing of injection-production Wells was shortened from 250 meters to 106 meters, and the density of well pattern increased from 90.7 to 196 per square kilometer. This leads to the problems of “rapid rise of water cut, large difference in oil formation production, and large production decline in block u”. In recent years, we by fine geologic research, to improve the poor thin oil layer use condition, controlling water cut rising velocity, as the key point, the energy recovery network continuously grope for dense well spacing control regulation technology, gradually formed dense well network from decreasing “three-excellent” control technology, through the effective implementation, improved the block development effect, achieve the goal of stabilizing oil water control.

Numerical Simulation of Critical Production Pressure Drop of Injection and Production Wells in Gas Storage Based on Gas-Solid Coupling

The periodic injection-production process of natural gas in underground gas storage make the rock bear alternating load under the gas-solid coupling. The alternating load changes the physical properties of rock, and then influence the critical production pressure drop of injection-production wells in gas storage. In the case of gas-solid coupling, the decisive factors affecting the alternating load are the number of injection-production cycles and the injection-production differential pressure. Therefore, a discrete element numerical simulation model is established to simulate the gas-solid coupling process of gas storage wells under different injection-production cycle and differential pressure. The influence mechanism of injection-production cycle and differential pressure on particle cementation and primary crack is analyzed microscopically and also the influence law of injection-production cycle and differential pressure on rock mechanical properties is analyzed from the macroscopic. Finally, the influence law of injection-production cycle and differential pressure on the critical production pressure drop of injection-production wells due to gas-solid coupling can be obtained. The results show that under the influence of gas-solid coupling, the number of bonded contact cracks and micro cracks in the model increase gradually, both the elastic modulus ratio and the cohesion ratio decrease gradually with the increase of injection-production cycle and the higher the injection-production differential pressure, the greater the decline range. Then, with the injection-production cycle increasing the Poisson’s ratio increases gradually and the higher the injection-production differential pressure, the greater the increase range. Finally, the internal friction angle ratio increases greatly in the initial stage, after that decreases and then shows a linear increase. According to the influence law, the relationship model between the critical production pressure drop of injection-production wells in gas storage and the injection-production cycle and differential pressure under the gas-solid coupling will be established, which is used for the dynamic prediction of the critical production pressure drop of injection-production wells in the whole life cycle of gas storage.

Mechanisms of remaining oil formation by water flooding and enhanced oil recovery by reversing water injection in fractured-vuggy reservoirs

To get a deeper understanding on the formation mechanisms and distribution laws of remaining oil during water flooding, and enhanced oil recovery (EOR) mechanisms by reversing water injection after water flooding, 3D visualization models of fractured-vuggy reservoir were constructed based on the elements and configuration of fractures and vugs, and typical fracture-vug structures by using advanced CT scanning and 3D printing technologies. Then, water flooding and reversing water injection experiments were conducted. The formation mechanisms of remaining oil during water flooding include inadequate injection-production well control, gravity difference between oil and water, interference between different flow channels, isolation by low connectivity channel, weak hydrodynamic force at the far end. Under the above effects, 7 kinds of remaining oil may come about, imperfect well-control oil, blind side oil, attic oil at the reservoir top, by-pass residual oil under gravity, by-pass residual oil in secondary channel, isolated oil in low connectivity channel, and remaining oil at far and weakly connected end. Some remaining oil can be recovered by reversing water injection after water flooding, but its EOR is related to the remaining oil type, fracture-cavity structure and reversing injection-production structure. Five of the above seven kinds of remaining oil can be produced by six EOR mechanisms of reversing water injection: gravity displacement, opening new flow channel, rising the outflow point, hydrodynamic force enhancement, vertically equilibrium displacement, and synergistic effect of hydrodynamic force and gravity.

Application of Isotope Tracer in Cross-Well Nanometre Tracer Testing.

