The rapid changing near source, multi-stream depositional environment of conglomerate reservoirs leads to severe heterogeneity, complex lithology and physical properties, and large changes of oil layer resistivity. Qu...The rapid changing near source, multi-stream depositional environment of conglomerate reservoirs leads to severe heterogeneity, complex lithology and physical properties, and large changes of oil layer resistivity. Quantitative evaluation of water-flooded layers has become an important but difficult focus for secondary development of oilfields. In this paper, based on the analysis of current problems in quantitative evaluation of water-flooded layers, the Kexia Group conglomerate reservoir of the Sixth District in the Karamay Oilfield was studied. Eight types of conglomerate reservoir lithology were identified effectively by a data mining method combined with the data from sealed coring wells, and then a multi-parameter model for quantitative evaluation of the water-flooded layers of the main oil-bearing lithology was developed. Water production rate, oil saturation and oil productivity index were selected as the characteristic parameters for quantitative evaluation of water-flooded layers of conglomerate reservoirs. Finally, quantitative evaluation criteria and identification rules for water-flooded layers of main oil-bearing lithology formed by integration of the three characteristic parameters of water-flooded layer and undisturbed formation resistivity. This method has been used in evaluation of the water-flooded layers of a conglomerate reservoir in the Karamay Oilfield and achieved good results, improving the interpretation accuracy and compliance rate. It will provide technical support for avoiding perforation of high water-bearing layers and for adjustment of developmental programs.展开更多
To understand the displacement characteristics and remaining oil displacement process by the surfactant/polymer(SP) flooding in cores with different pore structures, the effects of pore structure on the enhanced oil r...To understand the displacement characteristics and remaining oil displacement process by the surfactant/polymer(SP) flooding in cores with different pore structures, the effects of pore structure on the enhanced oil recovery of SP flooding was investigated at the pore, core and field scales through conducting experiments on natural core samples with three typical types of pore structures. First, the in-situ nuclear magnetic resonance core flooding test was carried out to capture the remaining oil variation features in the water flooding and SP flooding through these three types of cores. Subsequently, at the core scale, displacement characteristics and performances of water flooding and SP flooding in these three types of cores were evaluated based on the full-size core flooding tests. Finally, at the field scale, production characteristics of SP flooding in the bimodal sandstone reservoir and multimodal conglomerate reservoir were compared using the actual field production data. The results show: as the pore structure gets more and more complex, the water flooding performance gets poorer, but the incremental recovery factor by SP flooding gets higher;the SP flooding can enhance the producing degree of oil in 1-3 μm pores in the unimodal and bimodal core samples, while it produces largely oil in medium and large pores more than 3 μm in pore radius in the multimodal core sample. The core flooding test using full-size core sample demonstrates that the injection of SP solution can significantly raise up the displacement pressure of the multimodal core sample, and greatly enhance recovery factor by emulsifying the remaining oil and enlarging swept volume. Compared with the sandstone reservoir, the multimodal conglomerate reservoir is more prone to channeling. With proper profile control treatments to efficiently enlarge the microscopic and macroscopic swept volumes, SP flooding in the conglomerate reservoir can contribute to lower water cuts and longer effective durations.展开更多
The micro-nano pore structure of conglomerate in the Lower Karamay Formation of the Xinjiang Oilfield,Junggar Basin,northern China is characterized to predict its impact on fluid reserves and seepage.Authigenic clay m...The micro-nano pore structure of conglomerate in the Lower Karamay Formation of the Xinjiang Oilfield,Junggar Basin,northern China is characterized to predict its impact on fluid reserves and seepage.Authigenic clay minerals are mainly kaolinite(67%),followed by an illite/smectite mixed layer(18%),illite(10%),and chlorite(5%).For kaolinite,pore throats between 0–200 nm are dominant,accounting for 90%of the total pore throats.For illite/smectite mixed layer,pore throats also between 0–200 nm account for nearly 80%,while pore throats between 200-500 nm only account for 15%.For illite,pore throats below 100 nm account for about 80%,while pore throats in the range of 100–500 nm only account for 20%.For chlorite,most throats are below 200 nm.The pore roundness of illite is the highest,while the pore roundness of chlorite is relatively lower.The lower limits of the dynamic and static pore throat radii are 42.128 nm and 72.42 nm,respectively.The theoretical contribution rates of the illite/smectite mixed layer,kaolinite,illite and chlorite to storage/seepage are 60%/45.86%,52.72%/38.18%,37.07%/28.78%and 32.97%/26.3%,respectively.Therefore,the contribution rates of clay minerals in the study area are as follows:illite/smectite mixed layer,kaolinite,illite and chlorite.展开更多
