Volume 31,Issue 6,2024 Table of Contents
WANG Yongshi
,
ZHANG Pengfei
,
WANG Xuejun
,
MA Shuai
,
LUO Xia
,
ZHANG Yunyin
,
XIONG Wei
,
WANG Yong
,
TIAN Wen
,
LIU Ruijuan
2024, 31(6):1-17.
DOI: 10.13673/j.pgre.202405049
Abstract:
Paleozoic buried hill is one of the high-yield fields of oil and gas enrichment in Jiyang Depression， and it is a critical reserve expansion position. Oil and gas accumulation in Paleozoic buried hills has unique petroleum geology conditions. The strata are age-old， and lithology includes carbonate rock and clastic rock. In the long geological evolution process， multi-stage structures，faults， and deep fluid activities are strong， making the buried hill have the characteristics of evolutionary superposition， structural diversity， reservoir complexity， multi-sources of oil and gas， and accumulation differences. Based on the progress of oil and gas exploration and further research of Paleozoic buried hills in Jiyang Depression since“ The 13th Five-Year Plan”， the formation and enrichment of oil and gas in Paleozoic buried hills in faulted basins were revealed from the internal geological process of hill formation，hydrocarbon generation， reservoir formation， and petroleum accumulation. The co-controlled hill formation mechanism of “compression-tension-strike-slip-denudation” was proposed. The Paleozoic buried hills had Carboniferous-Permian and Palaeogene dual-source hydrocarbon supply conditions， ternary control storage mode of “sedimentary-diagenetic environment， structurepressure coupling， and fluid-rock interaction，” oil and gas accumulation mode controlled by migration and plugging， and orderly distribution of reservoirs. Guided by these understandings， the exploration directions of Paleozoic buried hill reservoirs in Jiyang Depression was changed， and the exploration space of buried hills was expanded， laying a foundation for the evaluation of Paleozoic buried hill exploration zones， and the optimization of trap targets and breakthroughs were made in the exploration of hidden buried hills in deep slopes and negative tectonic zones. At the same time， based on the understanding degree and theoretical development status of different accumulation conditions of Paleozoic buried hills in Jiyang Depression， the next research direction of oil and gas exploration was put forward.
Paleozoic buried hill is one of the high-yield fields of oil and gas enrichment in Jiyang Depression， and it is a critical reserve expansion position. Oil and gas accumulation in Paleozoic buried hills has unique petroleum geology conditions. The strata are age-old， and lithology includes carbonate rock and clastic rock. In the long geological evolution process， multi-stage structures，faults， and deep fluid activities are strong， making the buried hill have the characteristics of evolutionary superposition， structural diversity， reservoir complexity， multi-sources of oil and gas， and accumulation differences. Based on the progress of oil and gas exploration and further research of Paleozoic buried hills in Jiyang Depression since“ The 13th Five-Year Plan”， the formation and enrichment of oil and gas in Paleozoic buried hills in faulted basins were revealed from the internal geological process of hill formation，hydrocarbon generation， reservoir formation， and petroleum accumulation. The co-controlled hill formation mechanism of “compression-tension-strike-slip-denudation” was proposed. The Paleozoic buried hills had Carboniferous-Permian and Palaeogene dual-source hydrocarbon supply conditions， ternary control storage mode of “sedimentary-diagenetic environment， structurepressure coupling， and fluid-rock interaction，” oil and gas accumulation mode controlled by migration and plugging， and orderly distribution of reservoirs. Guided by these understandings， the exploration directions of Paleozoic buried hill reservoirs in Jiyang Depression was changed， and the exploration space of buried hills was expanded， laying a foundation for the evaluation of Paleozoic buried hill exploration zones， and the optimization of trap targets and breakthroughs were made in the exploration of hidden buried hills in deep slopes and negative tectonic zones. At the same time， based on the understanding degree and theoretical development status of different accumulation conditions of Paleozoic buried hills in Jiyang Depression， the next research direction of oil and gas exploration was put forward.
2024, 31(6):18-32.