In order to understand the dynamic monitoring characteristics and heterogeneity characteristics of injection production wells in the monitoring area and judge the reservoir connectivity, this study puts forward the application method of isotope nanometre tracer in interwell nanometre tracer testing. The trace material nanometre tracer interwell monitoring technology was applied to well block J in a basin. Through the analysis of the morphological characteristics of the nanometre tracer production curve and the quantitative interpretation of trace material tracer, combined with the analysis of the advancing speed of the water line at the front edge of the nanometre tracer and the distribution of injected water wells, the nanometre tracer connectivity, and advancing speed, the characteristics of seepage channels and heterogeneity of the well groups in the study area were defined. The research results show that 8 oil wells in the monitoring area are controlled by water injection well J1, the injection water inrush direction is generally north, the main channel of injection water is mainly high-permeability strip, and the heterogeneity contradiction between layers is strong. It is recommended to adopt mild water injection. Conclusion. This study found that the dynamic connectivity between oil and water wells in the monitoring area is good.

Analysis and Application of Horizontal Well Test in Low Permeability Porous Carbonate Reservoir

Low permeability porous carbonate rocks occupy a certain proportion in the Middle East. Horizontal injection-production well pattern development is often adopted. Due to the influence of well type and wellbore, reservoir dynamic monitoring is mainly based on conventional daily measurement data, well test and pressure monitoring. Therefore, it is particularly important to combine well test interpretation with production dynamic analysis to diagnose the main control factors and production characteristics of this type of reservoir. In this paper, the point source function is used to obtain the pressure variation function of a horizontal well in infinite formation with upper and lower closed boundary. The difference between the horizontal well test curve of A reservoir and the typical horizontal well test curve is compared and analyzed, and the abnormal well test curve of horizontal wells is characterized by a linear flow phase with a slope of 1/3 or 1/4. The abnormal well test curve accounted for 33.34%. The main influencing factors are the permeability around the well and the well trajectory. By combining well test interpretation with dynamic inversion method, the correlation between well test interpretation and dynamic characteristics of horizontal wells with different characteristics is classified and clarified. The main controlling factors that affect the difference in the water injection development effect of different horizontal wells are further clarified, and provide an important reference for the adjustment of injection-production parameters and the optimal deployment of schemes.

Impact research of well layout schemes and fracture parameters on heat production performance of enhanced geothermal system considering water cooling effect

The fluid flow route in an enhanced geothermal system (EGS) is jointly determined by well layout and fracture network, which affects the fluid flow and heat transmission process. To obtain an efficient EGS, it is critical to explore the best well layout and fracture parameter. In this study, combination effects of well layout scheme and fracturing networks are researched. A thermal-hydraulic-mechanical coupling model, accounting for the thermal shock impact of cool water on high temperature rock, is built to evaluate the heat production performance, which takes production temperature, production thermal power and reservoir recovery rate as indicators. Results indicate that addition of symmetrical injection wells could lengthen EGS's operating life and boost production thermal power. Connection between injection-production wells should be as close to the main direction of the fracture as possible to improve fluid flow rate, accelerate heat transfer, and increase heat recovery rate. Furthermore, Morris based sensitivity analyses are performed to identify the key variables influencing EGS production performance. It reveals that the most crucial parameters are injection pressure and fracture opening, which should be raised in practice as much as allowed on the assumption that the production temperature meets the threshold.

Experimental research on the mechanisms of improving water flooding in fractured-vuggy reservoirs

Fractured-vuggy reservoirs have extremely complex reservoir characteristics, leading to a large amount of remaining oil not being recovered after water flooding. In order to solve the problem of the low recovery in fractured-vuggy reservoirs, we utilized 3D printing technology to fabricate two-dimensional and three-dimensional experimental models based on the typical reservoir structure. A series of experiments with different models on improving water flooding is conducted to study the production improvement effect. The difference in oil-water distribution or oil saturation distribution before and after improved water flooding is also compared, and the mechanism is analyzed. The results show that the oil-water gravity differentiation is the most critical factor affecting the remaining oil distribution, and changing the injected pressure or its propagation direction is the root of improving water injection. Reversing injection-production wells, increasing injection strength, water plugging, and cyclic water injection can effectively increase the sweeping scope or displacement efficiency. The attic oil, residual oil in filling medium, bypass remaining oil, and water cone remaining oil can be produced by one or more improving water flooding methods. This paper provides effective measures and mechanisms for the efficient and rapid development of fractured-vuggy reservoirs.

