The effects of gravity,capillary force,and viscous force on the migration characteristics of oil and gas interface in oxygen-reduced air-assisted gravity drainage(OAGD)were studied through a two-dimensional visualizat...The effects of gravity,capillary force,and viscous force on the migration characteristics of oil and gas interface in oxygen-reduced air-assisted gravity drainage(OAGD)were studied through a two-dimensional visualization model.The effects of bond number,capillary number and low-temperature oxidation on OAGD recovery were studied by long core displacement experiments.On this basis,the low-temperature oxidation number was introduced and its relationship with the OAGD recovery was established.The results show that the shape and changing law of oil and gas front are mainly influenced by gravity,capillary force and viscous force.When the bond number is constant(4.52×10-4),the shape of oil-gas front is controlled by capillary number.When the capillary number is less than 1.68×10-3,the oil and gas interface is stable.When the capillary number is greater than 2.69×10-2,the oil and gas interface shows viscous fingering.When the capillary number is between 1.68×10-3 and 2.69×10-2,the oil and gas interface becomes capillary fingering.The core flooding experiments results show that for OAGD stable flooding,before the gas breakthrough,higher recovery is obtained in higher gravity number and lower capillary number.In this stage,gravity is predominant in controlling OAGD recovery and the oil recovery could be improved by reducing injection velocity.After gas breakthrough,higher recovery was obtained in lower gravity and higher capillary numbers,which means that the viscous force had a significant influence on the recovery.Increasing gas injection velocity in this stage is an effective measure to improve oil recovery.The low-temperature oxidation number has a good correlation with the recovery and can be used to predict the OAGD recovery.展开更多
This paper introduces the results of selecting and breeding a micro-organism, Strain I, and its core model experiment investigation for microbial enhanced oil recovery (MEOR). Strain I was separated from the formation...This paper introduces the results of selecting and breeding a micro-organism, Strain I, and its core model experiment investigation for microbial enhanced oil recovery (MEOR). Strain I was separated from the formation water of the Dagang oil field, with analytical results showing that Strain I is a gram-positive bacillus. A further study revealed that this strain has an excellent tolerance of environmental stresses: It can survive in conditions of 70℃, 30 wt% salinity and pH3.5-9.4. Strain I can metabolize biosurfactants that could increase the oil recovery ratio, use crude oil as the single carbon source, and decompose long-chain paraffin with a large molecular weight into short-chain paraffin with a small molecular weight. The core model experiment shows that Strain I enhances oil recovery well. Using 2 vol% of the fermentation solution of Strain I to displace the crude oil in the synthetic plastic bonding core could increase the recovery ratio by 21.6%.展开更多
Laboratory experiments,numerical simulations and fracturing technology were combined to address the problems in shale oil recovery by CO_(2)injection.The laboratory experiments were conducted to investigate the displa...Laboratory experiments,numerical simulations and fracturing technology were combined to address the problems in shale oil recovery by CO_(2)injection.The laboratory experiments were conducted to investigate the displacement mechanisms of shale oil extraction by CO_(2)injection,and the influences of CO_(2)pre-pad on shale mechanical properties.Numerical simulations were performed about influences of CO_(2)pre-pad fracturing and puff-n-huff for energy replenishment on the recovery efficiency.The findings obtained were applied to the field tests of CO_(2)pre-pad fracturing and single well puff-n-huff.The results show that the efficiency of CO_(2)puff-n-huff is affected by micro-and nano-scale effect,kerogen,adsorbed oil and so on,and a longer soaking time in a reasonable range leads to a higher exploitation degree of shale oil.In the"injection+soaking"stage,the exploitation degree of heavy hydrocarbons is enhanced by CO_(2)through its effects of solubility-diffusion and mass-transfer.In the"huff"stage,crude oil in large pores is displaced by CO_(2)to surrounding larger pores or bedding fractures and finally flows to the production well.The injection of CO_(2)pre-pad is conducive to keeping the rock brittle and reducing the fracture breakdown pressure,and the CO_(2)is liable to filter along the bedding surface,thereby creating a more complex fracture.Increasing the volume of CO_(2)pre-pad can improve the energizing effect,and enhance the replenishment of formation energy.Moreover,the oil recovery is more enhanced by CO_(2)huff-n-puff with the lower shale matrix permeability,the lower formation pressure,and the larger heavy hydrocarbon content.The field tests demonstrate a good performance with the pressure maintained well after CO_(2)pre-pad fracturing,the formation energy replenished effectively after CO_(2)huff-n-puff in a single well,and the well productivity improved.展开更多