DOI: 10.13673/j.pgre.202312018
Abstract:
The shale oil in the Lower Es3 and Upper Es4 Submembers of Niuzhuang Subsag of Dongying Sag is rich， with high yield， belonging to the typical terrestrial shale oil. Currently， the understanding of material exchanges and reservoir characteristics driven by diagenesis between shale laminae is not clear. The mechanism of the interaction influence of sedimentation and diagenesis on the quality of shale oil generation and storage was analyzed by the petrology， geochemical analysis of trace elements and rare earth elements， and other methods based on the sparry calcite veins and material transfer phenomena， as well as shale hydrocarbon generation and oil-bearing parameters. In addition， material transfer between shale laminae， generation of sparry calcite veins， and shale oil migration were scientifically explained. The geochemical microanalysis of rare earth elements reveals that the Th and U element contents within different material laminae in descending order are as follows： argillaceous layer， sparry calcite vein， recrystallized calcite layer， and contact surface between argillaceous layer and sparry calcite vein. The differentiation of light and heavy rare earth elements in the argillaceous layer and sparry calcite vein is obvious， showing significant enrichment of light rare earth elements and loss of heavy rare earth elements， exhibiting obvious negative anomalies of Dy. The differentiation of light and heavy rare earth elements in the recrystallized calcite layer is not obvious， showing a negative anomaly of Dy. The contents of Th， U， and rare earth elements in the sparry calcite veins are lower than those in the argillaceous layer and higher than those in the recrystallized calcite layer， and it is an essential geochemical indicator to distinguish between the sparry calcite veins and the recrystallized calcite layer. The compaction effect and material component content are the main factors affecting shale porosity. According to the nuclear magnetic resonance experiment， the reduction in pore size greater than 30 nm is the most significant in shale with a burial depth of 3 300-3 600 m， and the reduction amplitude is about 1%/hm. The total content of terrestrial minerals is positively correlated with porosity due to the effect of overpressure fluid pore retention caused by hydrocarbon pressurization. Hydrogenated carbonate minerals have strong resistance to overlying rock pressure， which is beneficial for artificial fracturing. Their intergranular and dissolution pores have large sizes with superior oil storage capacity.
The shale oil in the Lower Es3 and Upper Es4 Submembers of Niuzhuang Subsag of Dongying Sag is rich， with high yield， belonging to the typical terrestrial shale oil. Currently， the understanding of material exchanges and reservoir characteristics driven by diagenesis between shale laminae is not clear. The mechanism of the interaction influence of sedimentation and diagenesis on the quality of shale oil generation and storage was analyzed by the petrology， geochemical analysis of trace elements and rare earth elements， and other methods based on the sparry calcite veins and material transfer phenomena， as well as shale hydrocarbon generation and oil-bearing parameters. In addition， material transfer between shale laminae， generation of sparry calcite veins， and shale oil migration were scientifically explained. The geochemical microanalysis of rare earth elements reveals that the Th and U element contents within different material laminae in descending order are as follows： argillaceous layer， sparry calcite vein， recrystallized calcite layer， and contact surface between argillaceous layer and sparry calcite vein. The differentiation of light and heavy rare earth elements in the argillaceous layer and sparry calcite vein is obvious， showing significant enrichment of light rare earth elements and loss of heavy rare earth elements， exhibiting obvious negative anomalies of Dy. The differentiation of light and heavy rare earth elements in the recrystallized calcite layer is not obvious， showing a negative anomaly of Dy. The contents of Th， U， and rare earth elements in the sparry calcite veins are lower than those in the argillaceous layer and higher than those in the recrystallized calcite layer， and it is an essential geochemical indicator to distinguish between the sparry calcite veins and the recrystallized calcite layer. The compaction effect and material component content are the main factors affecting shale porosity. According to the nuclear magnetic resonance experiment， the reduction in pore size greater than 30 nm is the most significant in shale with a burial depth of 3 300-3 600 m， and the reduction amplitude is about 1%/hm. The total content of terrestrial minerals is positively correlated with porosity due to the effect of overpressure fluid pore retention caused by hydrocarbon pressurization. Hydrogenated carbonate minerals have strong resistance to overlying rock pressure， which is beneficial for artificial fracturing. Their intergranular and dissolution pores have large sizes with superior oil storage capacity.
2024, 31(6):33-44.
DOI: 10.13673/j.pgre.202308034
Abstract:
Due to the strong non-homogeneity and complex pore structure of glutenite reservoirs， it isn’t easy to accurately reflect the oil content of the reservoir through resistivity response. However， the traditional two-component three-dimensional （3D） digital core modeling and numerical simulation method of resistivity fail to characterize the multi-component and multi-scale pore space and accurately simulate the resistivity of the glutenite. The deep glutenites of the upper Submember of the 4th Member of the Paleogene Eocene Shahejie Formation （Es4U ） in the northern steep slope zone of Dongying Sag were studied， as well as the plunger samples of Well Yan 22-22 in Yanjia Oilfield. The conventional core analysis， nuclear magnetic resonance （NMR） test， X-ray computerized tomography （X-CT） scanning， modular automated processing system （MAPS） test， and quantitative evaluation of minerals by scanning electron microscopy （QEMSCAN） were performed to establish a multi-component 3D digital core of glutenite. The numerical simulation method of resistivity was adopted to analyze the influence of reservoir parameters on the resistivity characteristics of the glutenite. The results show that ① X-CT scanning is used to scan the standard plunger samples， and the multi-threshold segmentation is performed to distinguish the main mineral components to establish a multi-component 3D digital core of the glutenite.The main components match with the results of X-ray diffraction （XRD） tests of the samples， but the identified porosity is much lower than the gas porosity measured of the core due to the limitation of the scanning resolution. ② The two-dimensional （2D） images established by the MAPS test with 100 nm and 10 nm resolution are selected to calculate the microporosity of the main mineral components， which is combined with the component content of the 3D digital core to calculate the total porosity of the multi-component 3D digital core of the glutenite， which matches with the gas porosity measured of the core. ③ The numerical simulation results of resistivity show that the influence of gravel and clay mineral content on the resistivity of glutenite is not monotonous.The influence of gravel content is related to sample sorting， and that of clay mineral content is related to the type of clay and the salinity of the formation water.
