Volume 28,Issue 4,2021 Table of Contents
2021, 28(4):1-11.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.001
Abstract:
Middle-late Permian tight fluvial sandstone is the most important reservoir sequence in the Upper Paleozoic of Bohai Bay Basin. Based on field investigation of geological profile，analysis of logging data，thin-section identification as well as core observation and description，the sedimentary evolution and sandstone distribution of middle-late Permian fluvial facies in the study area were analyzed in detail. As a result，the middle-late Permian fluvial sediments mainly developed in Lower-Upper Shihezi Formation in Bohai Bay Basin with sand-rich Heishan Member，Wanshan Member，and Kuishan Member from bottom to top. A set of purple-red siliceous clastic sedimentary formation developed，featuring various rock types and colors，well-developed beddings，and strong hydrodynamic conditions for sediments. The Lower Shihezi Formation consists of meandering river deposits with developed marginal beaches，embankments，and flood basins but limited distribution of sandstones. With regard to the Upper Shihezi Formation，Wanshan Member gradually evolves to the braided river. Alternating sedimentation of channel bar，river channel，and flood basin and the number of layers and size of sandstone are both larger than those in the Lower Shihezi Formation；the clastic material supply of the source area in Kuishan Member was enhanced during the sedimentary period when the study area was characterized by braided river channels and channelbar deposits，forming a paleogeographic pattern of“basin full of sandstone”. The accumulated fluvial sandstone thickness in the residual framework of Lower Shihezi Formation in Bohai Bay Basin is generally less than 80 m，while the accumulated thickness of Wanshan Member-Kuishan Member of Upper Shihezi Formation is generally 40-120 m. Three thickness centers were developed in Jiyang Depression，Eastern Jizhong Depression-Huanghua Depression，and Central and Western Linqing Depression. The research results provide new technical support for oil and gas exploration and target optimization in Bohai Bay Basin in the Upper Paleozoic.
Middle-late Permian tight fluvial sandstone is the most important reservoir sequence in the Upper Paleozoic of Bohai Bay Basin. Based on field investigation of geological profile，analysis of logging data，thin-section identification as well as core observation and description，the sedimentary evolution and sandstone distribution of middle-late Permian fluvial facies in the study area were analyzed in detail. As a result，the middle-late Permian fluvial sediments mainly developed in Lower-Upper Shihezi Formation in Bohai Bay Basin with sand-rich Heishan Member，Wanshan Member，and Kuishan Member from bottom to top. A set of purple-red siliceous clastic sedimentary formation developed，featuring various rock types and colors，well-developed beddings，and strong hydrodynamic conditions for sediments. The Lower Shihezi Formation consists of meandering river deposits with developed marginal beaches，embankments，and flood basins but limited distribution of sandstones. With regard to the Upper Shihezi Formation，Wanshan Member gradually evolves to the braided river. Alternating sedimentation of channel bar，river channel，and flood basin and the number of layers and size of sandstone are both larger than those in the Lower Shihezi Formation；the clastic material supply of the source area in Kuishan Member was enhanced during the sedimentary period when the study area was characterized by braided river channels and channelbar deposits，forming a paleogeographic pattern of“basin full of sandstone”. The accumulated fluvial sandstone thickness in the residual framework of Lower Shihezi Formation in Bohai Bay Basin is generally less than 80 m，while the accumulated thickness of Wanshan Member-Kuishan Member of Upper Shihezi Formation is generally 40-120 m. Three thickness centers were developed in Jiyang Depression，Eastern Jizhong Depression-Huanghua Depression，and Central and Western Linqing Depression. The research results provide new technical support for oil and gas exploration and target optimization in Bohai Bay Basin in the Upper Paleozoic.
2021, 28(4):12-22.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.002
Abstract:
In the extensional faulted basin，the displacement transfer between faults is enabled through the transfer zones to realize the conservation of regional extensional stress. The transfer zones of Lishui Sag in the East China Sea shelf basin are well developed，exerting a vital influence on the sag structure. Based on the systematic investigation into research status of transfer zones and the interpretation of regional structures in Lishui Sag，the locations，types and characteristics of the transfer zones in Lishui Sag were analyzed in detail through structural analysis，fault analysis，fault growth process recovery，fault displacement-strike curve and other methods. As a result，three main types of transfer zones were identified：relay ramps，transfer faults，and accommodation zones. It is believed that the transfer zones are the main reason for the sharp change in the strike of the main Lingfeng Fault of Lishui Sag and the transition of the sedimentary center in the basin，and the western sub-sag of Lishui Sag is divided into the north and south structural belts. Then the influence of the transfer zones on the process of sediment input into the basin and its control on the reservoir are studied. It is considered that the relay ramps between major boundary faults in Lishui Sag constitute a favorable accumulation zones.
In the extensional faulted basin，the displacement transfer between faults is enabled through the transfer zones to realize the conservation of regional extensional stress. The transfer zones of Lishui Sag in the East China Sea shelf basin are well developed，exerting a vital influence on the sag structure. Based on the systematic investigation into research status of transfer zones and the interpretation of regional structures in Lishui Sag，the locations，types and characteristics of the transfer zones in Lishui Sag were analyzed in detail through structural analysis，fault analysis，fault growth process recovery，fault displacement-strike curve and other methods. As a result，three main types of transfer zones were identified：relay ramps，transfer faults，and accommodation zones. It is believed that the transfer zones are the main reason for the sharp change in the strike of the main Lingfeng Fault of Lishui Sag and the transition of the sedimentary center in the basin，and the western sub-sag of Lishui Sag is divided into the north and south structural belts. Then the influence of the transfer zones on the process of sediment input into the basin and its control on the reservoir are studied. It is considered that the relay ramps between major boundary faults in Lishui Sag constitute a favorable accumulation zones.