Impact of Well Placement in the Fractured Geothermal Reservoirs Based on Available Discrete Fractured System

Well placement in a given geological setting for a fractured geothermal reservoir is necessary for enhanced geothermal operations. High computational cost associated with the framework of fully coupled thermo-hydraulic-mechanical (THM) processes in a fractured reservoir simulation makes the well positioning a missing point in developing a field-scale investigation. To enhance the knowledge of well placement for different working fluids, we present the importance of this topic by examining different injection-production well (doublet) positions in a given fracture network using coupled THM numerical simulations. Results of this study are examined through the thermal breakthrough time, mass flux, and the energy extraction potential to assess the impact of well position in a two-dimensional reservoir framework. Almost ten times the difference between the final amount of heat extraction is observed for different well positions but with the same well spacing and geological characteristics. Furthermore, the stress field is a strong function of well position that is important concerning the possibility of high-stress development. The objective of this work is to exemplify the importance of fracture connectivity and density near the wellbores, and from the simulated cases, it is sufficient to understand this for both the working fluids. Based on the result, the production well position search in the future will be reduced to the high-density fracture area, and it will make the optimization process according to the THM mechanism computationally efficient and economical.

Evaluation of heat extraction performance of multi-well injection enhanced geothermal system

• Model of multiple-injection and one-production is established using local thermal non-equilibrium. • Effects of reservoir and injection-production parameters on EGS performance were investigated. • Increasing of injection temperature can increases production temperature and prolongs EGS life. • Thermal extraction rate increases with the injection-production distance increases. • Heat recovery rates of four different injection-production well patterns are compared. The well layout can provide fluid channels, which is important for enhanced geothermal system (EGS), then the thermal energy in the rock mass can be used for heat extraction and power generation. The heat extraction rate analysis of injection-production well patterns can provide reference for the heat extraction condition of EGS. Based on the local thermal non-equilibrium theory and random fracture model, the EGS model of four injection and one production was established in this paper. Effects of reservoir parameters and injection-production parameters on production temperature and thermal extraction rate were studied. The results show that the injection temperature and injection-production distance are important parameters that affecting the thermal performance of the EGS. Increasing injection temperature can increases the production temperature and prolongs the EGS life. When the injection temperature increases from 293.15 K to 323.15 K, the production temperature increases from 340.04 K to 354.21 K. The higher the injection-production distance is, the higher the thermal extraction rate is. When the injection-production distance increases from 210 m to 325 m, the thermal extraction rate increases from 41.9% to 56.4%. In addition, heat extraction rates of four injection-production well patterns were compared and analyzed. The heat extraction performance of three-injections and one-production is obviously better than other methods. For the heating demand, the heat extraction rate of this well pattern is 60.34% and its service life is 39.7a. For power generation demand, its heat extraction rate of the well pattern is 55.9%, and its life is 32.7a.

Injection-production optimization of fault-karst reservoir\u2014considering high-speed non-Darcy effect

Fault-karst reservoirs are featured by complex geological characteristics, and accurate and fast simulation of such kind of reservoirs using traditional simulator and simulation methods is pretty hard. Herein, we tried to discrete the complex fault-karst structures into one-dimensional connected units connecting the well, fracture and cave based on reservoir static physical parameters and injection-production dynamics. Two characteristic parameters, conductivity and connected volume, are proposed to characterize the inter-well connectivity and material basis. Meanwhile, the high-speed non-Darcy seepage term is introduced into the material balance equations for well-fracture-cave connected units to describe the actual seepage characteristics within the fault-karst reservoirs, and to better simulate the oil/water production dynamics. Based on this method, a fracture reservoir model of 1 injection-3 production was established. The change of oil–water action law in different injection and extraction systems under two production regimes of fixed production rate and fixed pressure is analyzed. A case study was conducted on S fault zone, where the flow of oil and gas did not follow the Darcy seepage rule and with a β value of 103–104, the single well flow pressure and oil production were perfectly matched with the real data. In addition, connected units with more prominent high-speed non-Darcy features were found to have better connectivity, which might shed light on the more accurate prediction of inter-well connectivity. Moreover, an improved injection-production well pattern and was proposed based on connectivity prediction model and reservoir engineering method to solve the problems of insufficient natural energy supply and overhigh oil production rate in Block S. Furthermore, the injection/production rate as well as the timing and cycle of water injection was predicted and optimized so as to better guide to site operations.