Due to the strong non-homogeneity and complex pore structure of glutenite reservoirs， it isn’t easy to accurately reflect the oil content of the reservoir through resistivity response. However， the traditional two-component three-dimensional （3D） digital core modeling and numerical simulation method of resistivity fail to characterize the multi-component and multi-scale pore space and accurately simulate the resistivity of the glutenite. The deep glutenites of the upper Submember of the 4th Member of the Paleogene Eocene Shahejie Formation （Es4U ） in the northern steep slope zone of Dongying Sag were studied， as well as the plunger samples of Well Yan 22-22 in Yanjia Oilfield. The conventional core analysis， nuclear magnetic resonance （NMR） test， X-ray computerized tomography （X-CT） scanning， modular automated processing system （MAPS） test， and quantitative evaluation of minerals by scanning electron microscopy （QEMSCAN） were performed to establish a multi-component 3D digital core of glutenite. The numerical simulation method of resistivity was adopted to analyze the influence of reservoir parameters on the resistivity characteristics of the glutenite. The results show that ① X-CT scanning is used to scan the standard plunger samples， and the multi-threshold segmentation is performed to distinguish the main mineral components to establish a multi-component 3D digital core of the glutenite.The main components match with the results of X-ray diffraction （XRD） tests of the samples， but the identified porosity is much lower than the gas porosity measured of the core due to the limitation of the scanning resolution. ② The two-dimensional （2D） images established by the MAPS test with 100 nm and 10 nm resolution are selected to calculate the microporosity of the main mineral components， which is combined with the component content of the 3D digital core to calculate the total porosity of the multi-component 3D digital core of the glutenite， which matches with the gas porosity measured of the core. ③ The numerical simulation results of resistivity show that the influence of gravel and clay mineral content on the resistivity of glutenite is not monotonous.The influence of gravel content is related to sample sorting， and that of clay mineral content is related to the type of clay and the salinity of the formation water.
2024, 31(6):45-56.
DOI: 10.13673/j.pgre.202309024
Abstract:
The pore structure characteristics of tight sandstone are of significance for the exploration and development of tight oil reservoirs. However， little attention is paid to the flow characteristics and influencing factors of different types of pores. This restricts the understanding of the flow and storage capacity of tight sandstone and affects the evaluation and prediction of favorable areas for tight oil reservoirs. Therefore， this paper focuses on the tight sandstone in the Chang 7 member of the Triassic Yanchang Formation in Ordos Basin， and casting thin sections， scanning electron microscopy， nuclear magnetic resonance， and the fractal method are adopted to research the pore structure characteristics of tight sandstone. The results indicate that the pore structure of tight sandstone is a binary pore system composed of bound pores and movable pores. The morphological characteristics and connectivity of different types of pores vary greatly. Bound pores are mainly composed of intergranular pores， and the pore model is the envelope surface of clay accumulation. The pore radius is small， the connectivity is poor， and the fluid flow is poor. The pore features a regular shape， weak heterogeneity， low fractal dimension， and an average value of 1.306 3. The movable pores are mainly combined pores with a spiky-spherical shape. This type of pore has a large radius and multiple connecting channels formed by dissolution，resulting in strong connectivity. The shape of movable pores is irregular， with strong heterogeneity， a large fractal dimension，and an average value of 3.241 6. The influence of different types of pores on physical properties is also different. The average contribution of bound pores to porosity is 47.7%， and that of movable pores to porosity is 52.3%. The two types of pores have similar content but are affected by differences in connectivity. The average contribution of bound pores to permeability is 0.2%， while that of movable pores to permeability is 99.8%. Movable pores are the main factor affecting the permeability of tight sandstone. The fractal dimension can characterize the pore structure of tight sandstone. Sandstone is mainly composed of composite pores and located near the source rocks is a favorable area for exploration and development of tight sandstone.