2021, 28(4):23-34.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.003
Abstract:
Chang 3 reservoir of Yanchang Formation in Weibei Oilfield is a low-ultra-low permeability reservoir. The relationship between pore throat microstructures and fluid availability and the percolation mechanism are unclear during the water injection development of this reservoir. With regard to this problem，microscopic water flooding experiments on real sandstones were performed to investigate the pore throat microstructures，water-flooding percolation characteristics，and their influencing factors in Chang 3 reservoir of Yanchang Formation in Weibei Oilfield，using the casting thin-section analysis，scanning electron microscopy，high-pressure mercury intrusion，physical property analysis，and other test methods.The results show that Chang 3 reservoir space in the study area is dominated by intergranular pores，intergranular dissolved pores，and intragranular dissolved pores，with flaky and necking throats. The pore throat structures can be divided into TypesⅠ，ⅡandⅢ，and their corresponding percolation characteristics in reservoirs and water displacement efficiencies are distinctly different. The water displacement in TypesⅠ-Ⅱpore throat structures mainly belongs to the piston-like，while that in TypeⅢpore throat structure is mainly the non-piston-like. In the pore networks，the water displacement pattern is mainly uniform and networked-uniform in TypeⅠpore throat structure；while networked in TypeⅡstructure；meanwhile finger-shaped–networked in TypeⅢstructure. In addition，the physical properties of the reservoirs corresponding to Types Ⅰ-Ⅲpore throat structures gradually deteriorate；the number of small pore throats increases；the ultimate oil displacement efficiency decreases successively. Reservoir physical properties，pore throat structure，displacement pressure，and water injection multiples all influence the water-flooding percolation characteristics and the ultimate displacement efficiency. The more favorable reservoir physical properties and the better pore throat structure can lead to the higher water flooding efficiency，and appropriately increasing injection pressure and water injection multiples can enhance the ultimate water displacement recovery.
Chang 3 reservoir of Yanchang Formation in Weibei Oilfield is a low-ultra-low permeability reservoir. The relationship between pore throat microstructures and fluid availability and the percolation mechanism are unclear during the water injection development of this reservoir. With regard to this problem，microscopic water flooding experiments on real sandstones were performed to investigate the pore throat microstructures，water-flooding percolation characteristics，and their influencing factors in Chang 3 reservoir of Yanchang Formation in Weibei Oilfield，using the casting thin-section analysis，scanning electron microscopy，high-pressure mercury intrusion，physical property analysis，and other test methods.The results show that Chang 3 reservoir space in the study area is dominated by intergranular pores，intergranular dissolved pores，and intragranular dissolved pores，with flaky and necking throats. The pore throat structures can be divided into TypesⅠ，ⅡandⅢ，and their corresponding percolation characteristics in reservoirs and water displacement efficiencies are distinctly different. The water displacement in TypesⅠ-Ⅱpore throat structures mainly belongs to the piston-like，while that in TypeⅢpore throat structure is mainly the non-piston-like. In the pore networks，the water displacement pattern is mainly uniform and networked-uniform in TypeⅠpore throat structure；while networked in TypeⅡstructure；meanwhile finger-shaped–networked in TypeⅢstructure. In addition，the physical properties of the reservoirs corresponding to Types Ⅰ-Ⅲpore throat structures gradually deteriorate；the number of small pore throats increases；the ultimate oil displacement efficiency decreases successively. Reservoir physical properties，pore throat structure，displacement pressure，and water injection multiples all influence the water-flooding percolation characteristics and the ultimate displacement efficiency. The more favorable reservoir physical properties and the better pore throat structure can lead to the higher water flooding efficiency，and appropriately increasing injection pressure and water injection multiples can enhance the ultimate water displacement recovery.
WANG Yue
,
YU Hongzhou
,
XIONG Wei
,
WANG Qianjun
,
ZHANG Guanlong
,
XIAO Xiongfei
,
XUE Yan
,
WANG Yuxin
2021, 28(4):35-45.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.004
Abstract:
The Permian Pingdiquan Formation is an important exploration stratum in the eastern uplift area of Junggar Basin. On the west side of the uplift area，Huoshaoshan Oilfield with abundant petroleum geological reserves has been found in Zhangbei fault-fold belt，while in Shiqiantan Sag on the east side，only oil and gas shows are observed，with an unclear future direction for favorable exploration. Through systematic analysis of seismic survey，outcrops，as well as drilling and logging data，the sequence stratigraphic units of Pingdiquan Formation were divided，and the sedimentary characteristics within the sequence stratigraphic framework were clarified. In addition，a sequence sedimentary filling model was constructed. Accordingly，the petroleum geological characteristics in Shiqiantan Sag were analyzed. The results indicate that Pingdiquan Formation in Shiqiantan Sag is divided into two third-order sequences from bottom to top. Sequence1 developed the lowstand system tract，the transgressive system tract and the highstand system tract，while Sequence 2 developed the lowstand system tract and the transgressive system tract，without the highstand system tract. During the sedimentary period of Sequence1，deltas and fan deltas developed in the north and south of Shiqiantan Sag，and the dark shale of semi-deepdeep lacustrine facies developed in the transgressive system tract，becoming a set of good source rocks. In the sedimentary period of Sequence 2，fan deltas and shore-shallow lacustrine sediment developed in Shiqiantan Sag from north to south. In Sequence 1，the fan delta front and grey flat in the transgressive system tract and the fan delta front，delta front，and grey flat in the highstand system tract are adjacent to source rocks，which are the most favorable sedimentary facies belts in the study area. The progradational sandbody at the delta front of the highstand system tract represents a favorable exploration direction for lithologic reservoirs.