In order to improve the enhanced oil recovery of high-temperature and high-salt oilfields, a novel temperature-resistant and salt-tolerant surfactant （denoted as SDB-7） was synthesized and evaluated for the Tahe Oil...In order to improve the enhanced oil recovery of high-temperature and high-salt oilfields, a novel temperature-resistant and salt-tolerant surfactant （denoted as SDB-7） was synthesized and evaluated for the Tahe Oilfield （Xinjiang, China）, which is representative of high-temperature and high-salt oilfields. It has a central reservoir temperature of 140 ℃ and salinity of 22.6× 10^4 mg/L. The temperature-resistant and salt-tolerant performance, interfacial activity, oil displacement efficiency, aging properties, and adsorption properties of the synthesized surfactant were evaluated for Tahe Oilfield flooding. The results showed that the SDB-7 was temperature-resistant and salt-tolerant capacity of 140 ℃ and 22.6×10^4 rag/ L, respectively, oil displacement efficiency under static condition of 84%, and adsorption loss of 0.4 mg/ g （less than 1 mg/g-oil sand）. In the heat aging experiment （under the temperature of 140 ℃ for 60 days）, the oil-water interracial tension and oil displacement efficiency of SDB-7 were almost unchanged. The oil displacement experiments showed that, under the temperature of 140 ℃ and the salinity of 22.6× 10^4 mg/L, the surfactant SDB-7 can enhance oil recovery by 14.5% after water flooding,suggesting that SDB-7 has a promising application in high temperature and high salinity （HT/HS） reservoir.展开更多
The purpose of this study is to investigate the entire evolution process of shales with various total organic contents(TOC)in order to build models for quantitative evaluation of oil and gas yields and establish metho...The purpose of this study is to investigate the entire evolution process of shales with various total organic contents(TOC)in order to build models for quantitative evaluation of oil and gas yields and establish methods for assessing recoverable oil and gas resources from in-situ conversion of organic matters in shale.Thermal simulation experiments under in-situ conversion conditions were conducted on Chang 7_(3) shales from the Ordos Basin in a semi-open system with large capacity.The results showed that TOC and R_(o) were the key factors affecting the in-situ transformation potential of shale.The remaining oil and gas yields increased linearly with TOC but inconsistently with R_(o).R_(o) ranged 0.75%—1.25%and 1.05%—2.3%,respectively,corresponding to the main oil generation stage and gas generation stage of shale in-situ transformation.Thus a model to evaluate the remaining oil/gas yield with TOC and R_(o) was obtained.The TOC of shale suitable for in-situ conversion should be greater than 6%,whereas its R_(o) should be less than 1.0%.Shales with 0.75%(R_(o))could obtain the best economic benefit.The results provided a theoretical basis and evaluation methodology for predicting the hydrocarbon resources from in-situ conversion of shale and for the identification of the optimum“sweet spots”.The assessment of the Chang 7_(3) shale in the Ordos Basin indicated that the recoverable oil and gas resources from in-situ conversion of organic matters in shale are substantial,with oil and gas resources reaching approximately 450×10^(8) t and 30×10^(12)m^(3),respectively,from an area of 4.27×10^(4) km^(2).展开更多
Taking tight oil in Gaotaizi and Fuyu oil layers of the Upper Cretaceous Qingshankou Formation in northern Songliao Basin as an example, based on analyses of nuclear magnetic resonance and high pressure mercury inject...Taking tight oil in Gaotaizi and Fuyu oil layers of the Upper Cretaceous Qingshankou Formation in northern Songliao Basin as an example, based on analyses of nuclear magnetic resonance and high pressure mercury injection, experiment methods of supercritical carbon dioxide displacement and extraction are firstly employed to quantify crude oil mobility in tight sand reservoirs with different lithologies and oil contents. The results show that, under the conditions of simulating the Cretaceous Qingshankou Formation in the northern Songliao Basin at a temperature of 76-89 °C and a pressure of 35-42 MPa, the lower limit of the porosity of the movable oil is4.4%, and the lower limit of the permeability is 0.015′10-3 mm2. The lower limit of the average pore throat radius is 21 nm. On this basis,a classification standard for three types of tight sand reservoirs is proposed. Type I reservoirs are characterized by the movable fluid saturation larger than 40%, the movable oil ratio(ratio of movable oil to total oil) greater than 30% and the starting pressure gradient in the range of 0.3-0.6 MPa/m; Type II reservoirs are