Volume 31,Issue 1,2024 Table of Contents
YIN Shuai
,
TIAN Tao
,
LI Junlu
,
WANG Ruifei
,
ZHOU Xue
,
LI Yurong
,
LIU Weiming
,
LI Xiangxue
,
ZHANG Lei
2024, 31(1):1-12.
DOI: 10.13673/j.pgre.202305040
Abstract:
Fault-fracture bodies are developed in the southwestern margin of Ordos Basin， and thus， the study on the controlling effect of fracture bodies on sweet spot distribution of Yanchang Formation reservoirs needs to be deepened. In this paper， based on the extensive seismic and logging interpretation results， the characteristics of fault-fracture bodies are described from the point of view of their evolution mechanism， and then the controlling effect of fault-fracture bodies on oil and gas is systematically discussed. The results show that vertical strike-slip faults are developed in the southwest margin of Ordos Basin， with Y-shaped， flower-like， and negative flower-like structures. The faults usually pass through the bottom of Chang 7 Member， the bottom of Yan’an Formation，the bottom of the Cretaceous series， and the basement. Some of the faults retain the early reverse fault properties， indicating that the late inversion degree is not complete. The main fault has different shapes and migrations in different parts， and the section shows the cyclic transformation of tension-torsion and compression-torsion properties. On the plane， different types of fracture combinations appear alternately. The development model of strike-slip faults is established， and the strike-slip faults have typical characteristics of “multi-stage activity and inherited development”. Chang 8 Member mainly develops vertical fractures and horizontal bedding fractures.The development frequency of horizontal bedding fractures is 62.5%， while that of vertical fractures is 37.5%. The oil level of vertical fractures is relatively higher. Fractures are mainly developed in fine sandstone in distributary channels. When the distance from the main fault is greater than 1.25-1.5 km， the degree of fracture development decreases sharply， showing a fault-fracture body boundary. In addition， fractures are relatively developed in the single sand body within 6 m from the main fault. When the thickness of the single sand body exceeds 6 m， the degree of fracture development decreases sharply. The study shows that the index system based on sedimentation （foundation）， structure （dominant）， and fracture （effective） can effectively predict the favorable zones of Chang 8 fault-fracture body reservoir.
Fault-fracture bodies are developed in the southwestern margin of Ordos Basin， and thus， the study on the controlling effect of fracture bodies on sweet spot distribution of Yanchang Formation reservoirs needs to be deepened. In this paper， based on the extensive seismic and logging interpretation results， the characteristics of fault-fracture bodies are described from the point of view of their evolution mechanism， and then the controlling effect of fault-fracture bodies on oil and gas is systematically discussed. The results show that vertical strike-slip faults are developed in the southwest margin of Ordos Basin， with Y-shaped， flower-like， and negative flower-like structures. The faults usually pass through the bottom of Chang 7 Member， the bottom of Yan’an Formation，the bottom of the Cretaceous series， and the basement. Some of the faults retain the early reverse fault properties， indicating that the late inversion degree is not complete. The main fault has different shapes and migrations in different parts， and the section shows the cyclic transformation of tension-torsion and compression-torsion properties. On the plane， different types of fracture combinations appear alternately. The development model of strike-slip faults is established， and the strike-slip faults have typical characteristics of “multi-stage activity and inherited development”. Chang 8 Member mainly develops vertical fractures and horizontal bedding fractures.The development frequency of horizontal bedding fractures is 62.5%， while that of vertical fractures is 37.5%. The oil level of vertical fractures is relatively higher. Fractures are mainly developed in fine sandstone in distributary channels. When the distance from the main fault is greater than 1.25-1.5 km， the degree of fracture development decreases sharply， showing a fault-fracture body boundary. In addition， fractures are relatively developed in the single sand body within 6 m from the main fault. When the thickness of the single sand body exceeds 6 m， the degree of fracture development decreases sharply. The study shows that the index system based on sedimentation （foundation）， structure （dominant）， and fracture （effective） can effectively predict the favorable zones of Chang 8 fault-fracture body reservoir.
LIU Haojie
,
ZHANG Changmin
,
GAI Shanshan
,
YU Wenzheng
,
LI Jin
,
YUAN Haihan
,
ZHANG Li
,
LIU Hongping
2024, 31(1):13-22.
DOI: 10.13673/j.pgre.202211031
Abstract:
Deep-buried tight sandstone reservoirs have strong heterogeneity and complex distribution patterns， which makes it difficult to predict geological sweet spots in those reservoirs. In order to achieve efficient exploration and development， it is urgent to research the accurate identification and prediction of the diagenetic facies of reservoirs among the wells. The identification and distribution prediction of diagenetic facies were carried out using core， well logging， and 3D seismic data based on the diagenesis of Jurassic ultra-deep reservoirs in Yongjin Oilfield， Junggar Basin. It was considered that the diagenesis types of reservoirs mainly include compaction， cementation， dissolution， and metasomatism， which can be divided into five diagenetic facies， such as strong dissolution with chlorite enclave， medium dissolution with authigenic kaolinite， medium calcareous cemented dissolution， strong calcareous cementation， and strongly tight compaction. Based on logging data， petrophysical and physical parameters were used to identify diagenetic facies types of the reservoirs and determine their vertical distribution. The results find that the two dominant diagenetic facies， namely strong dissolution with chlorite enclave and medium dissolution with authigenic kaolinite， are mainly located in the sand body of the main distributary channel of the delta， with suitable reservoir property， and they are the main parts of the oil reservoir development. Based on the analysis of the corresponding relationship between diagenetic facies and seismic P-wave impedance， it is found that the P-wave impedance of the dominant diagenetic facies is relatively low， and the distribution of the dominant diagenetic facies can be predicted by the numerical distribution characteristics of P-wave impedance. Therefore，diagenetic facies distribution is predicted using the inversion results of 3D seismic P-wave impedance， and the development area of the dominant diagenetic facies is determined according to the corresponding relationship between P-wave impedance and different types of diagenetic rocks. The result indicates that the dominant diagenetic facies are mainly located in the Y301-Y302 well area in the northeast of the study area and the Y1 well area in the northwest， showing a locally continuous distribution pattern. Identification of diagenetic facies in reservoirs can provide an essential basis for the distribution prediction of ultra-deep geological sweet spots.