The Permian Pingdiquan Formation is an important exploration stratum in the eastern uplift area of Junggar Basin. On the west side of the uplift area，Huoshaoshan Oilfield with abundant petroleum geological reserves has been found in Zhangbei fault-fold belt，while in Shiqiantan Sag on the east side，only oil and gas shows are observed，with an unclear future direction for favorable exploration. Through systematic analysis of seismic survey，outcrops，as well as drilling and logging data，the sequence stratigraphic units of Pingdiquan Formation were divided，and the sedimentary characteristics within the sequence stratigraphic framework were clarified. In addition，a sequence sedimentary filling model was constructed. Accordingly，the petroleum geological characteristics in Shiqiantan Sag were analyzed. The results indicate that Pingdiquan Formation in Shiqiantan Sag is divided into two third-order sequences from bottom to top. Sequence1 developed the lowstand system tract，the transgressive system tract and the highstand system tract，while Sequence 2 developed the lowstand system tract and the transgressive system tract，without the highstand system tract. During the sedimentary period of Sequence1，deltas and fan deltas developed in the north and south of Shiqiantan Sag，and the dark shale of semi-deepdeep lacustrine facies developed in the transgressive system tract，becoming a set of good source rocks. In the sedimentary period of Sequence 2，fan deltas and shore-shallow lacustrine sediment developed in Shiqiantan Sag from north to south. In Sequence 1，the fan delta front and grey flat in the transgressive system tract and the fan delta front，delta front，and grey flat in the highstand system tract are adjacent to source rocks，which are the most favorable sedimentary facies belts in the study area. The progradational sandbody at the delta front of the highstand system tract represents a favorable exploration direction for lithologic reservoirs.
2021, 28(4):47-54.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.005
Abstract:
According to massive data from core experiments，we systematically studied the main controlling factors of the clastic reservoir property difference in the Lower Member of the Lower Ganchaigou Formation within the same sedimentary system but different plays in the western Qaidam Basin. The results reveal that the variations in sedimentary environment，lithological characteristics，sand body thickness，burial history，geothermal gradients and lake water paleosalinity contribute heavily to the reservoir property difference. The distributary channel sand in the delta plain，the underwater distributary channel sand at the delta front and the beach-bar sand in the shore-shallow lake facies are widely developed in the Lower Member of the Lower Ganchaigou Formation of the western Qaidam Basin，providing a basis for high-quality reservoirs.Sand body thickness，matrix content and clastic particle are the important controlling factors of reservoir properties. Diagenesis plays a decisive role in reservoir evolution and properties，among which compaction has the strongest impact on reservoir properties，while cementation is a significant controlling factor in the local play. In the same sedimentary system，the difference in reservoir compaction strength is dominated by clastic particle sorting and matrix content of the distributary channel sand in the delta plain. Moreover，the variation in reservoir cementation strength is controlled by the particle size and thickness of both the distributary channel sand at the delta front and the beach-bar sand in the shore-shallow lake facies. In different plays，different burial history and geothermal gradients result in the great variation in reservoir compaction，while the circular and banded distribution of lake water paleosalinity around the salt lake center lead to the reservoir cementation difference on the plane.
According to massive data from core experiments，we systematically studied the main controlling factors of the clastic reservoir property difference in the Lower Member of the Lower Ganchaigou Formation within the same sedimentary system but different plays in the western Qaidam Basin. The results reveal that the variations in sedimentary environment，lithological characteristics，sand body thickness，burial history，geothermal gradients and lake water paleosalinity contribute heavily to the reservoir property difference. The distributary channel sand in the delta plain，the underwater distributary channel sand at the delta front and the beach-bar sand in the shore-shallow lake facies are widely developed in the Lower Member of the Lower Ganchaigou Formation of the western Qaidam Basin，providing a basis for high-quality reservoirs.Sand body thickness，matrix content and clastic particle are the important controlling factors of reservoir properties. Diagenesis plays a decisive role in reservoir evolution and properties，among which compaction has the strongest impact on reservoir properties，while cementation is a significant controlling factor in the local play. In the same sedimentary system，the difference in reservoir compaction strength is dominated by clastic particle sorting and matrix content of the distributary channel sand in the delta plain. Moreover，the variation in reservoir cementation strength is controlled by the particle size and thickness of both the distributary channel sand at the delta front and the beach-bar sand in the shore-shallow lake facies. In different plays，different burial history and geothermal gradients result in the great variation in reservoir compaction，while the circular and banded distribution of lake water paleosalinity around the salt lake center lead to the reservoir cementation difference on the plane.
2021, 28(4):55-62.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.006
Abstract:
With the meandering river of Minghuazhen Formation in C Oilfield，Bohai Bay Basin as an example，a new equivalent characterization method is explored for the three-level architecture of meandering river reservoirs. The advantages，disadvantages and applicability of three common characterization methods of lateral accretion shale beddings are summarized，and the difficulties in the fine characterization of the C Oilfield are pointed out. On this basis，a new characterization method of unstructured depogrid is introduced to simulate lateral accretion shale beddings of the three-level architectures of meandering river reservoirs. The thickness and morphology of lateral accretion shale beddings simulated by the new method，compared with those by the other three methods，are more in line with their real subsurface morphology. The proposed method overcomes the problems of conventional methods such as distorting the grid，mismatching with the borehole data and being greatly affected by the grid size. The new method is used to construct the fine characterization models of the three-level architectures of meandering river reservoirs in the study area，and the numerical reservoir simulation of the models is carried out. Compared with conventional methods，the new method enables the smoother fluid migration path near lateral accretion shale beddings and the pressure recovery time closer to the real subsurface situation. Combined with the results of numerical reservoir simulation，the fluid migration modes of two types of horizontal wells under the influence of lateral accretion shale beddings are summarized to guide subsequent well deployment.