characterized by the movable fluid saturation in the range of 10%–40%, the movable oil ratio in the range of 5%–30% and the starting pressure gradient in the range of 0.6–1.0 MPa/m; Type III reservoirs are characterized by the movable fluid saturation less than 10% in general, the movable oil ratio less than 5%, and the starting pressure gradient greater than1.0 MPa/m. The fluid mobility in tight sand reservoirs is mainly affected by diagenesis and sedimentary environment. Reservoirs with depth lower than 2000 m are dominated by type I reservoir, whereas those with greater depth are dominated by type I and II reservoirs.Reservoirs in inner delta-front facies are dominated by type I reservoir, whereas those in outer delta-front facies and shore-shallow lacustrine facies are dominated by type II and III reservoirs.展开更多
To improve the oil recovery and economic efficiency in heavy oil reservoirs in late steam flooding,taking J6 Block of Xinjiang Oilfield as the research object,3D physical modeling experiments of steam flooding,CO2-foa...To improve the oil recovery and economic efficiency in heavy oil reservoirs in late steam flooding,taking J6 Block of Xinjiang Oilfield as the research object,3D physical modeling experiments of steam flooding,CO2-foam assisted steam flooding,and CO2 assisted steam flooding under different perforation conditions are conducted,and CO2-assisted steam flooding is proposed for reservoirs in the late stage of steam flooding.The experimental results show that after adjusting the perforation in late steam flooding,the CO2 assisted steam flooding formed a lateral expansion of the steam chamber in the middle and lower parts of the injection well and a development mode for the production of overriding gravity oil drainage in the top chamber of the production well;high temperature water,oil,and CO2 formed stable low-viscosity quasi-single-phase emulsified fluid;and CO2 acted as a thermal insulation in the steam chamber at the top,reduced the steam partial pressure inside the steam chamber,and effectively improved the heat efficiency of injected steam.Based on the three-dimensional physical experiments and the developed situation of the J6 block in Xinjiang Oilfield,the CO2 assisted steam flooding for the J6 block was designed.The application showed that the CO2 assisted steam flooding made the oil vapor ratio increase from 0.12 to 0.16 by 34.0%,the oil recovery increase from 16.1%to 21.5%,and the final oil recovery goes up to 66.5%compared to steam flooding after perforation adjustment.展开更多
Oxidative desulfurization (ODS) of Azeri crude oil was studied under the electric field.By means of orthogonal experiments,the optimum conditions for desulfurization of crude oil were identified,while the effect of ox...Oxidative desulfurization (ODS) of Azeri crude oil was studied under the electric field.By means of orthogonal experiments,the optimum conditions for desulfurization of crude oil were identified,while the effect of oxidative desulfurization under the electric field was compared with that of the single oxidative desulfurization method.The test results showed that the desulfurization reaction taking place under the electric field would be better than the traditional method.The desulfurization rate of crude oil could reach up to 77.06% at 115 ℃ at a distilled water amount of 10 m%,a desulfurizer dosage of 200 μg/g,and a demulsifier dosage of 50 μg/g.展开更多
Based on the systematic summary of current research on oil bank, the definition of oil bank in the process of fire flooding and its quantitative indices were proposed; and a new one-dimensional positive dry-fire flood...Based on the systematic summary of current research on oil bank, the definition of oil bank in the process of fire flooding and its quantitative indices were proposed; and a new one-dimensional positive dry-fire flooding model considering temperature gradient was established based on the steady flow theory of gas and liquid phases. Single factor analysis and orthogonal experiments were adopted to verify the reliability and reveal the formation mechanisms and the controlling factors of the oil bank. Then the optimal conditions for the oil bank to form were discussed. The study results show the formation of the oil bank is controlled by 3 factors:(1) Oil bank would come into being within a certain temperature interval and above a critical value of temperature gradient(absolute value), with temperature too high or too low and temperature gradient absolute value lower than the critical value, the oil bank couldn't form.(2) For fire flooding process in heavy oil reservoirs, the viscosity of oil influences the width of oil bank and the speed at which oil bank forms; the lower the oil viscosity is, the wider the oil bank is and the faster the oil bank forms.(3) Oil saturation could affect the developing temperature and speed of oil bank. The favorable temperature at which oil bank develops gets lower and the accumulating speed of oil gets faster when the oil saturation is higher. By orthogonal experiments with the model, the optimal combinations of reservoir conditions for forming oil bank during fire flooding in heavy oil reservoirs can be worked out.展开更多