Deep-buried tight sandstone reservoirs have strong heterogeneity and complex distribution patterns， which makes it difficult to predict geological sweet spots in those reservoirs. In order to achieve efficient exploration and development， it is urgent to research the accurate identification and prediction of the diagenetic facies of reservoirs among the wells. The identification and distribution prediction of diagenetic facies were carried out using core， well logging， and 3D seismic data based on the diagenesis of Jurassic ultra-deep reservoirs in Yongjin Oilfield， Junggar Basin. It was considered that the diagenesis types of reservoirs mainly include compaction， cementation， dissolution， and metasomatism， which can be divided into five diagenetic facies， such as strong dissolution with chlorite enclave， medium dissolution with authigenic kaolinite， medium calcareous cemented dissolution， strong calcareous cementation， and strongly tight compaction. Based on logging data， petrophysical and physical parameters were used to identify diagenetic facies types of the reservoirs and determine their vertical distribution. The results find that the two dominant diagenetic facies， namely strong dissolution with chlorite enclave and medium dissolution with authigenic kaolinite， are mainly located in the sand body of the main distributary channel of the delta， with suitable reservoir property， and they are the main parts of the oil reservoir development. Based on the analysis of the corresponding relationship between diagenetic facies and seismic P-wave impedance， it is found that the P-wave impedance of the dominant diagenetic facies is relatively low， and the distribution of the dominant diagenetic facies can be predicted by the numerical distribution characteristics of P-wave impedance. Therefore，diagenetic facies distribution is predicted using the inversion results of 3D seismic P-wave impedance， and the development area of the dominant diagenetic facies is determined according to the corresponding relationship between P-wave impedance and different types of diagenetic rocks. The result indicates that the dominant diagenetic facies are mainly located in the Y301-Y302 well area in the northeast of the study area and the Y1 well area in the northwest， showing a locally continuous distribution pattern. Identification of diagenetic facies in reservoirs can provide an essential basis for the distribution prediction of ultra-deep geological sweet spots.
2024, 31(1):23-35.
DOI: 10.13673/j.pgre.202305002
Abstract:
In order to clarify the pore structure and fractal characteristics of the deep continental shale of the Lower Wuerhe Formation in the central Junggar Basin， the Lower Wuerhe Formation shale in the Dongdaohaizi Sag was taken as the research object. On the basis of an in-depth analysis of shale minerals and geochemical characteristics， the pore structure characteristics of the Lower Wuerhe Formation shale were quantitatively characterized by using field emission scanning electron microscopy and lowtemperature N2 adsorption experiments. The fractal dimension of shale pores was calculated based on the FHH model， and the relationships among TOC content， mineral composition， pore structure parameters， fractal dimension， and its geological significance were revealed. The results show that the Lower Wuerhe Formation shale mainly develops inorganic pores and micro-fractures， and the pore size distribution is multi-peak type， mostly parallel plate or narrow slit pores. The pore development of shale is controlled by TOC and the content of quartz， feldspar， and clay minerals， which results in significant differences and strong heterogeneity among pore structures. Shale pores of the Lower Wuerhe Formation in the study area have double fractal characteristics，in which the surface fractal dimension D1 varies from 2.452 2 to 2.594 8， with an average value of 2.540 9. The fractal dimension D2 of the structure ranges from 2.604 5 to 2.774 8， with an average of 2.705 6. TOC is negatively correlated with fractal dimension，while pore structure parameters （specific surface area and pore volume） and mineral composition （quartz， feldspar， and clay mineral content） are positively correlated with fractal dimension. An increase in the content of brittle minerals such as quartz， feldspar and clay minerals contributes to the development of micro- and nano-scale pores and micro-fractures. This results in an increase in specific surface area， pore volume， and fractal dimension. As pore heterogeneity strengthens， the complexity of the pore structure also increases.
In order to clarify the pore structure and fractal characteristics of the deep continental shale of the Lower Wuerhe Formation in the central Junggar Basin， the Lower Wuerhe Formation shale in the Dongdaohaizi Sag was taken as the research object. On the basis of an in-depth analysis of shale minerals and geochemical characteristics， the pore structure characteristics of the Lower Wuerhe Formation shale were quantitatively characterized by using field emission scanning electron microscopy and lowtemperature N2 adsorption experiments. The fractal dimension of shale pores was calculated based on the FHH model， and the relationships among TOC content， mineral composition， pore structure parameters， fractal dimension， and its geological significance were revealed. The results show that the Lower Wuerhe Formation shale mainly develops inorganic pores and micro-fractures， and the pore size distribution is multi-peak type， mostly parallel plate or narrow slit pores. The pore development of shale is controlled by TOC and the content of quartz， feldspar， and clay minerals， which results in significant differences and strong heterogeneity among pore structures. Shale pores of the Lower Wuerhe Formation in the study area have double fractal characteristics，in which the surface fractal dimension D1 varies from 2.452 2 to 2.594 8， with an average value of 2.540 9. The fractal dimension D2 of the structure ranges from 2.604 5 to 2.774 8， with an average of 2.705 6. TOC is negatively correlated with fractal dimension，while pore structure parameters （specific surface area and pore volume） and mineral composition （quartz， feldspar， and clay mineral content） are positively correlated with fractal dimension. An increase in the content of brittle minerals such as quartz， feldspar and clay minerals contributes to the development of micro- and nano-scale pores and micro-fractures. This results in an increase in specific surface area， pore volume， and fractal dimension. As pore heterogeneity strengthens， the complexity of the pore structure also increases.
2024, 31(1):36-43.
DOI: 10.13673/j.pgre.202304005
Abstract:
Nuclear magnetic resonance （NMR） transverse relaxation time T2 is commonly used to characterize the full-scale pore size distribution characteristics of shale. In order to determine the quantitative relationship between T2and the pore size of shale，seven shale samples from Shahejie Formation in Jiyang Depression are selected to perform low-temperature nitrogen adsorption and NMR experiments. The surface relaxivity，the critical parameter to calculate the pore size distribution by T2，is obtained according to the equation reflecting the relationship between the logarithmic mean of T2 and specific surface area and pore volume. For these samples，the surface relaxivity ranges from 1.52 nm/ms to 3.06 nm/ms，with an average value of 2.53 nm/ms. The pore size distribution results calculated by surface relaxivity are more similar to the calculation results of the NLDFT model for low-temperature nitro‐gen adsorption， confirming the rationality of the determination method and values of the shale surface relaxivity. The pore size distribution of typical shale thin layers in Jiyang Depression is determined by the above method. Based on the reservoir properties and geochemical results，it is believed that the argillaceous thin layer in the shale mainly plays the role of generating and storing shale oil，while the fibrous calcite thin layer，powdered calcite thin layer，and silty sand thin layer can be used as the storage and flow channel. It is necessary to analyze the pore size distribution characteristics of different thin layers and their generation，storage， and flow when studying the micro-enrichment and flow mechanism and evaluating the sweet spot of shale oil resources.