With the meandering river of Minghuazhen Formation in C Oilfield，Bohai Bay Basin as an example，a new equivalent characterization method is explored for the three-level architecture of meandering river reservoirs. The advantages，disadvantages and applicability of three common characterization methods of lateral accretion shale beddings are summarized，and the difficulties in the fine characterization of the C Oilfield are pointed out. On this basis，a new characterization method of unstructured depogrid is introduced to simulate lateral accretion shale beddings of the three-level architectures of meandering river reservoirs. The thickness and morphology of lateral accretion shale beddings simulated by the new method，compared with those by the other three methods，are more in line with their real subsurface morphology. The proposed method overcomes the problems of conventional methods such as distorting the grid，mismatching with the borehole data and being greatly affected by the grid size. The new method is used to construct the fine characterization models of the three-level architectures of meandering river reservoirs in the study area，and the numerical reservoir simulation of the models is carried out. Compared with conventional methods，the new method enables the smoother fluid migration path near lateral accretion shale beddings and the pressure recovery time closer to the real subsurface situation. Combined with the results of numerical reservoir simulation，the fluid migration modes of two types of horizontal wells under the influence of lateral accretion shale beddings are summarized to guide subsequent well deployment.
2021, 28(4):63-70.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.007
Abstract:
When the traditional partitioned modeling method simulates reservoir distribution with multiple sources，the simulated sandbodies show abrupt contact at the boundaries between segments，which does not conform to geological understanding. Therefore，this paper proposed a partitioning coupled modeling method for multi-source reservoirs. Firstly，the research area was divided into several segments according to the influence ranges of different sources and then each part was simulated in a specific order. The simulation results on the segment boundaries modeled earlier were extracted as the conditional data for the adjacent segments modeled later. After combining the well-point data within the segments modeled later，the simulation calculation ensured the continuity of the sandbodies at the boundaries between segments. Finally，the sandbody model of the entire research area was obtained and the simulated sandbodies were continuous on each segment boundary. This paper performed the applied study with the upper sub-member of the fourth member of the Shahejie Formation in the Y935-936 block of the Yanjia Oilfield in the Dongying Sag as the example. The proposed method was compared with traditional partitioned modeling and the variogram modeling based on local variations. The result demonstrates that the partitioned coupling modeling method can build a more realistic three-dimensional geological model of the research area，eliminating the abrupt contact between sandbodies induced by traditional partitioned modeling and improving the modeling quality.
When the traditional partitioned modeling method simulates reservoir distribution with multiple sources，the simulated sandbodies show abrupt contact at the boundaries between segments，which does not conform to geological understanding. Therefore，this paper proposed a partitioning coupled modeling method for multi-source reservoirs. Firstly，the research area was divided into several segments according to the influence ranges of different sources and then each part was simulated in a specific order. The simulation results on the segment boundaries modeled earlier were extracted as the conditional data for the adjacent segments modeled later. After combining the well-point data within the segments modeled later，the simulation calculation ensured the continuity of the sandbodies at the boundaries between segments. Finally，the sandbody model of the entire research area was obtained and the simulated sandbodies were continuous on each segment boundary. This paper performed the applied study with the upper sub-member of the fourth member of the Shahejie Formation in the Y935-936 block of the Yanjia Oilfield in the Dongying Sag as the example. The proposed method was compared with traditional partitioned modeling and the variogram modeling based on local variations. The result demonstrates that the partitioned coupling modeling method can build a more realistic three-dimensional geological model of the research area，eliminating the abrupt contact between sandbodies induced by traditional partitioned modeling and improving the modeling quality.
2021, 28(4):71-76.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.008
Abstract:
CO2 flooding can substantially improve recovery while achieving carbon storage，maintaining a balance between economic benefits and environmental protection. Accordingly，it is necessary to research the diffusion law of CO2 in reservoirs. Experiments of CO2 diffusion in oil-saturated cores were conducted with self-designed HTHP diffusion sample holders. A mathematical model was established for calculating the diffusion coefficient of CO2 in oil-saturated cores. The measured pressure curves were fitted with the theoretical pressure curves to determine the CO2 diffusion coefficient. In addition，the influence of permeability on CO2 diffusion in oil-saturated cores was analyzed. The research results demonstrate that the mathematical model can faithfully reflect the CO2 diffusion law in oil-saturated cores，and the measured diffusion coefficients are highly accurate. The diffusion coefficient of CO2 in oil-saturated cores is at the order of magnitude of 10-8 m2/s within the experimental range. The diffusion coefficient of CO2 in cores increases with the rise in permeability，but the increment declines.
CO2 flooding can substantially improve recovery while achieving carbon storage，maintaining a balance between economic benefits and environmental protection. Accordingly，it is necessary to research the diffusion law of CO2 in reservoirs. Experiments of CO2 diffusion in oil-saturated cores were conducted with self-designed HTHP diffusion sample holders. A mathematical model was established for calculating the diffusion coefficient of CO2 in oil-saturated cores. The measured pressure curves were fitted with the theoretical pressure curves to determine the CO2 diffusion coefficient. In addition，the influence of permeability on CO2 diffusion in oil-saturated cores was analyzed. The research results demonstrate that the mathematical model can faithfully reflect the CO2 diffusion law in oil-saturated cores，and the measured diffusion coefficients are highly accurate. The diffusion coefficient of CO2 in oil-saturated cores is at the order of magnitude of 10-8 m2/s within the experimental range. The diffusion coefficient of CO2 in cores increases with the rise in permeability，but the increment declines.
2021, 28(4):77-85.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.009
Abstract:
To investigate the molecular properties and microscopic aggregation of asphaltenes and the microcosmic mechanism of asphaltene deposition，we adopt molecular dynamics methods to establish the average molecular configuration of representative asphaltenes. It can be utilized to construct the initial configuration of the asphaltene simulation system to simulate the migration of asphaltenes in the formation rock. The simulation experiment results indicate the radial distribution of asphaltenes，as typical amorphous matter，are generally in the pattern of short-range order and long-range disorder.In addition，simulated annealing optimization can fully release stress from the molecular structure，which is conducive to reducing its energy ground state. As the distance between molecules increases，the Van der Waals interaction between the molecules becomes weak，but the electrostatic interaction becomes dominant among non-bonding interactions of the system.It can be observed from the final migration state of the asphaltene simulation system that the main body of aromatic nucleus and part of the aliphatic chain of the asphaltene molecules tend to be gradually adsorbed to the surface of the silica molecular layer，altering the wettability of the rock surface from hydrophilic to lipophilic. The π-π stacking of the aromatic nucleus drives the asphaltene molecules to aggregate，leading to the flocculation and deposition of asphaltenes from crude oil.Wettability alteration and the pore-throat blockage of rock are important mechanisms for the reduction of oil recovery caused by asphaltene deposition.