This study aims to clarify the factors influencing oil recovery of surfactant-polymer(SP)flooding and to establish a quantitative calculation model of oil recovery during different displacement stages from water flood...This study aims to clarify the factors influencing oil recovery of surfactant-polymer(SP)flooding and to establish a quantitative calculation model of oil recovery during different displacement stages from water flooding to SP flooding.The conglomerate reservoir of the Badaowan Formation in the seventh block of the Karamay Oilfield is selected as the research object to reveal the start-up mechanism of residual oil and determine the controlling factors of oil recovery through SP flooding experiments of natural cores and microetching models.The experimental results are used to identify four types of residual oil after water flooding in this conglomerate reservoir with a complex pore structure:oil droplets retained in pore throats by capillary forces,oil cluster trapped at the junction of pores and throats,oil film on the rock surface,isolated oil in dead-ends of flow channel.For the four types of residual oil identified,the SP solution can enhance oil recovery by enlarging the sweep volume and improving the oil displacement efficiency.First,the viscosity-increasing effect of the polymer can effectively reduce the permeability of the displacement liquid phase,change the oil-water mobility ratio,and increase the water absorption.Furthermore,the stronger the shear drag force of the SP solution,the more the crude oil in a porous medium is displaced.Second,the surfactant can change the rock wettability and reduce the absorption capacity of residual oil by lowering interfacial tension.At the same time,the emulsification further increases the viscosity of the SP solution,and the residual oil is recovered effectively under the combined effect of the above two factors.For the four start-up mechanisms of residual oil identified after water flooding,enlarging the sweep volume and improving the oil displacement efficiency are interdependent,but their contribution to enhanced oil recovery are different.The SP flooding system primarily enlarges the sweep volume by increasing viscosity of solution to start two kinds of residual oil such as oil droplet retained in pore throats and isolated oil in dead-ends of flow channel,and primarily improves the oil displacement efficiency by lowing interfacial tension of oil phase to start two kinds of residual oil such as oil cluster trapped at the junction of pores and oil film on the rock surface.On this basis,the experimental results of the oil displacement from seven natural cores show that the pore structure of the reservoir is the main factor influencing water flooding recovery,while the physical properties and original oil saturation have relatively little influence.The main factor influencing SP flooding recovery is the physical and chemical properties of the solution itself,which primarily control the interfacial tension and solution viscosity in the reservoir.The residual oil saturation after water flooding is the material basis of SP flooding,and it is the second-most dominant factor controlling oil recovery.Combined with the analysis results of the influencing factors and reservoir parameters,the water flooding recovery index and SP flooding recovery index are defined to further establish quantitative calculation models of oil recovery under different displacement modes.The average relative errors of the two models are 4.4%and 2.5%,respectively;thus,they can accurately predict the oil recovery of different displacement stages and the ultimate reservoir oil recovery.展开更多
This paper is mainly about the calculation of reservoir parameters and theinterpretation method for identifying oil/water beds in Ke82 well areas of Junggar basin. It isdifficult to determine the reservoir parameters ...This paper is mainly about the calculation of reservoir parameters and theinterpretation method for identifying oil/water beds in Ke82 well areas of Junggar basin. It isdifficult to determine the reservoir parameters with common logging methods such as core calibrationlog because of the diversity of minerals and rocks and the complexity of pore structures in theconglomerate reservoir of Junggar basin. Optimization logging exploration is a good method todetermine the porosity by establishing the multi-mineral model with logging curves based on theintegration of geological, core and well testing data. Permeability is identified by BP algorithm ofneural network. Hydrocarbon saturation is determined by correlating Archie's and Simandouxformulas. Comparing the exploratory result and core data, we can see that these methods areeffective for conglomerate logging exploration. We processed and explained six wells in the Ke82well areas. And actual interpretation has had very good results, 85 % of which conform to welltesting data. Therefore, this technique will be effective for identifying conglomerate parameters.展开更多
The global mobility theory was used to evaluate the experimental results of oil displacement with water of different salinities.The results of scanning electron microscopy,X diffraction of clay minerals,nonlinear seep...The global mobility theory was used to evaluate the experimental results of oil displacement with water of different salinities.The results of scanning electron microscopy,X diffraction of clay minerals,nonlinear seepage and nuclear magnetic resonance experiments and particle migration inhibition experiments before and after water flooding were compared to determine the mechanisms of water sensitive damage and enhanced water flooding mechanism of low permeability sandy conglomerate reservoirs in Wushi region of Beibuwan Basin,China.A production equation of the oil-water two phase flow well considering low-speed non-Darcy seepage and reservoir stress sensitivity was established to evaluate the effect of changes in reservoir properties and oil-water two-phase seepage capacity on reservoir productivity quantitatively,and injection water source suitable for the low permeability sandy conglomerate reservoirs in Wushi region was selected according to dynamic compatibility experimental results of different types of injected water.The seepage capacity of reservoir is the strongest when the injected water is formation water of 2 times salinity.The water-sensitive damage mechanisms of the reservoirs in Wushi region include hydration of clay minerals and particle migration.By increasing the content of cations(especially K+and Mg2+)in the injected water,the water-sensitive damage of the reservoir can be effectively inhibited.The formation water of Weizhou Formation can be used as the injection water source of low permeability sandy conglomerate reservoirs in the Wushi region.展开更多