基金Supported by the National Science and Technology Major Project(ZX20170054)
文摘The effects of gravity,capillary force,and viscous force on the migration characteristics of oil and gas interface in oxygen-reduced air-assisted gravity drainage(OAGD)were studied through a two-dimensional visualization model.The effects of bond number,capillary number and low-temperature oxidation on OAGD recovery were studied by long core displacement experiments.On this basis,the low-temperature oxidation number was introduced and its relationship with the OAGD recovery was established.The results show that the shape and changing law of oil and gas front are mainly influenced by gravity,capillary force and viscous force.When the bond number is constant(4.52×10-4),the shape of oil-gas front is controlled by capillary number.When the capillary number is less than 1.68×10-3,the oil and gas interface is stable.When the capillary number is greater than 2.69×10-2,the oil and gas interface shows viscous fingering.When the capillary number is between 1.68×10-3 and 2.69×10-2,the oil and gas interface becomes capillary fingering.The core flooding experiments results show that for OAGD stable flooding,before the gas breakthrough,higher recovery is obtained in higher gravity number and lower capillary number.In this stage,gravity is predominant in controlling OAGD recovery and the oil recovery could be improved by reducing injection velocity.After gas breakthrough,higher recovery was obtained in lower gravity and higher capillary numbers,which means that the viscous force had a significant influence on the recovery.Increasing gas injection velocity in this stage is an effective measure to improve oil recovery.The low-temperature oxidation number has a good correlation with the recovery and can be used to predict the OAGD recovery.
文摘This paper introduces the results of selecting and breeding a micro-organism, Strain I, and its core model experiment investigation for microbial enhanced oil recovery (MEOR). Strain I was separated from the formation water of the Dagang oil field, with analytical results showing that Strain I is a gram-positive bacillus. A further study revealed that this strain has an excellent tolerance of environmental stresses: It can survive in conditions of 70℃, 30 wt% salinity and pH3.5-9.4. Strain I can metabolize biosurfactants that could increase the oil recovery ratio, use crude oil as the single carbon source, and decompose long-chain paraffin with a large molecular weight into short-chain paraffin with a small molecular weight. The core model experiment shows that Strain I enhances oil recovery well. Using 2 vol% of the fermentation solution of Strain I to displace the crude oil in the synthetic plastic bonding core could increase the recovery ratio by 21.6%.
基金Supported by Basic and Forward-Looking Project of the Science and Technology Department of SINOPEC(P22213-4)。
文摘Laboratory experiments,numerical simulations and fracturing technology were combined to address the problems in shale oil recovery by CO_(2)injection.The laboratory experiments were conducted to investigate the displacement mechanisms of shale oil extraction by CO_(2)injection,and the influences of CO_(2)pre-pad on shale mechanical properties.Numerical simulations were performed about influences of CO_(2)pre-pad fracturing and puff-n-huff for energy replenishment on the recovery efficiency.The findings obtained were applied to the field tests of CO_(2)pre-pad fracturing and single well puff-n-huff.The results show that the efficiency of CO_(2)puff-n-huff is affected by micro-and nano-scale effect,kerogen,adsorbed oil and so on,and a longer soaking time in a reasonable range leads to a higher exploitation degree of shale oil.In the"injection+soaking"stage,the exploitation degree of heavy hydrocarbons is enhanced by CO_(2)through its effects of solubility-diffusion and mass-transfer.In the"huff"stage,crude oil in large pores is displaced by CO_(2)to surrounding larger pores or bedding fractures and finally flows to the production well.The injection of CO_(2)pre-pad is conducive to keeping the rock brittle and reducing the fracture breakdown pressure,and the CO_(2)is liable to filter along the bedding surface,thereby creating a more complex fracture.Increasing the volume of CO_(2)pre-pad can improve the energizing effect,and enhance the replenishment of formation energy.Moreover,the oil recovery is more enhanced by CO_(2)huff-n-puff with the lower shale matrix permeability,the lower formation pressure,and the larger heavy hydrocarbon content.The field tests demonstrate a good performance with the pressure maintained well after CO_(2)pre-pad fracturing,the formation energy replenished effectively after CO_(2)huff-n-puff in a single well,and the well productivity improved.