To investigate the molecular properties and microscopic aggregation of asphaltenes and the microcosmic mechanism of asphaltene deposition，we adopt molecular dynamics methods to establish the average molecular configuration of representative asphaltenes. It can be utilized to construct the initial configuration of the asphaltene simulation system to simulate the migration of asphaltenes in the formation rock. The simulation experiment results indicate the radial distribution of asphaltenes，as typical amorphous matter，are generally in the pattern of short-range order and long-range disorder.In addition，simulated annealing optimization can fully release stress from the molecular structure，which is conducive to reducing its energy ground state. As the distance between molecules increases，the Van der Waals interaction between the molecules becomes weak，but the electrostatic interaction becomes dominant among non-bonding interactions of the system.It can be observed from the final migration state of the asphaltene simulation system that the main body of aromatic nucleus and part of the aliphatic chain of the asphaltene molecules tend to be gradually adsorbed to the surface of the silica molecular layer，altering the wettability of the rock surface from hydrophilic to lipophilic. The π-π stacking of the aromatic nucleus drives the asphaltene molecules to aggregate，leading to the flocculation and deposition of asphaltenes from crude oil.Wettability alteration and the pore-throat blockage of rock are important mechanisms for the reduction of oil recovery caused by asphaltene deposition.
GU Hao
,
KANG Zhijiang
,
SHANG Genhua
,
ZHENG Songqing
,
ZHU Guiliang
,
ZHANG Yun
,
ZHU Xiansheng
,
ZHU Lianhua
2021, 28(4):86-92.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.010
Abstract:
With the Q Oilfield in the Tarim Basin as an example，according to the principle of material balance，the main controlling factors behind elastic flooding productivity of ultra-deep fault-karst reservoirs are analyzed from the reserves，energy，fluidity 3 aspects to explain the difference in elastic flooding productivity at different fault orders. The results show that the main controlling factors include the scale of fracture-cavity reservoirs，elastic energy of formations and flow capacity of fluids. These three factors，on the whole，all play a greater role at the main fault than at the branch fault and contribute more at the branch fault than at the secondary fault. There is a strong linear relationship of single-well controlled reserves with cumulative oil production，daily oil production，and staged cumulative oil production of a single well by elastic flooding. The products of initial formation pressure with the cumulative oil production and controlled reserves of a single well manifest as a straight line with a slope of approximately 1 on the logarithmic coordinate. The comprehensive elastic compressibility coefficient and the fracture-cavity reservoir scale have a greater influence on cumulative oil production than initial formation pressure. The stronger fluid flow capacity indicates the higher average daily oil production per well. For the greater elastic flooding productivity of ultra-deep fault-karst reservoirs，the fracture-cavity reservoirs with a large scale and a high level of formation breakage should be preferred in the early deployment of well locations，and single-well controlled reserves should be maximized in the middle and late stages of development.
With the Q Oilfield in the Tarim Basin as an example，according to the principle of material balance，the main controlling factors behind elastic flooding productivity of ultra-deep fault-karst reservoirs are analyzed from the reserves，energy，fluidity 3 aspects to explain the difference in elastic flooding productivity at different fault orders. The results show that the main controlling factors include the scale of fracture-cavity reservoirs，elastic energy of formations and flow capacity of fluids. These three factors，on the whole，all play a greater role at the main fault than at the branch fault and contribute more at the branch fault than at the secondary fault. There is a strong linear relationship of single-well controlled reserves with cumulative oil production，daily oil production，and staged cumulative oil production of a single well by elastic flooding. The products of initial formation pressure with the cumulative oil production and controlled reserves of a single well manifest as a straight line with a slope of approximately 1 on the logarithmic coordinate. The comprehensive elastic compressibility coefficient and the fracture-cavity reservoir scale have a greater influence on cumulative oil production than initial formation pressure. The stronger fluid flow capacity indicates the higher average daily oil production per well. For the greater elastic flooding productivity of ultra-deep fault-karst reservoirs，the fracture-cavity reservoirs with a large scale and a high level of formation breakage should be preferred in the early deployment of well locations，and single-well controlled reserves should be maximized in the middle and late stages of development.
2021, 28(4):93-100.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.011
Abstract:
The oil-water interaction in water-flooding is scarcely studied and the existing conclusions are controversial，which is mainly reflected in a lack of a unified conclusions of potential determining ions on oil-water interaction. Experiments on coreflooding and interfacial tension measurement were combined to study the oil-water interaction law and mechanism in smart water-flooding. The results show that oil-water interaction plays an important role in smart water-flooding，and adjusting the ion composition of the injected water can considerably influence recovery factors. Mg2+ and Ca2+ can effectively improve coreflooding efficiency，of which Mg2+ performs better, and they both have optimal concentrations. SO42- has no positive effect on enhencing recovery factors. According to interfacial tension measurement，the effects of ions in the solution on the characteristics of the oil-water interface vary enormously in the intensity order of Mg2+ > Ca2+ > Na+. As the concentrations of Na+，Ca2+，and Mg2+ increase，the oil-water interfacial tension goes down first and up then，and the interfacial relaxation time first shortens and then lengthens. There are optimal concentrations that lead to the lowest interfacial tension and the shortest interfacial relaxation time. SO42- can effectively inhibit the influence of Na+，Mg2+，and Ca2+ on the characteristics of the oil-water interface，increase optimal ion concentrations corresponding to the lowest oil-water interfacial tension，and extend the time for the oil-water interface system to reach equilibrium.