The origin and depositional characteristics of supported conglomerates in the Mahu Sag, Junggar Basin, Xinjiang, China, are examined. Based on the terminological comparison, modern sedimentary survey and core descript...The origin and depositional characteristics of supported conglomerates in the Mahu Sag, Junggar Basin, Xinjiang, China, are examined. Based on the terminological comparison, modern sedimentary survey and core description, the initial connotation and similarities and differences in definition between supported conglomerates and other similar concepts are discussed, the modern sedimentary environment in which supported conglomerates develop is analyzed, and the sedimentological characteristics of supported conglomerates formed in different depositional environments revealed by the cores of Mahu conglomerate oil field in the Junggar Basin are described. The supported conglomerate is similar in texture to grain supported conglomerate and openwork conglomerate but has differences from them, so it is suggested to keep the term "supported conglomerate", but the formation mechanism of supported conglomerate needs to be re-examined. Through field survey of modern sediments in Baiyanghe alluvial fan, Huangyangquan alluvial fan, and Wulungu Lake in Xinjiang, it is found that supported gravels not only formed by flooding events but also by sieving, avalanching, fluvial sorting as well as wind and wave reworking in the depositional environments such as inter-mountain creek, colluvium fan, gravel channel on gobi and the fan surface, lake beach, delta front, subaerial debris flow and subwater grain-flow etc. Supported gravels could form supported conglomerate after being buried. Supported conglomerates of seven different origins have been recognized in the cores of the Triassic and Permian stratum of Mahu Depression, Junggar Basin, namely, supported conglomerates in gravel channel deposits, in wind reworked channel deposits, in gravel beach bar deposits, in wave reworked delta front deposits, in mouth bar deposits and in debris flow deposits respectively. The study shows the supported conglomerates may be formed by a single depositional event or by multi-events during the post-depositional sedimentary reworking and even in diagenesis stage. Through flume experiment, numerical simulation, empirical model and modern sediment survey, infiltration process of gravelly channel can be reconstructed and the primary pore structure of supported gravel can be estimated. Statistics on physical properties of various types of reservoirs in Triassic Baikouquan Formation of Mahu oilfield show that granule conglomerate and pebbly conglomerate have higher porosity and permeability, while the cobble and coarse pebble conglomerate have lower permeability, which indicates that the supported gravels are easy to be reworked by post depositional filtration and diagenesis, and thus decrease in porosity and permeability.展开更多
Tight conglomerate reservoirs are featured with extremely low permeability,strong heterogeneity and poor water injectivity.CO_(2) huff-n-puff has been considered a promising candidate to enhance oil recovery in tight ...Tight conglomerate reservoirs are featured with extremely low permeability,strong heterogeneity and poor water injectivity.CO_(2) huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs,owing to its advantages in reducing oil viscosity,improving mobility ratio,quickly replenishing formation pressure,and potentially achieving a miscible state.However,reliable inhouse laboratory evaluation of CO_(2) huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure.In this study,we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO_(2) injection in a tight conglomerate reservoir.The impacts of depletion degree,pore volume injection of CO_(2) and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure.Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency(first increased and then decreased)with increased CO_(2) injection volume and soaking time.The lower oil recoveries under excess CO_(2) injection and soaking time were attributed to limited CO_(2) dissolution and asphaltene precipitation.This work guides secure and reliable laboratory design of CO_(2) huff-n-puff in tight reservoirs with high formation pressure.展开更多
文摘The rapid changing near source, multi-stream depositional environment of conglomerate reservoirs leads to severe heterogeneity, complex lithology and physical properties, and large changes of oil layer resistivity. Quantitative evaluation of water-flooded layers has become an important but difficult focus for secondary development of oilfields. In this paper, based on the analysis of current problems in quantitative evaluation of water-flooded layers, the Kexia Group conglomerate reservoir of the Sixth District in the Karamay Oilfield was studied. Eight types of conglomerate reservoir lithology were identified effectively by a data mining method combined with the data from sealed coring wells, and then a multi-parameter model for quantitative evaluation of the water-flooded layers of the main oil-bearing lithology was developed. Water production rate, oil saturation and oil productivity index were selected as the characteristic parameters for quantitative evaluation of water-flooded layers of conglomerate reservoirs. Finally, quantitative evaluation criteria and identification rules for water-flooded layers of main oil-bearing lithology formed by integration of the three characteristic parameters of water-flooded layer and undisturbed formation resistivity. This method has been used in evaluation of the water-flooded layers of a conglomerate reservoir in the Karamay Oilfield and achieved good results, improving the interpretation accuracy and compliance rate. It will provide technical support for avoiding perforation of high water-bearing layers and for adjustment of developmental programs.