The Impact of Plane Heterogeneity on Steam Flooding Development in Heavy Oil Reservoirs

Abstract Steam flooding is proven to be an effective method to improve the development effect of heavy oil reservoirs. And steam flooding is the most common oil recovery technology for heavy oil reservoirs in China. However, because of the various reservoir physical properties, bring great challenges to successful steam flooding development. According to the previous research and development practice, we know that reservoir heterogeneity has a great influence on the development effect of water flooding. Due to the heterogeneity of reservoirs, the development of different injection-production well patterns will be affected. However, it is uncertain whether reservoir heterogeneity has an impact on steam flooding development effect. In order to clarify the above scientific issues, we take Xinjiang steam flooding oilfield as the research object to carry out relevant research. According to the reservoir distribution characteristics of Xinjiang Oilfield, three conceptual heterogeneity models representing permeability, thickness, and geometric plane heterogeneity are firstly proposed. Then, mathematic models with different plane heterogeneity of reservoir sand were built. Based on the mathematic model, initial conditions, boundary condition, and geological parameters of conceptual models, different steam flooding patterns were studied by applying numerical calculation. It is found that heterogeneity is an important geological factor affecting the development of steam flooding of heavy oil reservoir. And the results showed that cumulative oil production was different of different flood pattern at the same production condition. It can be concluded that the development effect of steam flooding of heavy reservoirs is strongly influenced by flood pattern. In order to improve development effectiveness of steam flooding of heavy oil reservoirs, flood pattern should be optimized. For each type of plane heterogeneity reservoir, a reasonable flood pattern was proposed. For plane heterogeneity of permeability, thickness, and geometry form, under the conditions of that as the producer was deployed in high permeability, thick, wide sand body and injector was deployed in low permeability, thin, narrow sand body, the recovery of steam flooding in heavy oil reservoir was better. Finally, how the three types of plane heterogeneity influence steam flooding of heavy reservoirs was discussed by adopting a sensitivity analysis method. The results show that the influence of permeability heterogeneity is the largest, thickness heterogeneity is the second, and geometric heterogeneity is the least. This conclusion can help us improve the development of this reservoir. And also, the findings of this study can help for better understanding of properly deployed well pattern and how to effective develop the heavy oil reservoirs of strong plane heterogeneity for other heavy oil reservoirs.

Well pattern deployment and optimization in low-permeability glutenite reservoirs: A case of glutenite reservoirs in Sha 4 member of Yong 1

Low-permeability glutenite reservoir pattern deployment and pattern optimization are important for its efficient development. In this paper, taking the glutenite reservoir in Sha 4 member of Yong1 as an example, the numerical simulation method and percolation theory are used to study the influence of sediment source and in-situ stress direction on well pattern deployment. Then, the well pattern of the low-permeability glutenite reservoir was optimized, and finally the optimized well pattern parameters are designed. It is concluded that ① When injection wells are deployed along the direction of in-situ stress, the injected water can easily form linear displacement, which can effectively increase the volume of injected water and achieve a best development effect. ②The 5 point well pattern has the best development effect, and it belongs to the form of strong injection and strong production well patterns, which can effectively solve the problem of poor injection ability of glutenite reservoirs. ③For anisotropic reservoirs, deformed well patterns can be used to achieve equilibrium displacement. The injection-production well distance of the deformed well pattern in different directions is mainly controlled by the reservoir permeability.

Commercial production potential evaluation of injection-production mode for CH-Bk hydrate reservoir and investigation of its stimulated potential by fracture network

In this study, the productivity of depressurisation combined with thermal stimulation using the injection-production mode (D + Ti) in a CH-Bk reservoir (a natural gas hydrate reservoir exhibiting a low permeability and lack of impermeable boundaries) was explored. By exploring the influence of production parameters and well patterns on hydrate development, the challenges faced in the development of D + Ti and its commercial production potential were explored. Furthermore, the stimulation potential of the fracture network on D + Ti was investigated. The results showed that the interlayer contradiction and the low methane flow capacity between the injection-production well led to poor production ability and insensitivity to production parameters for D + Ti. The permeable caprocks limited the well pattern infilling potential of D + Ti. These defects made it impossible for D + Ti to obtain commercial production in the CH-Bk reservoir. The fracture network significantly improved the productivity and well pattern infilling potential of D + Ti. In particular, the gas production rate and production degree of the five-spot well increased by 6.5 and 7 times, respectively, after network fracturing, reaching commercial standards. Thus, D + Ti combined with network fracturing can be a promising mode for CH-Bk development. This study can provide meaningful guidance for future CH-Bk trial production and commercial development.