The oil-water interaction in water-flooding is scarcely studied and the existing conclusions are controversial，which is mainly reflected in a lack of a unified conclusions of potential determining ions on oil-water interaction. Experiments on coreflooding and interfacial tension measurement were combined to study the oil-water interaction law and mechanism in smart water-flooding. The results show that oil-water interaction plays an important role in smart water-flooding，and adjusting the ion composition of the injected water can considerably influence recovery factors. Mg2+ and Ca2+ can effectively improve coreflooding efficiency，of which Mg2+ performs better, and they both have optimal concentrations. SO42- has no positive effect on enhencing recovery factors. According to interfacial tension measurement，the effects of ions in the solution on the characteristics of the oil-water interface vary enormously in the intensity order of Mg2+ > Ca2+ > Na+. As the concentrations of Na+，Ca2+，and Mg2+ increase，the oil-water interfacial tension goes down first and up then，and the interfacial relaxation time first shortens and then lengthens. There are optimal concentrations that lead to the lowest interfacial tension and the shortest interfacial relaxation time. SO42- can effectively inhibit the influence of Na+，Mg2+，and Ca2+ on the characteristics of the oil-water interface，increase optimal ion concentrations corresponding to the lowest oil-water interfacial tension，and extend the time for the oil-water interface system to reach equilibrium.
2021, 28(4):101-106.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.012
Abstract:
In the Shengli Oilfield，the temperature of ultra-high temperature reservoirs is 95-120 ℃. The existing polymer for oil displacement，after being placed at this temperature for 30 d，has a hydrolysis degree of about 100% and viscosity of only 1 mPa·s. Its oil displacement performance is greatly affected and cannot meet the polymer flooding requirements of this type of reservoirs. To improve the thermal stability and oil displacement performance of the polymer at ultra-high temperatures，we selected a new type of polymer with ultra-high temperature and hydrolysis resistance by introducing the AMPS and NVP monomer. We studied the performance of the polymer，including viscosity-increasing，rheology，injection and oil displacement，in ultra-high temperature reservoirs，and focused on the thermal stability of hydrolysis degree and viscosity of the polymer at 120 ℃. The results demonstrate that compared with conventional partially hydrolyzed polyacrylamide with similar relative molecular mass，the polymer in this paper has the more than doubled initial viscosity. With the viscoelastic performance greatly enhanced，it performs well in injection and oil displacement. After being placed at 120 ℃ for 30 d，it still has a hydrolysis degree of 0 and constant viscosity，indicating great thermal stability. It is promising to be applied to the ultra-high temperature reservoirs in the Shengli Oilfield，breaking through the temperature limit of EOR by chemical flooding.
In the Shengli Oilfield，the temperature of ultra-high temperature reservoirs is 95-120 ℃. The existing polymer for oil displacement，after being placed at this temperature for 30 d，has a hydrolysis degree of about 100% and viscosity of only 1 mPa·s. Its oil displacement performance is greatly affected and cannot meet the polymer flooding requirements of this type of reservoirs. To improve the thermal stability and oil displacement performance of the polymer at ultra-high temperatures，we selected a new type of polymer with ultra-high temperature and hydrolysis resistance by introducing the AMPS and NVP monomer. We studied the performance of the polymer，including viscosity-increasing，rheology，injection and oil displacement，in ultra-high temperature reservoirs，and focused on the thermal stability of hydrolysis degree and viscosity of the polymer at 120 ℃. The results demonstrate that compared with conventional partially hydrolyzed polyacrylamide with similar relative molecular mass，the polymer in this paper has the more than doubled initial viscosity. With the viscoelastic performance greatly enhanced，it performs well in injection and oil displacement. After being placed at 120 ℃ for 30 d，it still has a hydrolysis degree of 0 and constant viscosity，indicating great thermal stability. It is promising to be applied to the ultra-high temperature reservoirs in the Shengli Oilfield，breaking through the temperature limit of EOR by chemical flooding.
2021, 28(4):107-112.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.013
Abstract:
Conglomerate reservoirs are strongly heterogenous and complex in pore structures，and the microscopic percolation system presents sparse network-non-network characteristics. Conventional chemical flooding can easily cause chemical agents to protrude along high-permeability layers and the medium- and low-permeability layers are difficult to exploit，leading to limited swept volume and low oil displacement efficiency. Through the explorative research in a conglomerate reservoir in Block K7，Karamay Oilfield，Xinjiang，an oil recovery method of“cascaded injection and graded production”is proposed，dramatically enhancing oil recovery. This method combines the reservoir percolation theory and core analysis.Firstly，a calculation model of the decline rate of inter-well pressure gradients is constructed，which is affected by reservoir heterogeneity. Secondly，the major influencing factors of the percolation resistance to the chemical agent medium are determined，and a calculation formula of percolation resistance is created on the basis of the microscopic pore structure parameters of the reservoir，the mass concentration of polymer solution，and the polymer molecular weight. According to the theory that oil displacement media can flow in reservoir only when the displacement pressure gradient is greater than percolation resistance，the high-resistance chemical agent system can only enter the large pore-throat permeable layer at a constant injection rate and a fixed injection-production well spacing. As the system continues to advance，the displacement pressure gradient plummets and the chemical agent system can stay and block the large pore-throat permeable layer. At this time，the mass concentration of the system can be reduced in a cascaded manner，and the resistance coefficient can be lowered，so that the system can enter permeable layers at different pore throat levels sequentially，and the remaining oil in different microscopic pore spaces can be produced in grades. This theory has achieved good application effects in the field test of Block K7，the oil recovery enhanced by 15.9% in the chemical flooding stage of the reservoir.