基金Supported by China National Science and Technology Major Project(2016ZX05025-003-010) and (2016ZX05010-005).
文摘To understand the displacement characteristics and remaining oil displacement process by the surfactant/polymer(SP) flooding in cores with different pore structures, the effects of pore structure on the enhanced oil recovery of SP flooding was investigated at the pore, core and field scales through conducting experiments on natural core samples with three typical types of pore structures. First, the in-situ nuclear magnetic resonance core flooding test was carried out to capture the remaining oil variation features in the water flooding and SP flooding through these three types of cores. Subsequently, at the core scale, displacement characteristics and performances of water flooding and SP flooding in these three types of cores were evaluated based on the full-size core flooding tests. Finally, at the field scale, production characteristics of SP flooding in the bimodal sandstone reservoir and multimodal conglomerate reservoir were compared using the actual field production data. The results show: as the pore structure gets more and more complex, the water flooding performance gets poorer, but the incremental recovery factor by SP flooding gets higher;the SP flooding can enhance the producing degree of oil in 1-3 μm pores in the unimodal and bimodal core samples, while it produces largely oil in medium and large pores more than 3 μm in pore radius in the multimodal core sample. The core flooding test using full-size core sample demonstrates that the injection of SP solution can significantly raise up the displacement pressure of the multimodal core sample, and greatly enhance recovery factor by emulsifying the remaining oil and enlarging swept volume. Compared with the sandstone reservoir, the multimodal conglomerate reservoir is more prone to channeling. With proper profile control treatments to efficiently enlarge the microscopic and macroscopic swept volumes, SP flooding in the conglomerate reservoir can contribute to lower water cuts and longer effective durations.
基金granted by Petro China Innovation Foundation(Grant No.2019D-5007-0214)the National Mega Project of Oil and Gas(Grant No.2017ZX05013005-009)。
文摘The micro-nano pore structure of conglomerate in the Lower Karamay Formation of the Xinjiang Oilfield,Junggar Basin,northern China is characterized to predict its impact on fluid reserves and seepage.Authigenic clay minerals are mainly kaolinite(67%),followed by an illite/smectite mixed layer(18%),illite(10%),and chlorite(5%).For kaolinite,pore throats between 0–200 nm are dominant,accounting for 90%of the total pore throats.For illite/smectite mixed layer,pore throats also between 0–200 nm account for nearly 80%,while pore throats between 200-500 nm only account for 15%.For illite,pore throats below 100 nm account for about 80%,while pore throats in the range of 100–500 nm only account for 20%.For chlorite,most throats are below 200 nm.The pore roundness of illite is the highest,while the pore roundness of chlorite is relatively lower.The lower limits of the dynamic and static pore throat radii are 42.128 nm and 72.42 nm,respectively.The theoretical contribution rates of the illite/smectite mixed layer,kaolinite,illite and chlorite to storage/seepage are 60%/45.86%,52.72%/38.18%,37.07%/28.78%and 32.97%/26.3%,respectively.Therefore,the contribution rates of clay minerals in the study area are as follows:illite/smectite mixed layer,kaolinite,illite and chlorite.