Nuclear magnetic resonance （NMR） transverse relaxation time T2 is commonly used to characterize the full-scale pore size distribution characteristics of shale. In order to determine the quantitative relationship between T2and the pore size of shale，seven shale samples from Shahejie Formation in Jiyang Depression are selected to perform low-temperature nitrogen adsorption and NMR experiments. The surface relaxivity，the critical parameter to calculate the pore size distribution by T2，is obtained according to the equation reflecting the relationship between the logarithmic mean of T2 and specific surface area and pore volume. For these samples，the surface relaxivity ranges from 1.52 nm/ms to 3.06 nm/ms，with an average value of 2.53 nm/ms. The pore size distribution results calculated by surface relaxivity are more similar to the calculation results of the NLDFT model for low-temperature nitro‐gen adsorption， confirming the rationality of the determination method and values of the shale surface relaxivity. The pore size distribution of typical shale thin layers in Jiyang Depression is determined by the above method. Based on the reservoir properties and geochemical results，it is believed that the argillaceous thin layer in the shale mainly plays the role of generating and storing shale oil，while the fibrous calcite thin layer，powdered calcite thin layer，and silty sand thin layer can be used as the storage and flow channel. It is necessary to analyze the pore size distribution characteristics of different thin layers and their generation，storage， and flow when studying the micro-enrichment and flow mechanism and evaluating the sweet spot of shale oil resources.
2024, 31(1):44-53.
DOI: 10.13673/j.pgre.202305033
Abstract:
The carbonate reservoir in Puguang Gas Field has the characteristics of large burial depth， developed reef-flat facies， poor matrix properties，widespread development of natural fractures， and strong heterogeneity. The challenge is to construct threedimensional geological modeling of such strongly heterogeneous dual-medium reservoirs. We divided the reservoir modeling object into two major media： matrix and fracture. Based on single well interpretation data and seismic wave impedance data，the matrix model was established by using well-seismic combination， step-by-step facies control， and multi-trend fusion probability constraint volume construction. According to the idea of multi-scale and multi-stage modeling， the entropy weight method combined with expert experience evaluation was used to construct the spatial distribution constraint volume of fracture through the integration of mechanism-geology-seismic data， as well as tectonic stress fields， distances to the fault， and seismic sensitive attributes of fractures.Under the constraints of the constraint volume， the fracture model was constructed by the discrete fracture network modeling. The numerical simulation of the gas reservoir was conducted on the established matrix-fracture model. The historical fitting rate of each well reaches 90%， and the fitting error is controlled within 20%， indicating a high fitting accuracy of the model.
The carbonate reservoir in Puguang Gas Field has the characteristics of large burial depth， developed reef-flat facies， poor matrix properties，widespread development of natural fractures， and strong heterogeneity. The challenge is to construct threedimensional geological modeling of such strongly heterogeneous dual-medium reservoirs. We divided the reservoir modeling object into two major media： matrix and fracture. Based on single well interpretation data and seismic wave impedance data，the matrix model was established by using well-seismic combination， step-by-step facies control， and multi-trend fusion probability constraint volume construction. According to the idea of multi-scale and multi-stage modeling， the entropy weight method combined with expert experience evaluation was used to construct the spatial distribution constraint volume of fracture through the integration of mechanism-geology-seismic data， as well as tectonic stress fields， distances to the fault， and seismic sensitive attributes of fractures.Under the constraints of the constraint volume， the fracture model was constructed by the discrete fracture network modeling. The numerical simulation of the gas reservoir was conducted on the established matrix-fracture model. The historical fitting rate of each well reaches 90%， and the fitting error is controlled within 20%， indicating a high fitting accuracy of the model.
2024, 31(1):54-62.
DOI: 10.13673/j.pgre.202305048
Abstract:
In response to the development issues faced by chemical flooding in the mature Shengli Oilfield with high water cut in terms of science， technology， management， and engineering， Block Bohai 76 was taken as a typical unit， and the specific countermeasures were analyzed in engineering practice. A new comprehensive management method was constructed for chemical flooding in mature oilfields：“ Appropriate， Specialized， Fast， and Integrated.” Among them，“ Appropriate” refers to the construction of optimal changing timing models for chemical flooding in different oil reservoirs of mature oilfields during the transformation of scientific development methods for mature oilfields. It was proposed that the favorable changing timing for chemical flooding is at the relatively low water cut stage， and efficient development methods should be used in an appropriate manner.“ Specialized” refers to changing the traditional development approach of dissolving polymers before injection in the application of development technology for mature oilfields， developing controllable phase conversion polymers to enable polymer injection followed by dissolution， over‐coming the problem of borehole shear degradation， and improving the ability to control oil-water fluidity. The development issues in mature oilfields need to be specifically addressed.“ Fast” refers to the transformation in the traditional comprehensive management mode of mature oil fields， which involves a“ serial” management mode of problems proposed by fields， schemes designed by research institutes， and oil displacement agents produced by chemical plants. A“ parallel” management mode was proposed that fully leveraged the advantages of fields， research institutes， and production plants， and the industrial chemical technology packages and industrialization implementation plans were formed for a single oil reservoir. The development technology of mature oilfields can thus achieve fast transformation.“ Integrated” refers to breaking the engineering process model of large-scale construction of chemical flooding stations in mature oilfields during engineering application practice， adopting integrated assembly of injection equipment，achieving the rapid and integrated injection allocation of chemical flooding in mature oilfields， and thus ensuring “integrated” application of engineering processes in mature oilfields. A transition from water flooding to controllable phase conversion polymer flooding was implemented using the above method in Block Bohai 76 of Shengli Oilfield at the early stage of the comprehensive water cut increase. The significant water cut reduction and oil increase effects were observed after one year. The average oil production rate per well increased by 8.6 t/d， and the comprehensive water cut decreased by 3.1%. The feasibility of the comprehensive management model was verified， providing an effective path for the efficient development of chemical flooding in mature oilfields with high water cuts.
In response to the development issues faced by chemical flooding in the mature Shengli Oilfield with high water cut in terms of science， technology， management， and engineering， Block Bohai 76 was taken as a typical unit， and the specific countermeasures were analyzed in engineering practice. A new comprehensive management method was constructed for chemical flooding in mature oilfields：“ Appropriate， Specialized， Fast， and Integrated.” Among them，“ Appropriate” refers to the construction of optimal changing timing models for chemical flooding in different oil reservoirs of mature oilfields during the transformation of scientific development methods for mature oilfields. It was proposed that the favorable changing timing for chemical flooding is at the relatively low water cut stage， and efficient development methods should be used in an appropriate manner.“ Specialized” refers to changing the traditional development approach of dissolving polymers before injection in the application of development technology for mature oilfields， developing controllable phase conversion polymers to enable polymer injection followed by dissolution， over‐coming the problem of borehole shear degradation， and improving the ability to control oil-water fluidity. The development issues in mature oilfields need to be specifically addressed.“ Fast” refers to the transformation in the traditional comprehensive management mode of mature oil fields， which involves a“ serial” management mode of problems proposed by fields， schemes designed by research institutes， and oil displacement agents produced by chemical plants. A“ parallel” management mode was proposed that fully leveraged the advantages of fields， research institutes， and production plants， and the industrial chemical technology packages and industrialization implementation plans were formed for a single oil reservoir. The development technology of mature oilfields can thus achieve fast transformation.“ Integrated” refers to breaking the engineering process model of large-scale construction of chemical flooding stations in mature oilfields during engineering application practice， adopting integrated assembly of injection equipment，achieving the rapid and integrated injection allocation of chemical flooding in mature oilfields， and thus ensuring “integrated” application of engineering processes in mature oilfields. A transition from water flooding to controllable phase conversion polymer flooding was implemented using the above method in Block Bohai 76 of Shengli Oilfield at the early stage of the comprehensive water cut increase. The significant water cut reduction and oil increase effects were observed after one year. The average oil production rate per well increased by 8.6 t/d， and the comprehensive water cut decreased by 3.1%. The feasibility of the comprehensive management model was verified， providing an effective path for the efficient development of chemical flooding in mature oilfields with high water cuts.