The pore structure characteristics of tight sandstone are of significance for the exploration and development of tight oil reservoirs. However， little attention is paid to the flow characteristics and influencing factors of different types of pores. This restricts the understanding of the flow and storage capacity of tight sandstone and affects the evaluation and prediction of favorable areas for tight oil reservoirs. Therefore， this paper focuses on the tight sandstone in the Chang 7 member of the Triassic Yanchang Formation in Ordos Basin， and casting thin sections， scanning electron microscopy， nuclear magnetic resonance， and the fractal method are adopted to research the pore structure characteristics of tight sandstone. The results indicate that the pore structure of tight sandstone is a binary pore system composed of bound pores and movable pores. The morphological characteristics and connectivity of different types of pores vary greatly. Bound pores are mainly composed of intergranular pores， and the pore model is the envelope surface of clay accumulation. The pore radius is small， the connectivity is poor， and the fluid flow is poor. The pore features a regular shape， weak heterogeneity， low fractal dimension， and an average value of 1.306 3. The movable pores are mainly combined pores with a spiky-spherical shape. This type of pore has a large radius and multiple connecting channels formed by dissolution，resulting in strong connectivity. The shape of movable pores is irregular， with strong heterogeneity， a large fractal dimension，and an average value of 3.241 6. The influence of different types of pores on physical properties is also different. The average contribution of bound pores to porosity is 47.7%， and that of movable pores to porosity is 52.3%. The two types of pores have similar content but are affected by differences in connectivity. The average contribution of bound pores to permeability is 0.2%， while that of movable pores to permeability is 99.8%. Movable pores are the main factor affecting the permeability of tight sandstone. The fractal dimension can characterize the pore structure of tight sandstone. Sandstone is mainly composed of composite pores and located near the source rocks is a favorable area for exploration and development of tight sandstone.
2024, 31(6):57-64.
DOI: 10.13673/j.pgre.202404005
Abstract:
The fracturability of reservoirs is an essential parameter for selecting perforation stages and predicting hydraulic fracturing effects， but fracturability evaluation for tight sandstone reservoirs lacks unified methods and standards. This paper studies Chang 6 tight sandstone reservoir in an oilfield in the southeastern part of Ordos Basin and optimizes the characterization model of rock mechanics parameters based on the conventional logging data. The paper analyzes the relationships among reservoir rock brittleness，fracture toughness， in-situ stress difference coefficient， and daily fluid production， establishes the fracturability evaluation model and evaluation standard for tight sandstone reservoirs， and obtains fracture quality factor curves corresponding to logging curves. As a result， a high-precision logging evaluation method for the fracturability of tight sandstone reservoirs was developed. The results indicate as follows： ① The brittleness index is positively correlated with the fracturability， and the fracture toughness and in-situ stress difference coefficient are negatively correlated with the fracturability. ② The fracturing quality factor is greater than 25 for Class I reservoirs， indicating the best fracturability； it is easy to form a complex fracture network during fracturing and belongs to high-quality tight sandstone reservoirs. The fracturing quality factor ranges from 14 to 25 for Class II reservoirs， indicating medium fracturability； it is necessary to use fracturing fluid with low viscosity or keep high net pressure in fractures to form a better fracture network. The fracturing quality factor is less than 14 for class III reservoirs， indicating poor fracturability； an ideal fracture network is usually not formed during fracturing， and fractures are easy to close after fracturing. ③ Higher fracturing quality factors of tight sandstone reservoirs indicate better characteristics of artificial fracture morphologies and higher production capacity after fracturing.The evaluation results by the established model are more than 80% consistent with the microseismic fracture monitoring results and production testing results.
The fracturability of reservoirs is an essential parameter for selecting perforation stages and predicting hydraulic fracturing effects， but fracturability evaluation for tight sandstone reservoirs lacks unified methods and standards. This paper studies Chang 6 tight sandstone reservoir in an oilfield in the southeastern part of Ordos Basin and optimizes the characterization model of rock mechanics parameters based on the conventional logging data. The paper analyzes the relationships among reservoir rock brittleness，fracture toughness， in-situ stress difference coefficient， and daily fluid production， establishes the fracturability evaluation model and evaluation standard for tight sandstone reservoirs， and obtains fracture quality factor curves corresponding to logging curves. As a result， a high-precision logging evaluation method for the fracturability of tight sandstone reservoirs was developed. The results indicate as follows： ① The brittleness index is positively correlated with the fracturability， and the fracture toughness and in-situ stress difference coefficient are negatively correlated with the fracturability. ② The fracturing quality factor is greater than 25 for Class I reservoirs， indicating the best fracturability； it is easy to form a complex fracture network during fracturing and belongs to high-quality tight sandstone reservoirs. The fracturing quality factor ranges from 14 to 25 for Class II reservoirs， indicating medium fracturability； it is necessary to use fracturing fluid with low viscosity or keep high net pressure in fractures to form a better fracture network. The fracturing quality factor is less than 14 for class III reservoirs， indicating poor fracturability； an ideal fracture network is usually not formed during fracturing， and fractures are easy to close after fracturing. ③ Higher fracturing quality factors of tight sandstone reservoirs indicate better characteristics of artificial fracture morphologies and higher production capacity after fracturing.The evaluation results by the established model are more than 80% consistent with the microseismic fracture monitoring results and production testing results.