基金the China National High Technology Research and Development Program (No. 2013AA064301)National Natural Science Foundation of China (No. 51274210) for financial support
文摘In order to improve the enhanced oil recovery of high-temperature and high-salt oilfields, a novel temperature-resistant and salt-tolerant surfactant （denoted as SDB-7） was synthesized and evaluated for the Tahe Oilfield （Xinjiang, China）, which is representative of high-temperature and high-salt oilfields. It has a central reservoir temperature of 140 ℃ and salinity of 22.6× 10^4 mg/L. The temperature-resistant and salt-tolerant performance, interfacial activity, oil displacement efficiency, aging properties, and adsorption properties of the synthesized surfactant were evaluated for Tahe Oilfield flooding. The results showed that the SDB-7 was temperature-resistant and salt-tolerant capacity of 140 ℃ and 22.6×10^4 rag/ L, respectively, oil displacement efficiency under static condition of 84%, and adsorption loss of 0.4 mg/ g （less than 1 mg/g-oil sand）. In the heat aging experiment （under the temperature of 140 ℃ for 60 days）, the oil-water interracial tension and oil displacement efficiency of SDB-7 were almost unchanged. The oil displacement experiments showed that, under the temperature of 140 ℃ and the salinity of 22.6× 10^4 mg/L, the surfactant SDB-7 can enhance oil recovery by 14.5% after water flooding,suggesting that SDB-7 has a promising application in high temperature and high salinity （HT/HS） reservoir.
基金supported by PetroChina Co Ltd.(Grant number:2015D-4810-02,2018YCQ03,2021DJ52)National Natural Science Foundation of China(Grant number:42172170)
文摘The purpose of this study is to investigate the entire evolution process of shales with various total organic contents(TOC)in order to build models for quantitative evaluation of oil and gas yields and establish methods for assessing recoverable oil and gas resources from in-situ conversion of organic matters in shale.Thermal simulation experiments under in-situ conversion conditions were conducted on Chang 7_(3) shales from the Ordos Basin in a semi-open system with large capacity.The results showed that TOC and R_(o) were the key factors affecting the in-situ transformation potential of shale.The remaining oil and gas yields increased linearly with TOC but inconsistently with R_(o).R_(o) ranged 0.75%—1.25%and 1.05%—2.3%,respectively,corresponding to the main oil generation stage and gas generation stage of shale in-situ transformation.Thus a model to evaluate the remaining oil/gas yield with TOC and R_(o) was obtained.The TOC of shale suitable for in-situ conversion should be greater than 6%,whereas its R_(o) should be less than 1.0%.Shales with 0.75%(R_(o))could obtain the best economic benefit.The results provided a theoretical basis and evaluation methodology for predicting the hydrocarbon resources from in-situ conversion of shale and for the identification of the optimum“sweet spots”.The assessment of the Chang 7_(3) shale in the Ordos Basin indicated that the recoverable oil and gas resources from in-situ conversion of organic matters in shale are substantial,with oil and gas resources reaching approximately 450×10^(8) t and 30×10^(12)m^(3),respectively,from an area of 4.27×10^(4) km^(2).
基金Supported by the PetroChina Science and Technology Project(2012E-2603-06)
文摘Taking tight oil in Gaotaizi and Fuyu oil layers of the Upper Cretaceous Qingshankou Formation in northern Songliao Basin as an example, based on analyses of nuclear magnetic resonance and high pressure mercury injection, experiment methods of supercritical carbon dioxide displacement and extraction are firstly employed to quantify crude oil mobility in tight sand reservoirs with different lithologies and oil contents. The results show that, under the conditions of simulating the Cretaceous Qingshankou Formation in the northern Songliao Basin at a temperature of 76-89 °C and a pressure of 35-42 MPa, the lower limit of the porosity of the movable oil is4.4%, and the lower limit of the permeability is 0.015′10-3 mm2. The lower limit of the average pore throat radius is 21 nm. On this basis,a classification standard for three types of tight sand reservoirs is proposed. Type I reservoirs are characterized by the movable fluid saturation larger than 40%, the movable oil ratio(ratio of movable oil to total oil) greater than 30% and the starting pressure gradient in the range of 0.3-0.6 MPa/m; Type II reservoirs are characterized by the movable fluid saturation in the range of 10%–40%, the movable oil ratio in the range of 5%–30% and the starting pressure gradient in the range of 0.6–1.0 MPa/m; Type III reservoirs are characterized by the movable fluid saturation less than 10% in general, the movable oil ratio less than 5%, and the starting pressure gradient greater than1.0 MPa/m. The fluid mobility in tight sand reservoirs is mainly affected by diagenesis and sedimentary environment. Reservoirs with depth lower than 2000 m are dominated by type I reservoir, whereas those with greater depth are dominated by type I and II reservoirs.Reservoirs in inner delta-front facies are dominated by type I reservoir, whereas those in outer delta-front facies and shore-shallow lacustrine facies are dominated by type II and III reservoirs.