Calculation of Average Reservoir Pore Pressure Based on Surface Displacement Using Image-To-Image Convolutional Neural Network Model

The average pore pressure during oil formation is an important parameter for measuring the energy required for the oil formation and the capacity of injection–production wells. In past studies, the average pore pressure has been derived mainly from pressure build-up test results. However, such tests are expensive and time-consuming. The surface displacement of an oilfield is the result of change in the formation pore pressure, but no method is available for calculating the formation pore pressure based on the surface displacement. Therefore, in this study, the vertical displacement of the Earth’s surface was used to calculate changes in reservoir pore pressure. We employed marker-stakes to measure ground displacement. We used an improved image-to-image convolutional neural network (CNN) that does not include pooling layers or full-connection layers and uses a new loss function. We used the forward evolution method to produce training samples with labels. The CNN completed self-training using these samples. Then, machine learning was used to invert the surface vertical displacement to change the pore pressure in the oil reservoir. The method was tested in a block of the Sazhong X development zone in the Daqing Oilfield in China. The results showed that the variation in the formation pore pressure was 83.12%, in accordance with the results of 20 groups of pressure build-up tests within the range of the marker-stake measurements. Thus, the proposed method is less expensive, and faster than existing methods.

Impact of fracture shear dilation on long-term heat extraction in Enhanced Geothermal Systems: Insights from a fully-coupled thermo-hydro-mechanical simulation

Shear dilation of fractures has been recognized as a main mechanism of permeability enhancement by hydraulic stimulation in Enhanced Geothermal Systems (EGSs); however, the interactive role of fracture shear dilation and thermo-hydro-mechanical (THM) coupling processes in long-term heat extraction performance of EGSs remains unclear. In this study, we develop a novel THM coupling model based on the discrete fracture network approach, which can realistically capture important processes including hybrid normal-shear deformation of fractures, thermal expansion of rocks, fluid flow in both fractures and rocks, and heat convection/conduction as well as local thermal non-equilibrium effect and changes in physical parameters of fluid. We quantitatively investigate the effects of fracture network geometries and geomechanical boundary constraints on fracture shear dilatancy, and the resulting heat transfer characteristics of EGSs. Numerical results reveal that shear dilation of fractures can be triggered by transient pore pressurization and thermal stress under anisotropic in-situ stress condition, and would severely engender flow channeling as well as anisotropic heat transfer, which strongly impact the heat extraction performance. The production temperature tends to be overestimated while the thermal production rate may be underestimated, if the shear dilatational behavior is not incorporated. Increased in-situ stress ratio and injection/production pressure would magnify the effects of shear dilation, and lead to considerable enhancement of fracture permeability, eventually resulting in much earlier and quicker temperature drop. Excessive increase of fracture density and the location of injection-production wells parallel to potential channelized flow paths, formed by intersected fractures preferentially oriented for shear sliding, tend to form short circulating flow paths and reduce the heat extraction performance. Our study demonstrates the importance of considering fracture shear dilation and fully-coupled THM behaviors when evaluating the long-term performance and efficiency of heat extraction in EGSs.

Design and productivity evaluation of multi-lateral well enhanced geothermal development system