GAO Yongjin
,
CHEN Yi
,
SUN Xiangcan
,
WEN Lei
,
WANG Qianjun
,
BAI Zhongkai
,
TAN Zhilong
,
WANG Xinshui
,
XIN Yunlu
,
ZHANG Yuanyin
,
ZHU Depeng
2024, 31(6):65-73.
DOI: 10.13673/j.pgre.202407028
Abstract:
Volcanic rocks， such as andesite and tuff， are widely developed in the Carboniferous system in Karamali area， northern Xinjiang. The tectonic background of their formation is still controversial. In this paper， two typical Carboniferous profiles from Karamali Mountain were selected. Andesite and tuff samples from the lower Carboniferous Jiangbasitao Formation， the upper Carboniferous Bashan Formation， and Huxingliang Formation were observed under a microscope， and their main trace elements were analyzed. The results show that the contents of MgO （0.5%-2.35%） and Mg# （15.7%-42.5%） are low to medium in samples， indicating that the crystallization differentiation of rock samples occurs during the formation process. The distribution curve of trace elements in the samples is obviously different from that of N-MORB， E-MORB， and OIB. The samples are almost all in the calcalkaline series in Ta/Yb-Th/Yb and La-Y-Nb diagrams， while the samples fall subduction components and approach the mantle series in Nb/Yb-La/Yb diagrams. The Nb/Y-Rb/Y and Ba/La-Ba/Nb diagrams also show that the samples are affected by both fluid enrichment and melt enrichment. The Nb/U and Ce/Pb ratios of the samples are 1.6-11.1 and 0.47-12.2， respectively， which are close to the range of continental crust and indicate that the source of the material may be mixed with continental crust materials. According to the Th-Hf/3-Nb/16 diagram， all the samples are located in the island arc basalt region. The comprehensive analysis shows that Karamali area was in the continental island arc environment of active continental margin from the early Carboniferous to the late Carboniferous， and this environment lasted at least from the early Carboniferous to the late Carboniferous.
Volcanic rocks， such as andesite and tuff， are widely developed in the Carboniferous system in Karamali area， northern Xinjiang. The tectonic background of their formation is still controversial. In this paper， two typical Carboniferous profiles from Karamali Mountain were selected. Andesite and tuff samples from the lower Carboniferous Jiangbasitao Formation， the upper Carboniferous Bashan Formation， and Huxingliang Formation were observed under a microscope， and their main trace elements were analyzed. The results show that the contents of MgO （0.5%-2.35%） and Mg# （15.7%-42.5%） are low to medium in samples， indicating that the crystallization differentiation of rock samples occurs during the formation process. The distribution curve of trace elements in the samples is obviously different from that of N-MORB， E-MORB， and OIB. The samples are almost all in the calcalkaline series in Ta/Yb-Th/Yb and La-Y-Nb diagrams， while the samples fall subduction components and approach the mantle series in Nb/Yb-La/Yb diagrams. The Nb/Y-Rb/Y and Ba/La-Ba/Nb diagrams also show that the samples are affected by both fluid enrichment and melt enrichment. The Nb/U and Ce/Pb ratios of the samples are 1.6-11.1 and 0.47-12.2， respectively， which are close to the range of continental crust and indicate that the source of the material may be mixed with continental crust materials. According to the Th-Hf/3-Nb/16 diagram， all the samples are located in the island arc basalt region. The comprehensive analysis shows that Karamali area was in the continental island arc environment of active continental margin from the early Carboniferous to the late Carboniferous， and this environment lasted at least from the early Carboniferous to the late Carboniferous.
2024, 31(6):74-88.
DOI: 10.13673/j.pgre.202309029
Abstract:
Rock fracture mechanics properties are the intrinsic geo-mechanical basis for determining the effectiveness of reservoir fracturing stimulation. It is of practical significance to clarify the fracture mechanics properties of reservoirs with different lithologies in marine-continental transitional facies to optimize the fracturing stimulation measures and improve the effect of fracture networks.Taking the reservoir in marine-continental transitional facies at the eastern edge of Ordos Basin as the research object， this study carried out the fracture toughness test of various lithologies in the reservoir， clarified the fracture mechanics characteristics of the reservoir with different lithologies and the influencing factors， and finally established a numerical model of fracturing with the logging lithology depositional sequence on the finite element platform， and emphasized the influence of the combination of lithologies on the fracture height propagation. The results show that reservoir lithologies in the marine-continental transitional facies are complex and rich in quartz and clay minerals， and the mechanical deformation shows strong brittleness characteristics. Compared with marine shale， the reservoir rocks in the marine-continental transitional facies are characterized by low fracture toughness. The fracture toughness value shows the characteristics of coal rock < clastic sedimentary rock < gray rock. Among them， weak structural surfaces such as plant debris and grain layers have a strong deterioration effect by changing the fracture paths and thus affecting the fracture toughness of the corresponding lithologies. The static elastic modulus of reservoir rocks is an important mechanical factor controlling the fracture toughness of different lithologies， and the fracture toughness has a linear correlation with the static elastic modulus. The reservoir rock is characterized by strong interlayer mechanical heterogeneity. The hydraulic fracture height tendency is blunted in the process of moving from the mudstone layer into the sandstone layer， and the interbedded coal layer in the reservoir will significantly reduce the fracture height and increase the probability of non-uniform proppant placement in the reservoir. The influence of reservoir in-situ stress on fracture height morphology is related to the lithology combination， so the selection of horizontal well traversing trajectory in the early stage needs to pay attention to the influence of the lithology combination characteristics above and below the horizontal wells on the fracturing effect of the subsequent horizontal wells.