Conglomerate reservoirs are strongly heterogenous and complex in pore structures，and the microscopic percolation system presents sparse network-non-network characteristics. Conventional chemical flooding can easily cause chemical agents to protrude along high-permeability layers and the medium- and low-permeability layers are difficult to exploit，leading to limited swept volume and low oil displacement efficiency. Through the explorative research in a conglomerate reservoir in Block K7，Karamay Oilfield，Xinjiang，an oil recovery method of“cascaded injection and graded production”is proposed，dramatically enhancing oil recovery. This method combines the reservoir percolation theory and core analysis.Firstly，a calculation model of the decline rate of inter-well pressure gradients is constructed，which is affected by reservoir heterogeneity. Secondly，the major influencing factors of the percolation resistance to the chemical agent medium are determined，and a calculation formula of percolation resistance is created on the basis of the microscopic pore structure parameters of the reservoir，the mass concentration of polymer solution，and the polymer molecular weight. According to the theory that oil displacement media can flow in reservoir only when the displacement pressure gradient is greater than percolation resistance，the high-resistance chemical agent system can only enter the large pore-throat permeable layer at a constant injection rate and a fixed injection-production well spacing. As the system continues to advance，the displacement pressure gradient plummets and the chemical agent system can stay and block the large pore-throat permeable layer. At this time，the mass concentration of the system can be reduced in a cascaded manner，and the resistance coefficient can be lowered，so that the system can enter permeable layers at different pore throat levels sequentially，and the remaining oil in different microscopic pore spaces can be produced in grades. This theory has achieved good application effects in the field test of Block K7，the oil recovery enhanced by 15.9% in the chemical flooding stage of the reservoir.
2021, 28(4):113-119.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.014
Abstract:
Ordovician deep carbonate rocks have become an important field of natural gas exploration in Changqing. However，compared with the conventional dolomite reservoirs，the Ordovician carbonate reservoirs are deeply buried and tight with high limestone content and fast acid-rock reaction. Conventional acid-fracturing is confronted with short acid-etched fractures and low single-well production. Therefore，it is necessary to study acid-fracturing mechanism and optimize the deep acid-fracturing technique to improve the acid-fracturing effect. In accordance with the reservoir geological characteristics and the demand for acid-fracturing，the kinetic experiments of acid-rock reaction，the evaluation of acid etching，and the numerical simulation of acid fracturing were carried out to clarify the differences in the acid-rock reaction mechanism of carbonate reservoirs with different dolomite contents：With the decrease in dolomite content and increase in limestone content，the acid-rock reaction is accelerated with severer acid etching on the rock surface，while the length of acid-etched fractures witnesses a decline. Hence，the differential design of carbonate reservoirs with different dolomite contents should be strengthened. The deep acid-fracturing technology with the core of“hydraulic fracture generation by prepad fluid，alternative acid injection by multi-system，and internal fracture turning”was optimized based on the idea of“forming hydraulic fractures first and then conducting acid etching”. Through the joint action of acid solution and fracturing fluid，a fracture network connecting hydraulic fractures，acid-etched fractures，and matrix dissolved pores was formed. In the field test，our technology has played a role in raising production.
Ordovician deep carbonate rocks have become an important field of natural gas exploration in Changqing. However，compared with the conventional dolomite reservoirs，the Ordovician carbonate reservoirs are deeply buried and tight with high limestone content and fast acid-rock reaction. Conventional acid-fracturing is confronted with short acid-etched fractures and low single-well production. Therefore，it is necessary to study acid-fracturing mechanism and optimize the deep acid-fracturing technique to improve the acid-fracturing effect. In accordance with the reservoir geological characteristics and the demand for acid-fracturing，the kinetic experiments of acid-rock reaction，the evaluation of acid etching，and the numerical simulation of acid fracturing were carried out to clarify the differences in the acid-rock reaction mechanism of carbonate reservoirs with different dolomite contents：With the decrease in dolomite content and increase in limestone content，the acid-rock reaction is accelerated with severer acid etching on the rock surface，while the length of acid-etched fractures witnesses a decline. Hence，the differential design of carbonate reservoirs with different dolomite contents should be strengthened. The deep acid-fracturing technology with the core of“hydraulic fracture generation by prepad fluid，alternative acid injection by multi-system，and internal fracture turning”was optimized based on the idea of“forming hydraulic fractures first and then conducting acid etching”. Through the joint action of acid solution and fracturing fluid，a fracture network connecting hydraulic fractures，acid-etched fractures，and matrix dissolved pores was formed. In the field test，our technology has played a role in raising production.
GAO Yihua
,
JIANG Bin
,
ZHANG Yingchun
,
YUAN Zhiwang
,
KANG Botao
,
DUAN Ruikai
,
LI Chenxi
,
CHEN Guoning
2021, 28(4):120-130.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.015
Abstract:
It is difficult to evaluate the infill well productivity of multi-layer reservoirs in old offshore oilfields due to the interlayer heterogeneity of producers and water breakthrough at the initial stage of production. Interlayer interference coefficient is usually used to describe the effect of commingled production on infill well productivity in multi-layer reservoirs.However，the interlayer interference coefficient can hardly be quantitatively characterized. To solve this，with dynamic and static data from old offshore oilfields，we propose a new method to evaluate the infill well productivity of multi-layer reservoirs. The paper introduces the concept of injection-production affection efficiency. A method that analyzes the injectionproduction affection efficiency of multi-layer reservoirs is worked out by integrating modular dynamics test（MDT）results，production logging test（PLT）results，logging interpretation results of water-out reservoirs，and static geological knowledge. By the method，the unaffected layers without contribution to stable productivity can be identified. Furthermore，the dynamic relative permeability is used to calculate the dimensionless liquid productivity index，macroscopically characterizing the effect of interlayer heterogeneity on infill well productivity of commingled production at different water cuts. The chart and process of evaluating infill well productivity of multi-layer reservoirs in old offshore oilfields at different water cuts are established. The reliability of this method is verified by productivity analysis of newly infill wells in Block N of Bohai A Oilfield. The flow coefficient lower-limits of infill wells at various production goals are charted to guide the primary selectionof infill well location.