Enhanced geothermal development system is an effective means to develop hot dry rock geothermal resources, and its reasonable structural design is crucial to the efficient exploitation of hot dry rocks. In this paper, a multi-lateral well enhanced geothermal development system, which is composed of one low-permeability thermal reservoir, three multi-lateral injection wells, three multi-lateral production wells and three artificial fractures, was designed based on the traditional dual-well development model. Then, a 3D hydrothermal coupling numerical evaluation model was established by using the local heat balance method, and its accuracy and reliability were verified according to Lauwerier analytical theory of fractured flow and heat transfer. Finally, the influence of reservoir parameters, well layout parameters, and injection-production parameters on the heat production performance of this enhanced geothermal development system were explored based on the water-rock coupling mechanism inside the reservoir in the process of thermal production. And the following research results were obtained. First, the “rock invasion effect” of the cold front in the fractures of the multi-lateral well development system is stronger than that in the matrix. Increasing the reservoir permeability can improve the internal heat transfer effect, but also enhances the “invasion performance” of cold front. Second, the annual thermal energy extraction of the system gradually decreases over time and it also decreases with the increase of the injection temperature. It increases with the increase of the reservoir permeability in the early stage of the operation, but decreases greatly after the completion of the thermal breakthrough. Third, the system's thermal energy extraction rate and production mass flow rate are less influenced by reservoir porosity and injection temperature, but they decrease with the increase of the vertical spacing of injection-production wells. Fourth, the production temperature decreases greatly with the increase of the reservoir permeability, increases with the increase of the reservoir porosity, and decreases with the decrease of the vertical spacing of injection-production wells. Fifth, the heat production performance of the system in the early stage can be improved by increasing the length of the production well, and the heat production capacity of the system can be enhanced to a certain degree by increasing the injection-production pressure difference, but excessive pressure difference will impact the service life of the reservoir seriously.

Analysis of Interwell Connectivity of Tracer Monitoring in Carbonate Fracture-Vuggy Reservoir: Taking T-Well Group of Tahe Oilfield as an Example

Carbonate fracture-vuggy reservoirs are one of the hot spots in oil and gas exploration and development. However, it is extremely difficult to describe the internal spatial structure of the fracture-vuggy unit and understand the interwell connection relationship. As a method to measure reservoir characteristics and feedback reservoir production information directly according to the detected concentration curve, interwell tracer technology provides a direct measure for people to understand the law of oil-water movement and reservoir heterogeneity and is widely used in various domestic oil fields. Based on the flow law of tracer and the CFD flow simulation basic model, this paper establishes the physical conceptual model and studies the influence of three physical parameters (the flow velocity of the fluid passing through the connected channel, diameter of the connected channel, and length of the connected channel) on the concentration curve at the outlet. In addition, the influence of different interwell connection modes on tracer concentration was studied and classified scientifically. According to the simulation, the tracer concentration curve can be classified into three types: unimodal curve, bimodal curve, and multimodal curve. Finally, the injection-production well group in the T-well area of the Tahe Oilfield is taken as an example, the connection mode between injection and production wells in this well area is further discussed and has been verified, which can be used as a reference for the connectivity analysis of similar carbonate reservoirs.

Discussion and application of establishing oil saturation model by stages

Most of the old oilfields in China have entered the stage of ultra-high water cut development. In order to guide drilling wells and further exploitation, it is necessary to describe the remaining oil distribution at present accurately and quantitatively. At the same time, the focus of work should be shifted to the study of remaining oil distribution between wells. For the oilfields with wide area, large thickness, long history of production and many injection production wells, the calculation of numerical simulation is too large and the grid precision is coarse. Although the traditional modeling method of mixing new and old wells can ensure the grid precision, it cannot represent the current situation of the reservoir and play a guiding role in production, so it needs a new way, ensures the plane and vertical precision of the model (accuracy 10×10×0.5m), and through certain constraints, can accurately describe the current plane and vertical oil saturation distribution law of the oilfield, which provides a new direction for further exploitation of the oilfield.

Research and Application of Chemical Regulating Technology for ISC Injection-Production Wells in Liaohe Oilfield

In Situ Combustion (ISC) Technology is an effective replacement method of oil recovery after Heavy Oil Cyclic Steam Stimulation (CSS) and Steam Flooding (SF). At present, ISC Technology has been carried out mainly in Du 66, Shu 13832, Gao 3618 and Jin 91 blocks of Liaohe Oilfield. However, during the ISC development process, due to the heterogeneity of reservoir growth, the uneven propulsion of fire lines and gas channeling will affect the development effect of ISC reservoir. In this paper, the chemical regulating technology proposed in this paper could improve air injection efficiency, solve the gas channeling problem of production wells, expand the swept volume of air injection and increase the recovery rate of ISC.