Rock fracture mechanics properties are the intrinsic geo-mechanical basis for determining the effectiveness of reservoir fracturing stimulation. It is of practical significance to clarify the fracture mechanics properties of reservoirs with different lithologies in marine-continental transitional facies to optimize the fracturing stimulation measures and improve the effect of fracture networks.Taking the reservoir in marine-continental transitional facies at the eastern edge of Ordos Basin as the research object， this study carried out the fracture toughness test of various lithologies in the reservoir， clarified the fracture mechanics characteristics of the reservoir with different lithologies and the influencing factors， and finally established a numerical model of fracturing with the logging lithology depositional sequence on the finite element platform， and emphasized the influence of the combination of lithologies on the fracture height propagation. The results show that reservoir lithologies in the marine-continental transitional facies are complex and rich in quartz and clay minerals， and the mechanical deformation shows strong brittleness characteristics. Compared with marine shale， the reservoir rocks in the marine-continental transitional facies are characterized by low fracture toughness. The fracture toughness value shows the characteristics of coal rock < clastic sedimentary rock < gray rock. Among them， weak structural surfaces such as plant debris and grain layers have a strong deterioration effect by changing the fracture paths and thus affecting the fracture toughness of the corresponding lithologies. The static elastic modulus of reservoir rocks is an important mechanical factor controlling the fracture toughness of different lithologies， and the fracture toughness has a linear correlation with the static elastic modulus. The reservoir rock is characterized by strong interlayer mechanical heterogeneity. The hydraulic fracture height tendency is blunted in the process of moving from the mudstone layer into the sandstone layer， and the interbedded coal layer in the reservoir will significantly reduce the fracture height and increase the probability of non-uniform proppant placement in the reservoir. The influence of reservoir in-situ stress on fracture height morphology is related to the lithology combination， so the selection of horizontal well traversing trajectory in the early stage needs to pay attention to the influence of the lithology combination characteristics above and below the horizontal wells on the fracturing effect of the subsequent horizontal wells.
2024, 31(6):89-95.
DOI: 10.13673/j.pgre.202410007
Abstract:
For the new gas well with a closed boundary， the pressure drawdown curve testing was carried out after it operated at a stable production rate. Theoretically， the pressure drawdown curve can be divided into an unsteady state stage， a transit state stage （also called the late unsteady state stage）， and a pseudo-steady state stage according to its pressure dynamics. The unsteady state stage refers to the outer edge radius of the pressure drawdown distribution of the gas well not reaching the boundary. The transit state stage refers to the range from the unsteady state stage to the pseudo-steady state stage. At this stage， the elastic two-phase method used in China can be employed to determine the initial gas in place controlled by a gas well. This method has been listed four times in the national oil and gas industry standard. For the unsteady state stage， according to the differential formula of the plane radial flow based on Darcy’s law， this paper derived the elastic one-phase method of pseudo-pressure by using the pseudo-pressure function proposed by Al-Hussainy. This method could be used to evaluate the effective permeability of gas reservoirs and the total skin factor of wells. In addition， the elastic one-phase method expressed by the one power of pressure and pressure that was squared was obtained by simplifying the research results of Wattenbanger on the properties of the pseudo-pressure function. The practical application showed that the evaluation results with the three methods were consistent.
For the new gas well with a closed boundary， the pressure drawdown curve testing was carried out after it operated at a stable production rate. Theoretically， the pressure drawdown curve can be divided into an unsteady state stage， a transit state stage （also called the late unsteady state stage）， and a pseudo-steady state stage according to its pressure dynamics. The unsteady state stage refers to the outer edge radius of the pressure drawdown distribution of the gas well not reaching the boundary. The transit state stage refers to the range from the unsteady state stage to the pseudo-steady state stage. At this stage， the elastic two-phase method used in China can be employed to determine the initial gas in place controlled by a gas well. This method has been listed four times in the national oil and gas industry standard. For the unsteady state stage， according to the differential formula of the plane radial flow based on Darcy’s law， this paper derived the elastic one-phase method of pseudo-pressure by using the pseudo-pressure function proposed by Al-Hussainy. This method could be used to evaluate the effective permeability of gas reservoirs and the total skin factor of wells. In addition， the elastic one-phase method expressed by the one power of pressure and pressure that was squared was obtained by simplifying the research results of Wattenbanger on the properties of the pseudo-pressure function. The practical application showed that the evaluation results with the three methods were consistent.