HAN Xiao
,
SONG Zhaojie
,
LI Peiyu
,
DENG Sen
,
SONG Yilei
,
ZHANG Yunfei
,
CAO Changxiao
,
YANG Zhicheng
,
WU Jiapeng
2024, 31(1):63-71.
DOI: 10.13673/j.pgre.202307028
Abstract:
The core pore structure of the target shale oil block was finely characterized using scanning electron microscopy，and a microscopic numerical model of the pore-scale core was constructed to elucidate the intrinsic mechanisms and the main controlling factors of spontaneous imbibition of fracturing fluid within the complex pore space of shale. On this basis， research was conducted on spontaneous imbibition within the fracture-matrix system. The Navier-Stokes （N-S） equations were coupled with the level-set method to track changes in the oil and water interface， thus clarifying the oil and water two-phase flow characteristics and evaluating the efficiency of spontaneous imbibition under the influence of the wettability， viscosity ratio of oil and water， and interfacial tension. The research results revealed that large and small intercommunicating pores in shale form intricate microscopic displacement units under capillary action. When the rock wettability presents a water-wet state， water preferentially infiltrates from the fracture into the smaller pores， expelling oil from larger pores into the fracture， and the produced range of crude oil within the matrix pores is wider， resulting in higher spontaneous imbibition efficiency. When the rock wettability turns oil-wet， crude oil within the small pores cannot be produced during spontaneous imbibition， while the water invades from larger pores， causing crude oil to be displaced from other large pores. This results in a lower spontaneous imbibition efficiency and a small range of crude oil produced in the matrix pores. The spontaneous imbibition in the initial phase is faster but gradually slows over time. Stronger water wettability of shale indicates a lower viscosity ratio of oil and water and higher interfacial tension， resulting in a wider range of crude oil produced within the matrix pores and a cumulative efficiency of spontaneous imbibition of more than 15%.
The core pore structure of the target shale oil block was finely characterized using scanning electron microscopy，and a microscopic numerical model of the pore-scale core was constructed to elucidate the intrinsic mechanisms and the main controlling factors of spontaneous imbibition of fracturing fluid within the complex pore space of shale. On this basis， research was conducted on spontaneous imbibition within the fracture-matrix system. The Navier-Stokes （N-S） equations were coupled with the level-set method to track changes in the oil and water interface， thus clarifying the oil and water two-phase flow characteristics and evaluating the efficiency of spontaneous imbibition under the influence of the wettability， viscosity ratio of oil and water， and interfacial tension. The research results revealed that large and small intercommunicating pores in shale form intricate microscopic displacement units under capillary action. When the rock wettability presents a water-wet state， water preferentially infiltrates from the fracture into the smaller pores， expelling oil from larger pores into the fracture， and the produced range of crude oil within the matrix pores is wider， resulting in higher spontaneous imbibition efficiency. When the rock wettability turns oil-wet， crude oil within the small pores cannot be produced during spontaneous imbibition， while the water invades from larger pores， causing crude oil to be displaced from other large pores. This results in a lower spontaneous imbibition efficiency and a small range of crude oil produced in the matrix pores. The spontaneous imbibition in the initial phase is faster but gradually slows over time. Stronger water wettability of shale indicates a lower viscosity ratio of oil and water and higher interfacial tension， resulting in a wider range of crude oil produced within the matrix pores and a cumulative efficiency of spontaneous imbibition of more than 15%.
2024, 31(1):72-77.
DOI: 10.13673/j.pgre.202307027
Abstract:
For the gas flow controlled by the closed boun&dary， after the completion of gas testing and shut-in to obtain the original formation pressure， the pressure draw down curves can be divided into three stages： unsteady state， transit state and pseudosteady state. The pseudo-steady state is called elastic two-phase state， and the pressure within the well control range of the elastic two-phase state decreases at a constant velocity. This article established the general formulas for the stable rate and variable rate elastic two-phase method of gas wells， based on the stable rate elastic two-phase method represented by pressure first power，pressure square and pseudo pressure proposed by Chen Yuanqian， and the variable rate elastic two-phase method represented by pressure first power proposed by Blasingame. The practical application shows that the general formula provided in this paper are practical and effective.
For the gas flow controlled by the closed boun&dary， after the completion of gas testing and shut-in to obtain the original formation pressure， the pressure draw down curves can be divided into three stages： unsteady state， transit state and pseudosteady state. The pseudo-steady state is called elastic two-phase state， and the pressure within the well control range of the elastic two-phase state decreases at a constant velocity. This article established the general formulas for the stable rate and variable rate elastic two-phase method of gas wells， based on the stable rate elastic two-phase method represented by pressure first power，pressure square and pseudo pressure proposed by Chen Yuanqian， and the variable rate elastic two-phase method represented by pressure first power proposed by Blasingame. The practical application shows that the general formula provided in this paper are practical and effective.
2024, 31(1):78-86.