基金supported by the National Natural Science Foundation of China(No.41902141)the Fundamental Research Fund for the Central Universities(No.E1E40403)the PetroChina Innovation Foundation(No.2018D-5007-0103)
文摘This study aims to clarify the factors influencing oil recovery of surfactant-polymer(SP)flooding and to establish a quantitative calculation model of oil recovery during different displacement stages from water flooding to SP flooding.The conglomerate reservoir of the Badaowan Formation in the seventh block of the Karamay Oilfield is selected as the research object to reveal the start-up mechanism of residual oil and determine the controlling factors of oil recovery through SP flooding experiments of natural cores and microetching models.The experimental results are used to identify four types of residual oil after water flooding in this conglomerate reservoir with a complex pore structure:oil droplets retained in pore throats by capillary forces,oil cluster trapped at the junction of pores and throats,oil film on the rock surface,isolated oil in dead-ends of flow channel.For the four types of residual oil identified,the SP solution can enhance oil recovery by enlarging the sweep volume and improving the oil displacement efficiency.First,the viscosity-increasing effect of the polymer can effectively reduce the permeability of the displacement liquid phase,change the oil-water mobility ratio,and increase the water absorption.Furthermore,the stronger the shear drag force of the SP solution,the more the crude oil in a porous medium is displaced.Second,the surfactant can change the rock wettability and reduce the absorption capacity of residual oil by lowering interfacial tension.At the same time,the emulsification further increases the viscosity of the SP solution,and the residual oil is recovered effectively under the combined effect of the above two factors.For the four start-up mechanisms of residual oil identified after water flooding,enlarging the sweep volume and improving the oil displacement efficiency are interdependent,but their contribution to enhanced oil recovery are different.The SP flooding system primarily enlarges the sweep volume by increasing viscosity of solution to start two kinds of residual oil such as oil droplet retained in pore throats and isolated oil in dead-ends of flow channel,and primarily improves the oil displacement efficiency by lowing interfacial tension of oil phase to start two kinds of residual oil such as oil cluster trapped at the junction of pores and oil film on the rock surface.On this basis,the experimental results of the oil displacement from seven natural cores show that the pore structure of the reservoir is the main factor influencing water flooding recovery,while the physical properties and original oil saturation have relatively little influence.The main factor influencing SP flooding recovery is the physical and chemical properties of the solution itself,which primarily control the interfacial tension and solution viscosity in the reservoir.The residual oil saturation after water flooding is the material basis of SP flooding,and it is the second-most dominant factor controlling oil recovery.Combined with the analysis results of the influencing factors and reservoir parameters,the water flooding recovery index and SP flooding recovery index are defined to further establish quantitative calculation models of oil recovery under different displacement modes.The average relative errors of the two models are 4.4%and 2.5%,respectively;thus,they can accurately predict the oil recovery of different displacement stages and the ultimate reservoir oil recovery.
文摘This paper is mainly about the calculation of reservoir parameters and theinterpretation method for identifying oil/water beds in Ke82 well areas of Junggar basin. It isdifficult to determine the reservoir parameters with common logging methods such as core calibrationlog because of the diversity of minerals and rocks and the complexity of pore structures in theconglomerate reservoir of Junggar basin. Optimization logging exploration is a good method todetermine the porosity by establishing the multi-mineral model with logging curves based on theintegration of geological, core and well testing data. Permeability is identified by BP algorithm ofneural network. Hydrocarbon saturation is determined by correlating Archie's and Simandouxformulas. Comparing the exploratory result and core data, we can see that these methods areeffective for conglomerate logging exploration. We processed and explained six wells in the Ke82well areas. And actual interpretation has had very good results, 85 % of which conform to welltesting data. Therefore, this technique will be effective for identifying conglomerate parameters.
基金Supported by the China National Science and Technology Major Project(2016ZX05024006).
文摘The global mobility theory was used to evaluate the experimental results of oil displacement with water of different salinities.The results of scanning electron microscopy,X diffraction of clay minerals,nonlinear seepage and nuclear magnetic resonance experiments and particle migration inhibition experiments before and after water flooding were compared to determine the mechanisms of water sensitive damage and enhanced water flooding mechanism of low permeability sandy conglomerate reservoirs in Wushi region of Beibuwan Basin,China.A production equation of the oil-water two phase flow well considering low-speed non-Darcy seepage and reservoir stress sensitivity was established to evaluate the effect of changes in reservoir properties and oil-water two-phase seepage capacity on reservoir productivity quantitatively,and injection water source suitable for the low permeability sandy conglomerate reservoirs in Wushi region was selected according to dynamic compatibility experimental results of different types of injected water.The seepage capacity of reservoir is the strongest when the injected water is formation water of 2 times salinity.The water-sensitive damage mechanisms of the reservoirs in Wushi region include hydration of clay minerals and particle migration.By increasing the content of cations(especially K+and Mg2+)in the injected water,the water-sensitive damage of the reservoir can be effectively inhibited.The formation water of Weizhou Formation can be used as the injection water source of low permeability sandy conglomerate reservoirs in the Wushi region.