CHENG Qiuyang
,
YANG Hongzhi
,
YOU Lijun
,
KANG Yili
,
CHANG Cheng
,
XIE Weiyang
,
JIA Na
,
TANG Xuefeng
2024, 31(6):96-108.
DOI: 10.13673/j.pgre.202308031
Abstract:
Horizontal well multi-stage hydraulic fracturing technology makes the development of shale gas reservoirs efficient. However， water-rock interaction between shale rock and the work fluids like water-base drilling fluid， alkaline oil-base drilling fluid， slick-water fracturing fluid， pre-acid fluid， and oxidizing rubber breaking fluid may potentially affect wellbore stability， fracturing stimulation effect， shut-in performance， and flowback efficiency during the drilling process. This paper discusses the significance of water-rock interaction on shale gas development by systematically summarizing the mechanism of water-rock interaction and the response characteristics of shale pore structure under water-rock interaction in shale gas reservoirs in China and abroad.Shale is found rich in water-sensitive components such as clay minerals， acid-sensitive components such as carbonate minerals，alkali-sensitive components such as quartz， and oxidative-sensitive components such as organic matter and pyrite. The hydrolysis of shale components is very poor， while hydration swells and associated fracture generation due to clay minerals are prominent. The distribution of pores and fractures in shale is closely related to the chemically unstable components of quartz， carbonate minerals，organic matter， and clay minerals. Chemical dissolutions include acidizing， alkali， and oxidative dissolutions. The dissolution of shale components under water-rock action induces the dissolution and enlargement of pores and fractures， which also impairs the mechanical properties of rock. It is pointed out that optimizing working fluid， like the application of oxidative-acid and oxidative fracturing fluid， is conducive to improving the fracturing stimulation effect， promoting adsorption gas production， and improving shale gas recovery. Meanwhile， determining the maximum shut-in time based on the inflection point of the pressure drop curve and constructing the pressure control production system considering the protection of the diversion capacity of the fracture network can guide the reasonable pressure control in the whole process of gas well production， extend the stable production period， and increase the production of a single well.
Horizontal well multi-stage hydraulic fracturing technology makes the development of shale gas reservoirs efficient. However， water-rock interaction between shale rock and the work fluids like water-base drilling fluid， alkaline oil-base drilling fluid， slick-water fracturing fluid， pre-acid fluid， and oxidizing rubber breaking fluid may potentially affect wellbore stability， fracturing stimulation effect， shut-in performance， and flowback efficiency during the drilling process. This paper discusses the significance of water-rock interaction on shale gas development by systematically summarizing the mechanism of water-rock interaction and the response characteristics of shale pore structure under water-rock interaction in shale gas reservoirs in China and abroad.Shale is found rich in water-sensitive components such as clay minerals， acid-sensitive components such as carbonate minerals，alkali-sensitive components such as quartz， and oxidative-sensitive components such as organic matter and pyrite. The hydrolysis of shale components is very poor， while hydration swells and associated fracture generation due to clay minerals are prominent. The distribution of pores and fractures in shale is closely related to the chemically unstable components of quartz， carbonate minerals，organic matter， and clay minerals. Chemical dissolutions include acidizing， alkali， and oxidative dissolutions. The dissolution of shale components under water-rock action induces the dissolution and enlargement of pores and fractures， which also impairs the mechanical properties of rock. It is pointed out that optimizing working fluid， like the application of oxidative-acid and oxidative fracturing fluid， is conducive to improving the fracturing stimulation effect， promoting adsorption gas production， and improving shale gas recovery. Meanwhile， determining the maximum shut-in time based on the inflection point of the pressure drop curve and constructing the pressure control production system considering the protection of the diversion capacity of the fracture network can guide the reasonable pressure control in the whole process of gas well production， extend the stable production period， and increase the production of a single well.
2024, 31(6):109-117.