DOI: 10.13673/j.pgre.202209025
Abstract:
A partially enclosed fault reservoir is a common reservoir type. The partially enclosed faults caused by low-order faults lead to different fluid flow and distribution laws of remaining oil between partially enclosed fault reservoirs and completely enclosed reservoirs. Through the existing technology， it is difficult to quantitatively describe the evolution law of the dominant flow channel in the deep part of the reservoir in the whole process of water flooding， which affects the efficient development of this kind of reservoir. Therefore， the physical model of a partially enclosed fault reservoir was designed and fabricated， and the water flooding experiment was carried out. The numerical inversion model was established according to the model parameters and experimental re‐sults. The dominant flow channel was quantitatively characterized based on the standardized flow rate algorithm. Then， the numerical inversion model was used to compare with the evolution law of the dominant flow channels in fault-free reservoirs and reveal the evolution law of the dominant flow channel in the physical model of the partially enclosed fault reservoir. The results show that the accumulative oil yield and the oil production rate of the production well in the fault-occluded area were low. The reduction of the flow area in the fault discontinuity led to the earliest breakthrough in the production well. Although the production wells on the other side of the fault had close oil production in the early stage， the blocking effect of the fault on injection water led to a higher flow diversion rate and the highest oil production rate in the late stage in the strongly fault-occluded area. During the anhydrous oil production period， a dominant flow area played a positive role in oil displacement， which developed into a spindle-shaped dominant flow channel at the bottom of the reservoir through vertical equilibrium distribution and“ finger-shaped” distribution. After water production in each well， a dominant flow channel was formed from the injection well to the bottom of the production well， except for the strongly fault-occluded area. With the increase in injection volume， this channel developed in the vertical direction and around the production well and played a negative role in oil displacement. Compared with fault-free reservoirs， partially enclosed faults made the development of dominant flow channels lag in strongly fault-occluded areas and difficult water sweep in strongly fault-occluded areas， resulting in significant differences in the distribution of remaining oil in each area， and the remaining oil is concentrated in the upper part of the strongly fault-occluded area and near the faults in strongly fault-occluded areas.
A partially enclosed fault reservoir is a common reservoir type. The partially enclosed faults caused by low-order faults lead to different fluid flow and distribution laws of remaining oil between partially enclosed fault reservoirs and completely enclosed reservoirs. Through the existing technology， it is difficult to quantitatively describe the evolution law of the dominant flow channel in the deep part of the reservoir in the whole process of water flooding， which affects the efficient development of this kind of reservoir. Therefore， the physical model of a partially enclosed fault reservoir was designed and fabricated， and the water flooding experiment was carried out. The numerical inversion model was established according to the model parameters and experimental re‐sults. The dominant flow channel was quantitatively characterized based on the standardized flow rate algorithm. Then， the numerical inversion model was used to compare with the evolution law of the dominant flow channels in fault-free reservoirs and reveal the evolution law of the dominant flow channel in the physical model of the partially enclosed fault reservoir. The results show that the accumulative oil yield and the oil production rate of the production well in the fault-occluded area were low. The reduction of the flow area in the fault discontinuity led to the earliest breakthrough in the production well. Although the production wells on the other side of the fault had close oil production in the early stage， the blocking effect of the fault on injection water led to a higher flow diversion rate and the highest oil production rate in the late stage in the strongly fault-occluded area. During the anhydrous oil production period， a dominant flow area played a positive role in oil displacement， which developed into a spindle-shaped dominant flow channel at the bottom of the reservoir through vertical equilibrium distribution and“ finger-shaped” distribution. After water production in each well， a dominant flow channel was formed from the injection well to the bottom of the production well， except for the strongly fault-occluded area. With the increase in injection volume， this channel developed in the vertical direction and around the production well and played a negative role in oil displacement. Compared with fault-free reservoirs， partially enclosed faults made the development of dominant flow channels lag in strongly fault-occluded areas and difficult water sweep in strongly fault-occluded areas， resulting in significant differences in the distribution of remaining oil in each area， and the remaining oil is concentrated in the upper part of the strongly fault-occluded area and near the faults in strongly fault-occluded areas.
2024, 31(1):87-102.
DOI: 10.13673/j.pgre.202303005
Abstract:
The reserves of heavy oil far exceed those of conventional oil， but heavy oil is difficult to exploit due to its high viscosity and density. Thus， the efficient and economical development of heavy oil has become a research focus in the petroleum field. Hybrid thermal recovery are critical for efficiently developing heavy oil reservoirs， and phase behavior of multi-component thermal fluids are the key to designing and evaluating the development processes of heavy oil reservoirs. Therefore， this paper systematically reviewed the current experimental and theoretical research on phase behavior in multi-component thermal fluids of mixed gas systems and heavy oil-gas systems in hybrid thermal recovery. For phase behavior of mixed gas systems， static methods were employed for experimental tests， and state equations and mixing rules were for theoretical prediction. Meanwhile， the phase test of the binary system composed of common gas molecules such as CO2， N2， H2O， and CH4 tends to be mature， while there is a lack of test data and prediction models related to multivariate systems. For heavy oil-gas systems， general experimental processes and recent experimental results were summarized to propose a new experimental device concept for accelerating oil-gas phase equilibrium. Additionally，the disadvantages of current theoretical prediction in gas types， gas injection rates， gas diffusion models， and binary interaction coefficients were pointed out. Furthermore， a prospect was presented for studying the phase behavior of multi-component thermal fluids to promote further mechanism research and parameter optimization of hybrid thermal recovery.
The reserves of heavy oil far exceed those of conventional oil， but heavy oil is difficult to exploit due to its high viscosity and density. Thus， the efficient and economical development of heavy oil has become a research focus in the petroleum field. Hybrid thermal recovery are critical for efficiently developing heavy oil reservoirs， and phase behavior of multi-component thermal fluids are the key to designing and evaluating the development processes of heavy oil reservoirs. Therefore， this paper systematically reviewed the current experimental and theoretical research on phase behavior in multi-component thermal fluids of mixed gas systems and heavy oil-gas systems in hybrid thermal recovery. For phase behavior of mixed gas systems， static methods were employed for experimental tests， and state equations and mixing rules were for theoretical prediction. Meanwhile， the phase test of the binary system composed of common gas molecules such as CO2， N2， H2O， and CH4 tends to be mature， while there is a lack of test data and prediction models related to multivariate systems. For heavy oil-gas systems， general experimental processes and recent experimental results were summarized to propose a new experimental device concept for accelerating oil-gas phase equilibrium. Additionally，the disadvantages of current theoretical prediction in gas types， gas injection rates， gas diffusion models， and binary interaction coefficients were pointed out. Furthermore， a prospect was presented for studying the phase behavior of multi-component thermal fluids to promote further mechanism research and parameter optimization of hybrid thermal recovery.
2024, 31(1):103-110.