基金Supported by the the National Natural Science Foundation of China(41772094)China National Science and Technology Major Project(2016ZX05027-002-007)
文摘The origin and depositional characteristics of supported conglomerates in the Mahu Sag, Junggar Basin, Xinjiang, China, are examined. Based on the terminological comparison, modern sedimentary survey and core description, the initial connotation and similarities and differences in definition between supported conglomerates and other similar concepts are discussed, the modern sedimentary environment in which supported conglomerates develop is analyzed, and the sedimentological characteristics of supported conglomerates formed in different depositional environments revealed by the cores of Mahu conglomerate oil field in the Junggar Basin are described. The supported conglomerate is similar in texture to grain supported conglomerate and openwork conglomerate but has differences from them, so it is suggested to keep the term "supported conglomerate", but the formation mechanism of supported conglomerate needs to be re-examined. Through field survey of modern sediments in Baiyanghe alluvial fan, Huangyangquan alluvial fan, and Wulungu Lake in Xinjiang, it is found that supported gravels not only formed by flooding events but also by sieving, avalanching, fluvial sorting as well as wind and wave reworking in the depositional environments such as inter-mountain creek, colluvium fan, gravel channel on gobi and the fan surface, lake beach, delta front, subaerial debris flow and subwater grain-flow etc. Supported gravels could form supported conglomerate after being buried. Supported conglomerates of seven different origins have been recognized in the cores of the Triassic and Permian stratum of Mahu Depression, Junggar Basin, namely, supported conglomerates in gravel channel deposits, in wind reworked channel deposits, in gravel beach bar deposits, in wave reworked delta front deposits, in mouth bar deposits and in debris flow deposits respectively. The study shows the supported conglomerates may be formed by a single depositional event or by multi-events during the post-depositional sedimentary reworking and even in diagenesis stage. Through flume experiment, numerical simulation, empirical model and modern sediment survey, infiltration process of gravelly channel can be reconstructed and the primary pore structure of supported gravel can be estimated. Statistics on physical properties of various types of reservoirs in Triassic Baikouquan Formation of Mahu oilfield show that granule conglomerate and pebbly conglomerate have higher porosity and permeability, while the cobble and coarse pebble conglomerate have lower permeability, which indicates that the supported gravels are easy to be reworked by post depositional filtration and diagenesis, and thus decrease in porosity and permeability.
基金This study is financially supported by CNPC Innovation Foundation(2020D-5007-0214)Major Strategic Project of CNPC(ZLZX2020-01-04)Beijing Municipal Excellent Talent Training Funds Youth Advanced Individual Project(2018000020124G163)。
文摘Tight conglomerate reservoirs are featured with extremely low permeability,strong heterogeneity and poor water injectivity.CO_(2) huff-n-puff has been considered a promising candidate to enhance oil recovery in tight reservoirs,owing to its advantages in reducing oil viscosity,improving mobility ratio,quickly replenishing formation pressure,and potentially achieving a miscible state.However,reliable inhouse laboratory evaluation of CO_(2) huff-n-puff in natural conglomerate cores is challenging due to the inherent high formation pressure.In this study,we put forward an equivalent method based on the similarity of the miscibility index and Grashof number to acquire a lab-controllable pressure that features the flow characteristics of CO_(2) injection in a tight conglomerate reservoir.The impacts of depletion degree,pore volume injection of CO_(2) and soaking time on ultimate oil recovery in tight cores from the Mahu conglomerate reservoir were successfully tested at an equivalent pressure.Our results showed that oil recovery decreased with increased depletion degree while exhibiting a non-monotonic tendency(first increased and then decreased)with increased CO_(2) injection volume and soaking time.The lower oil recoveries under excess CO_(2) injection and soaking time were attributed to limited CO_(2) dissolution and asphaltene precipitation.This work guides secure and reliable laboratory design of CO_(2) huff-n-puff in tight reservoirs with high formation pressure.