基金Supported by the China National Science and Technology Major Project(2016ZX05012-002).
文摘To improve the oil recovery and economic efficiency in heavy oil reservoirs in late steam flooding,taking J6 Block of Xinjiang Oilfield as the research object,3D physical modeling experiments of steam flooding,CO2-foam assisted steam flooding,and CO2 assisted steam flooding under different perforation conditions are conducted,and CO2-assisted steam flooding is proposed for reservoirs in the late stage of steam flooding.The experimental results show that after adjusting the perforation in late steam flooding,the CO2 assisted steam flooding formed a lateral expansion of the steam chamber in the middle and lower parts of the injection well and a development mode for the production of overriding gravity oil drainage in the top chamber of the production well;high temperature water,oil,and CO2 formed stable low-viscosity quasi-single-phase emulsified fluid;and CO2 acted as a thermal insulation in the steam chamber at the top,reduced the steam partial pressure inside the steam chamber,and effectively improved the heat efficiency of injected steam.Based on the three-dimensional physical experiments and the developed situation of the J6 block in Xinjiang Oilfield,the CO2 assisted steam flooding for the J6 block was designed.The application showed that the CO2 assisted steam flooding made the oil vapor ratio increase from 0.12 to 0.16 by 34.0%,the oil recovery increase from 16.1%to 21.5%,and the final oil recovery goes up to 66.5%compared to steam flooding after perforation adjustment.
基金financial supports from the Science and Technology Office of Liaoning Province (Project number:2008403001)the Liaoning Provincial Office of Education for Innovation Team (Project number:2009T002)
文摘Oxidative desulfurization (ODS) of Azeri crude oil was studied under the electric field.By means of orthogonal experiments,the optimum conditions for desulfurization of crude oil were identified,while the effect of oxidative desulfurization under the electric field was compared with that of the single oxidative desulfurization method.The test results showed that the desulfurization reaction taking place under the electric field would be better than the traditional method.The desulfurization rate of crude oil could reach up to 77.06% at 115 ℃ at a distilled water amount of 10 m%,a desulfurizer dosage of 200 μg/g,and a demulsifier dosage of 50 μg/g.
基金Supported by the China National Science and Technology Major Project(2016ZX05012-004)the PetroChina Science and Technology Project(2016B-1402)
文摘Based on the systematic summary of current research on oil bank, the definition of oil bank in the process of fire flooding and its quantitative indices were proposed; and a new one-dimensional positive dry-fire flooding model considering temperature gradient was established based on the steady flow theory of gas and liquid phases. Single factor analysis and orthogonal experiments were adopted to verify the reliability and reveal the formation mechanisms and the controlling factors of the oil bank. Then the optimal conditions for the oil bank to form were discussed. The study results show the formation of the oil bank is controlled by 3 factors:(1) Oil bank would come into being within a certain temperature interval and above a critical value of temperature gradient(absolute value), with temperature too high or too low and temperature gradient absolute value lower than the critical value, the oil bank couldn't form.(2) For fire flooding process in heavy oil reservoirs, the viscosity of oil influences the width of oil bank and the speed at which oil bank forms; the lower the oil viscosity is, the wider the oil bank is and the faster the oil bank forms.(3) Oil saturation could affect the developing temperature and speed of oil bank. The favorable temperature at which oil bank develops gets lower and the accumulating speed of oil gets faster when the oil saturation is higher. By orthogonal experiments with the model, the optimal combinations of reservoir conditions for forming oil bank during fire flooding in heavy oil reservoirs can be worked out.