DOI: 10.13673/j.pgre.202303019
Abstract:
Small reservoir thickness， high crude oil viscosity， large steam heat loss， and short cyclic steam stimulation （CSS） period are problems facing in shallow-thin ultra-heavy oil reservoirs at the early stage of CSS development. Therefore， the development model of large CSS of alternating hot and cold fluid injection was proposed to improve the development effect effectively. In addition， carried out a three-dimensional physical simulation experiment of alternating heat and cold fluid injection in shallow-thin ultra-heavy oil reservoirs. The results show that the temperature of CSS decreases rapidly and the peak production is high because of the heat loss of the top and bottom cap rocks， but the single cycle production time is short， about 100 min. The injection of viscosity reducer can reduce the oil saturation near the well， improve the oil production rate， lower the water content， and increase the CSS period by more than 50 min at the production stage. Increasing temperature can enhance the viscosity reduction effect of the viscosity reducer， and the improvement effect during the second cycle is better than that during the first cycle. In addition， the production time is increased by 60 min， water content is cut by 45%， and the oil recovery is enhanced by 1.7%. The injection parameters of heat and cold fluid were optimized and the policy limits of this technology were established by a numerical simulation method：The best timing of alternating heat and cold fluid injection is the second or third cycle； and the injection strength is 0.02 t/m. The suitable reservoir thickness is less than 8 m； the crude oil viscosity is less than 200 000 mPa·s；the oil saturation is higher than 0.6，and the permeability is higher than 1 000 mD.
Small reservoir thickness， high crude oil viscosity， large steam heat loss， and short cyclic steam stimulation （CSS） period are problems facing in shallow-thin ultra-heavy oil reservoirs at the early stage of CSS development. Therefore， the development model of large CSS of alternating hot and cold fluid injection was proposed to improve the development effect effectively. In addition， carried out a three-dimensional physical simulation experiment of alternating heat and cold fluid injection in shallow-thin ultra-heavy oil reservoirs. The results show that the temperature of CSS decreases rapidly and the peak production is high because of the heat loss of the top and bottom cap rocks， but the single cycle production time is short， about 100 min. The injection of viscosity reducer can reduce the oil saturation near the well， improve the oil production rate， lower the water content， and increase the CSS period by more than 50 min at the production stage. Increasing temperature can enhance the viscosity reduction effect of the viscosity reducer， and the improvement effect during the second cycle is better than that during the first cycle. In addition， the production time is increased by 60 min， water content is cut by 45%， and the oil recovery is enhanced by 1.7%. The injection parameters of heat and cold fluid were optimized and the policy limits of this technology were established by a numerical simulation method：The best timing of alternating heat and cold fluid injection is the second or third cycle； and the injection strength is 0.02 t/m. The suitable reservoir thickness is less than 8 m； the crude oil viscosity is less than 200 000 mPa·s；the oil saturation is higher than 0.6，and the permeability is higher than 1 000 mD.
2024, 31(1):111-118.
DOI: 10.13673/j.pgre.202305039
Abstract:
CO2injection has become one of the most important methods of enhanced oil recovery in tight reservoirs， but some hydrocarbon gases have more viscosity-reducing and miscibility on oil compared to pure CO2. Therefore，this article studied the saturation pressure and viscosity changes of oil with CO2and composite gas （CO2and C2H6） by PVT experiments at high-temperature and high-pressure and revealed the percentage of producing oil with different gases，huff and puff pressures，and rounds by core huff and puff experiments at high-temperature and high-pressure. The results show that the C2H6 in the composite gas enhances the gas and liquid miscibility，improves the CO2 viscosity reduction and dissolution ability， and significantly increases the fluidity of oil. With the increase of C2H6mole fraction in the composite gas，the saturation pressure of oil increases by 26.54% from 14.24 MPa to 18.02 MPa， and the viscosity of crude oil decreases from 23.68 mPa·s to 8.76 mPa·s. Under different huff and puff pressures，the oil recoveries of composite gas（CO2 and C2H6） are better than that of pure CO2，and the increase of recovery near the minimum miscibility pressure is higher than under other huff and puff pressures. The percentage of producing oil by composite gases is higher than that of pure CO2 in the pores of 0.0001-0.001 μm and 0.01-1 μm.
CO2injection has become one of the most important methods of enhanced oil recovery in tight reservoirs， but some hydrocarbon gases have more viscosity-reducing and miscibility on oil compared to pure CO2. Therefore，this article studied the saturation pressure and viscosity changes of oil with CO2and composite gas （CO2and C2H6） by PVT experiments at high-temperature and high-pressure and revealed the percentage of producing oil with different gases，huff and puff pressures，and rounds by core huff and puff experiments at high-temperature and high-pressure. The results show that the C2H6 in the composite gas enhances the gas and liquid miscibility，improves the CO2 viscosity reduction and dissolution ability， and significantly increases the fluidity of oil. With the increase of C2H6mole fraction in the composite gas，the saturation pressure of oil increases by 26.54% from 14.24 MPa to 18.02 MPa， and the viscosity of crude oil decreases from 23.68 mPa·s to 8.76 mPa·s. Under different huff and puff pressures，the oil recoveries of composite gas（CO2 and C2H6） are better than that of pure CO2，and the increase of recovery near the minimum miscibility pressure is higher than under other huff and puff pressures. The percentage of producing oil by composite gases is higher than that of pure CO2 in the pores of 0.0001-0.001 μm and 0.01-1 μm.
2024, 31(1):119-125.
DOI: 10.13673/j.pgre.202204036
Abstract:
This paper establishes a microchannel model based on the pore scale distribution characteristics of natural cores from Daqing Oilfield. It considers the deformation and flow characteristics of the dispersed and continuous phases in the heterogeneous system， builds a flow model by the phase field method， and solves it by the finite element method. The paper also simulates the generation of dispersed phase particles in the microchannel， realizes particle sorting， and studies the effect of the matching coefficient and pore-throat ratio on the plugging performance of particles in the microscopic pore-throat structure. The results show that when the particles are elastically plugged in the microscopic pore-throat structure， the pressure at the entrance of the pore throat changes periodically with the migration of the particles through the pore throat. The optimal matching coefficient between the particles and the pore throat is ［1.0， 1.4）. In this interval， the particles can be temporarily plugged at the entrance of the pore throat and recover their original shape after deformation and migration through the pore throat. When the pore diameter is the same， a larger matching coefficient and pore-throat ratio indicate greater pressure of particles through the pore throat， and larger particle size reflects a smaller critical value of particles through the pore throat.
This paper establishes a microchannel model based on the pore scale distribution characteristics of natural cores from Daqing Oilfield. It considers the deformation and flow characteristics of the dispersed and continuous phases in the heterogeneous system， builds a flow model by the phase field method， and solves it by the finite element method. The paper also simulates the generation of dispersed phase particles in the microchannel， realizes particle sorting， and studies the effect of the matching coefficient and pore-throat ratio on the plugging performance of particles in the microscopic pore-throat structure. The results show that when the particles are elastically plugged in the microscopic pore-throat structure， the pressure at the entrance of the pore throat changes periodically with the migration of the particles through the pore throat. The optimal matching coefficient between the particles and the pore throat is ［1.0， 1.4）. In this interval， the particles can be temporarily plugged at the entrance of the pore throat and recover their original shape after deformation and migration through the pore throat. When the pore diameter is the same， a larger matching coefficient and pore-throat ratio indicate greater pressure of particles through the pore throat， and larger particle size reflects a smaller critical value of particles through the pore throat.