It is difficult to evaluate the infill well productivity of multi-layer reservoirs in old offshore oilfields due to the interlayer heterogeneity of producers and water breakthrough at the initial stage of production. Interlayer interference coefficient is usually used to describe the effect of commingled production on infill well productivity in multi-layer reservoirs.However，the interlayer interference coefficient can hardly be quantitatively characterized. To solve this，with dynamic and static data from old offshore oilfields，we propose a new method to evaluate the infill well productivity of multi-layer reservoirs. The paper introduces the concept of injection-production affection efficiency. A method that analyzes the injectionproduction affection efficiency of multi-layer reservoirs is worked out by integrating modular dynamics test（MDT）results，production logging test（PLT）results，logging interpretation results of water-out reservoirs，and static geological knowledge. By the method，the unaffected layers without contribution to stable productivity can be identified. Furthermore，the dynamic relative permeability is used to calculate the dimensionless liquid productivity index，macroscopically characterizing the effect of interlayer heterogeneity on infill well productivity of commingled production at different water cuts. The chart and process of evaluating infill well productivity of multi-layer reservoirs in old offshore oilfields at different water cuts are established. The reliability of this method is verified by productivity analysis of newly infill wells in Block N of Bohai A Oilfield. The flow coefficient lower-limits of infill wells at various production goals are charted to guide the primary selectionof infill well location.
16 Study on theoretical model for recovery evaluation of CO2 flooding in low permeability reservoirs
2021, 28(4):131-139.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.04.016
Abstract:
Years of development practice have witnessed the maturity of research on the mechanism of enhanced oil recovery（EOR）with CO2 flooding in low permeability reservoirs in China. However，the theoretical research on reservoir engineering was not sufficient and the theoretical model for the recovery evaluation of CO2 flooding in low permeability reservoirs was not available. Based on the EOR mechanism of CO2 flooding in low permeability reservoirs，the basic similarity criteria and key parameters for the theoretical research on the recovery evaluation of CO2 flooding were selected with the generalized reservoir engineering method. The main-factor characterization functions were created to characterize the development characteristics and EOR mechanism of CO2 flooding in low permeability reservoirs. A theoretical model for the recovery evaluation of CO2 flooding in low permeability reservoirs was construced. According to the actual development parameters of CO2 flooding in representative low permeability reservoirs in China，the coefficients of the model were solved by the single-factor virtual development method of numerical simulation. The applicability of the theoretical model was analyzed by the multi-factor virtual development method of numerical simulation. The reliability of the theoretical model was verified by comparing the actual recovery with the calculated result by the theoretical model. The results show that the proposed model is applicable and reliable and provides theoretical basis and technical support for quantitatively evaluating CO2 flooding development and improving the evaluation method of CO2 flooding in low permeability reservoirs and the theoretical research on reservoir engineering.
Years of development practice have witnessed the maturity of research on the mechanism of enhanced oil recovery（EOR）with CO2 flooding in low permeability reservoirs in China. However，the theoretical research on reservoir engineering was not sufficient and the theoretical model for the recovery evaluation of CO2 flooding in low permeability reservoirs was not available. Based on the EOR mechanism of CO2 flooding in low permeability reservoirs，the basic similarity criteria and key parameters for the theoretical research on the recovery evaluation of CO2 flooding were selected with the generalized reservoir engineering method. The main-factor characterization functions were created to characterize the development characteristics and EOR mechanism of CO2 flooding in low permeability reservoirs. A theoretical model for the recovery evaluation of CO2 flooding in low permeability reservoirs was construced. According to the actual development parameters of CO2 flooding in representative low permeability reservoirs in China，the coefficients of the model were solved by the single-factor virtual development method of numerical simulation. The applicability of the theoretical model was analyzed by the multi-factor virtual development method of numerical simulation. The reliability of the theoretical model was verified by comparing the actual recovery with the calculated result by the theoretical model. The results show that the proposed model is applicable and reliable and provides theoretical basis and technical support for quantitatively evaluating CO2 flooding development and improving the evaluation method of CO2 flooding in low permeability reservoirs and the theoretical research on reservoir engineering.
2021, 28(4):140-146.
Abstract:
The fracturing process of fracture network in shale is accompanied by a complicated fluid-solid-thermo-chemical coupling mechanism between fracturing fluid and rock. To evaluate the fracture propagation under this coupling mechanism，we performed the hydraulic fracturing experiments with fluid-solid-thermo-chemical coupling and highlighted the effects of thermal processes and hydration on shale fracture propagation. The research results show that the high temperature shale cooled by fracturing fluid is subject to thermal fractures during fracturing，resulting in micro-fractures and thus reducing the tensile strength. At the same time，the brittleness of the rock intensifies，which is conducive to the formation of a fracture network. In addition，the hydration stress is induced by hydration，causing stress concentration at the fracture tip and increasing the stress intensity factor. Meanwhile，the intrusion of the fracturing fluid reduces the weak plane cohesion and the critical stress intensity factor. The fractures are easy to propagate or turn along the weak plane，facilitating the formation of the fracture network.
The fracturing process of fracture network in shale is accompanied by a complicated fluid-solid-thermo-chemical coupling mechanism between fracturing fluid and rock. To evaluate the fracture propagation under this coupling mechanism，we performed the hydraulic fracturing experiments with fluid-solid-thermo-chemical coupling and highlighted the effects of thermal processes and hydration on shale fracture propagation. The research results show that the high temperature shale cooled by fracturing fluid is subject to thermal fractures during fracturing，resulting in micro-fractures and thus reducing the tensile strength. At the same time，the brittleness of the rock intensifies，which is conducive to the formation of a fracture network. In addition，the hydration stress is induced by hydration，causing stress concentration at the fracture tip and increasing the stress intensity factor. Meanwhile，the intrusion of the fracturing fluid reduces the weak plane cohesion and the critical stress intensity factor. The fractures are easy to propagate or turn along the weak plane，facilitating the formation of the fracture network.
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