14 Mechanism of imbibition and production enhancement of nanoemulsion in tight sandstone oil reservoirs
2024, 31(1):126-136.
DOI: 10.13673/j.pgre.202308003
Abstract:
Nanoemulsion， as a kind of nanoscale colloidal dispersion system， has been widely applied in unconventional oil reservoir development due to its outstanding interfacial properties and enhanced oil recovery effects. Water-in-oil type nanoemulsion systems are prepared based on the low-energy emulsification method. The intrinsic relationships among the static adsorption， wettability alteration， and spontaneous imbibition of nanoemulsion are determined by laboratory experiments， elucidating the mechanism of imbibition and production enhancement of nanoemulsion in tight sandstone oil reservoirs. The laboratory results show that the average droplet size of nanoemulsion is less than 10 nm， which can meet the droplet size requirement of entering most of the pore throat of tight sandstone and can fully diffuse and migrate in the tight pore throat， thus expanding the imbibition range. The critical micelle mass fraction of the nanoemulsion is 0.015%，which can effectively reduce the oil-water interfacial tension to about 2 mN/m. The adsorption isotherm of the nanoemulsion conforms to the Langmuir adsorption model， and the wettability alteration mechanism is mainly adsorption. The nanoemulsion can dissolve the crude oil， further disperse the crude oil through emulsification， reduce the size of oil droplets in the emulsion， and weaken the Jamin effect when oil droplets pass through the pore throat， reducing seepage resistance. Core wettability will affect the spontaneous imbibition recovery， and the imbibition recovery will increase with the increase in core hydrophilicity. There are differences in the oil recovery at the pore scale in different wettability core spontaneous imbibition， and the addition of nanoemulsion can significantly improve the recovery of small pores in the oil-wet core. Meanwhile，increasing nanoemulsion concentration and boundary openness can improve the spontaneous imbibition recovery efficiency. This is mainly because tight sandstone imbibition is dominated by capillary force，increasing boundary openness can expand the contact area of nanoemulsion，and increasing nanoemulsion concentration can improve the wettability alteration and emulsification，thus improving the effect of spontaneous imbibition.
Nanoemulsion， as a kind of nanoscale colloidal dispersion system， has been widely applied in unconventional oil reservoir development due to its outstanding interfacial properties and enhanced oil recovery effects. Water-in-oil type nanoemulsion systems are prepared based on the low-energy emulsification method. The intrinsic relationships among the static adsorption， wettability alteration， and spontaneous imbibition of nanoemulsion are determined by laboratory experiments， elucidating the mechanism of imbibition and production enhancement of nanoemulsion in tight sandstone oil reservoirs. The laboratory results show that the average droplet size of nanoemulsion is less than 10 nm， which can meet the droplet size requirement of entering most of the pore throat of tight sandstone and can fully diffuse and migrate in the tight pore throat， thus expanding the imbibition range. The critical micelle mass fraction of the nanoemulsion is 0.015%，which can effectively reduce the oil-water interfacial tension to about 2 mN/m. The adsorption isotherm of the nanoemulsion conforms to the Langmuir adsorption model， and the wettability alteration mechanism is mainly adsorption. The nanoemulsion can dissolve the crude oil， further disperse the crude oil through emulsification， reduce the size of oil droplets in the emulsion， and weaken the Jamin effect when oil droplets pass through the pore throat， reducing seepage resistance. Core wettability will affect the spontaneous imbibition recovery， and the imbibition recovery will increase with the increase in core hydrophilicity. There are differences in the oil recovery at the pore scale in different wettability core spontaneous imbibition， and the addition of nanoemulsion can significantly improve the recovery of small pores in the oil-wet core. Meanwhile，increasing nanoemulsion concentration and boundary openness can improve the spontaneous imbibition recovery efficiency. This is mainly because tight sandstone imbibition is dominated by capillary force，increasing boundary openness can expand the contact area of nanoemulsion，and increasing nanoemulsion concentration can improve the wettability alteration and emulsification，thus improving the effect of spontaneous imbibition.
2024, 31(1):137-144.
DOI: 10.13673/j.pgre.202306004
Abstract:
The factors affecting the remaining oil recoverable potential in ultra-high water-cut reservoirs are extremely complex， exhibiting substantial variations in their impact. Conventional methods often rely on singular indicators such as remaining oil saturation or remaining oil abundance to assess remaining oil recoverable potential， which fails to guide tapping remaining oil in ultrahigh water-cut reservoirs effectively. By considering the factors affecting the remaining oil recoverable potential in these reservoirs and comprehensively characterizing the heterogeneity of reservoirs，the scale of remaining oil reserves，watered conditions，and oil/water flow capacity，we constructed a quantitative assessment indicator system to tap the remaining oil recoverable potential in ultrahigh water-cut reservoirs. In addition， according to the control degree difference of the indicators on remaining oil recoverable potential， we determined the objective weights of each evaluation indicator by combining the accelerated genetic algorithm and the projection pursuit model. We constructed the remaining oil recoverable potential index to form a new quantitative assessment method of the remaining oil recoverable potential in ultra-high water-cut reservoirs. Taking the N mIL sand body of the main production layer in the south area of Bohai Q Oilfield as an example， we quantitatively assessed the remaining oil recoverable potential in ultra-high water-cut reservoirs. The results reveal that the new method can comprehensively characterize the effects of reservoir physical properties， remaining oil reserves， and dynamic characteristics of oil/water flow on the remaining oil recoverable potential in different locations and realize the differential quantitative assessment of the distribution of remaining oil recoverable potential in N mIL sand body of the main production layer. In addition， the dominant recoverable potential area is clearly characterized，and it is taken as the potential area for the subsequent adjustment of infill wells in the N mIL sand body to accurately guide the deployment of infill horizontal wells， thereby offering a novel perspective for tapping remaining oil resources in such reservoirs.
The factors affecting the remaining oil recoverable potential in ultra-high water-cut reservoirs are extremely complex， exhibiting substantial variations in their impact. Conventional methods often rely on singular indicators such as remaining oil saturation or remaining oil abundance to assess remaining oil recoverable potential， which fails to guide tapping remaining oil in ultrahigh water-cut reservoirs effectively. By considering the factors affecting the remaining oil recoverable potential in these reservoirs and comprehensively characterizing the heterogeneity of reservoirs，the scale of remaining oil reserves，watered conditions，and oil/water flow capacity，we constructed a quantitative assessment indicator system to tap the remaining oil recoverable potential in ultrahigh water-cut reservoirs. In addition， according to the control degree difference of the indicators on remaining oil recoverable potential， we determined the objective weights of each evaluation indicator by combining the accelerated genetic algorithm and the projection pursuit model. We constructed the remaining oil recoverable potential index to form a new quantitative assessment method of the remaining oil recoverable potential in ultra-high water-cut reservoirs. Taking the N mIL sand body of the main production layer in the south area of Bohai Q Oilfield as an example， we quantitatively assessed the remaining oil recoverable potential in ultra-high water-cut reservoirs. The results reveal that the new method can comprehensively characterize the effects of reservoir physical properties， remaining oil reserves， and dynamic characteristics of oil/water flow on the remaining oil recoverable potential in different locations and realize the differential quantitative assessment of the distribution of remaining oil recoverable potential in N mIL sand body of the main production layer. In addition， the dominant recoverable potential area is clearly characterized，and it is taken as the potential area for the subsequent adjustment of infill wells in the N mIL sand body to accurately guide the deployment of infill horizontal wells， thereby offering a novel perspective for tapping remaining oil resources in such reservoirs.
2024, 31(1):145-152.
DOI: 10.13673/j.pgre.202211027
Abstract:
The volume sweep coefficient is essential for evaluating the development effect and formulating development adjustment plans for oil fields. This paper aims to study the variation law of volume sweep coefficient in different stages of water injection development.From the perspective of the injection pore volume multiple， a calculation model is built of displacement efficiency and injection pore volume multiple， and a calculation method of volume sweep coefficient is proposed based on oil-water relative flow theory and reservoir engineering principle. In addition， three test areas of Shengli Oilfield are taken as examples for calculation and analysis. The results show that the relationship between the displacement efficiency and the injection pore volume multiple satisfies an exponential equation， and the relationship curve between the two is upward convex. As the injection pore volume multiple increases，the displacement efficiency gradually increases from the minimum displacement efficiency and approaches the maximum displacement efficiency. The displacement efficiency calculation model is verified， and the average relative error between the predicted and measured values is only 1.90%. During the water flooding development， the relationship curve between the volume sweep coefficient and the injection pore volume multiple shows an evolution trend of fast rising， slow rising， and near platform.The calculation results can guide the effect evaluation of development adjustment measures. At present， the volume sweep coefficient of the three test areas is about 90%. There is a large amount of remaining oil in the swept area. It is urgent to study the description and start-up method of the main remaining oil in the swept area.
The volume sweep coefficient is essential for evaluating the development effect and formulating development adjustment plans for oil fields. This paper aims to study the variation law of volume sweep coefficient in different stages of water injection development.From the perspective of the injection pore volume multiple， a calculation model is built of displacement efficiency and injection pore volume multiple， and a calculation method of volume sweep coefficient is proposed based on oil-water relative flow theory and reservoir engineering principle. In addition， three test areas of Shengli Oilfield are taken as examples for calculation and analysis. The results show that the relationship between the displacement efficiency and the injection pore volume multiple satisfies an exponential equation， and the relationship curve between the two is upward convex. As the injection pore volume multiple increases，the displacement efficiency gradually increases from the minimum displacement efficiency and approaches the maximum displacement efficiency. The displacement efficiency calculation model is verified， and the average relative error between the predicted and measured values is only 1.90%. During the water flooding development， the relationship curve between the volume sweep coefficient and the injection pore volume multiple shows an evolution trend of fast rising， slow rising， and near platform.The calculation results can guide the effect evaluation of development adjustment measures. At present， the volume sweep coefficient of the three test areas is about 90%. There is a large amount of remaining oil in the swept area. It is urgent to study the description and start-up method of the main remaining oil in the swept area.
2024, 31(1):153-162.
DOI: 10.13673/j.pgre.202305020
Abstract:
In order to effectively eliminate the reservoir damage caused by retrograde condensation in condensate gas reservoirs， a new method for removing the plugging pore throat of condensate oil by thermochemical fluid huff and puff was proposed. For tight sandstone， carbonate， and shale reservoirs， a core oil displacement experiment of thermochemical fluid huff and puff was carried out to evaluate the feasibility of removing condensate plugging by thermochemical fluid. Based on nuclear magnetic resonance technology，the change characteristics of the micro-pore structure of the three types of reservoirs before and after huff and puff were analyzed，and the mechanism of removing retrograde condensate damage by thermochemical fluid was clarified. The experimental results show that thermochemical fluids （NH4Cl and NaNO2） can rapidly release a large amount of gas and steam under the catalysis of acetic acid， increase the core pressure and temperature， reduce the viscosity of crude oil，make the condensate change from liquid to gas， and reduce the flow resistance. The cumulative condensate recoveries of tight sandstone， carbonate， and shale cores by thermochemical fluid huff and puff are 65.7%， 73.9%， and 46.3% respectively. Among them，two rounds of huff and puff can effectively remove 55.5% and 67.6% of condensate plugging in tight sandstone and carbonate samples respectively. However， the shale core needs to extend the soak time and increase the number of huff and puff to improve the recovery of condensate. After the thermochemical fluid huff and puff， the average pore size of tight sandstone， carbonate， and shale cores increases from 0.37， 1.04， and 0.002 1 μm to 0.84，2.04，and 0.005 8 μm respectively. The thermochemical fluid huff and puff effect is 1.85 and 1.32 times that of CH4injection and methanol injection respectively.
In order to effectively eliminate the reservoir damage caused by retrograde condensation in condensate gas reservoirs， a new method for removing the plugging pore throat of condensate oil by thermochemical fluid huff and puff was proposed. For tight sandstone， carbonate， and shale reservoirs， a core oil displacement experiment of thermochemical fluid huff and puff was carried out to evaluate the feasibility of removing condensate plugging by thermochemical fluid. Based on nuclear magnetic resonance technology，the change characteristics of the micro-pore structure of the three types of reservoirs before and after huff and puff were analyzed，and the mechanism of removing retrograde condensate damage by thermochemical fluid was clarified. The experimental results show that thermochemical fluids （NH4Cl and NaNO2） can rapidly release a large amount of gas and steam under the catalysis of acetic acid， increase the core pressure and temperature， reduce the viscosity of crude oil，make the condensate change from liquid to gas， and reduce the flow resistance. The cumulative condensate recoveries of tight sandstone， carbonate， and shale cores by thermochemical fluid huff and puff are 65.7%， 73.9%， and 46.3% respectively. Among them，two rounds of huff and puff can effectively remove 55.5% and 67.6% of condensate plugging in tight sandstone and carbonate samples respectively. However， the shale core needs to extend the soak time and increase the number of huff and puff to improve the recovery of condensate. After the thermochemical fluid huff and puff， the average pore size of tight sandstone， carbonate， and shale cores increases from 0.37， 1.04， and 0.002 1 μm to 0.84，2.04，and 0.005 8 μm respectively. The thermochemical fluid huff and puff effect is 1.85 and 1.32 times that of CH4injection and methanol injection respectively.
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