DOI: 10.13673/j.pgre.202308030
Abstract:
Oil-gas interfacial tension is an important parameter for analyzing the mixing degree of oil and gas phases and influencing the minimum mixing pressure of oil and gas and the development effect of gas injection during gas flooding for enhanced oil recovery.Aiming at n-octane （C8）， which is the main component of shale oil， the changing rules of interfacial tension and interfacial microscopic characteristics of pure CO2and mixed gases （CO2， CH4，N2） with n-octane were investigated by molecular dynamics simulation. Additionally， the effects of external factors such as temperature， pressure，and gas components on interfacial characteristics were also taken into account. The results show that with the increase in gas-phase pressure，the mixing degree of gas and n-octane increases，and the microscopic features such as interfacial thickness，roughness，and relative adsorption are enhanced，resulting in a gradual decrease in the interfacial tension between the oil and gas. The interfacial tension shows opposite trends with temperature in different pressure intervals. The interfacial tension declines as the temperature rises in low pressure intervals. While the interfacial tension grows as the temperature rises in high pressure intervals. Compared with pure CO2，the addition of CH4 and N2 increases the interfacial tension between the mixed gases and the oil，of which N2 has a greater effect on the oil-gas interfacial tension. At the same time，CH4 and N2 weaken the microscopic features such as the oil-gas interfacial thickness and relative adsorption.The relative adsorption of CO2 is the largest，followed by CH4 and the smallest N2 in the ternary CO2+CH4+N2/C8 system，which proves that the interactions between the three gases and the oil are from the strong to the weak，i.e.，CO2>CH4>N2. In addition，the relative adsorption of all the systems is greater than zero. As the adsorption is larger，the interfacial tension decreases faster with the increasing pressure，which is in agreement with Gibbs’ adsorption theory.
Oil-gas interfacial tension is an important parameter for analyzing the mixing degree of oil and gas phases and influencing the minimum mixing pressure of oil and gas and the development effect of gas injection during gas flooding for enhanced oil recovery.Aiming at n-octane （C8）， which is the main component of shale oil， the changing rules of interfacial tension and interfacial microscopic characteristics of pure CO2and mixed gases （CO2， CH4，N2） with n-octane were investigated by molecular dynamics simulation. Additionally， the effects of external factors such as temperature， pressure，and gas components on interfacial characteristics were also taken into account. The results show that with the increase in gas-phase pressure，the mixing degree of gas and n-octane increases，and the microscopic features such as interfacial thickness，roughness，and relative adsorption are enhanced，resulting in a gradual decrease in the interfacial tension between the oil and gas. The interfacial tension shows opposite trends with temperature in different pressure intervals. The interfacial tension declines as the temperature rises in low pressure intervals. While the interfacial tension grows as the temperature rises in high pressure intervals. Compared with pure CO2，the addition of CH4 and N2 increases the interfacial tension between the mixed gases and the oil，of which N2 has a greater effect on the oil-gas interfacial tension. At the same time，CH4 and N2 weaken the microscopic features such as the oil-gas interfacial thickness and relative adsorption.The relative adsorption of CO2 is the largest，followed by CH4 and the smallest N2 in the ternary CO2+CH4+N2/C8 system，which proves that the interactions between the three gases and the oil are from the strong to the weak，i.e.，CO2>CH4>N2. In addition，the relative adsorption of all the systems is greater than zero. As the adsorption is larger，the interfacial tension decreases faster with the increasing pressure，which is in agreement with Gibbs’ adsorption theory.
2024, 31(6):118-126.
DOI: 10.13673/j.pgre.202309020
Abstract:
The imbibition law of the Jurassic continental shale in Fuxing area is not clear， which brings great challenges to the production test after well shut-in. In addition， studies on the imbibition law and influencing factors of continental shale are insufficient.Therefore，the experiment on the imbibition law of the Jurassic continental shale in Fuxing area was conducted based on the lowfield nuclear magnetic resonance （NMR）. First， the differences in physical properties of shale of Lianggaoshan Formation and Dongyuemiao Member in Ziliujing Formation were tested and analyzed. Then， the changes in permeability and porosity before and after the imbibition were set as the evaluation indexes， and the influences of lithology， fluid， fluid pressure， and clay content on the imbibition law of the continental shale were analyzed. Besides， the wettability of the continental shale was evaluated. The experimental results show that compared with that of Dongyuemiao Member， the average porosity of shale of Lianggaoshan Formation is smaller， and the average permeability is larger； the average brittle mineral content is higher， and the average clay mineral content is lower. During the imbibition process of the Jurassic continental shale in Fuxing area， micro-fractures are induced by clay hydration， which provides additional imbibition channels. However， the imbibition ability of limestone is weaker than that of shale， and there are no micro-fractures during the imbibition； in addition， the shell limestone interlayer in the reservoir may inhibit the imbibition and micro-fracture propagation in the shale. The oil phase will enhance the micro-fracture propagation after the shale induces micro-fractures in the aqueous phase， and the complicated oil-water phase imbibition may be beneficial to the permeability improvement in the shale reservoir. Compared with atmospheric imbibition， pressureed imbibition has a limited effect on inducing micro-fractures and improving permeability， and the imbibition rate is larger； the imbibition equilibrium is earlier， but the imbibition amount is smaller. The influence of confining pressure on imbibition should be considered during well shut-in. The microfractures induced by hydration in shale with high clay mineral content are more significant， and the effect of improving permeability is more obvious. The imbibition rate and imbibition amount of shale in the oil phase are smaller than those in the aqueous phase，and the wettability of shale is hydrophilic. The experiment reveals the imbibition law and the characteristics of micro-fractures induced by the hydration of the Jurassic continental shale in Fuxing area， which provides a theoretical basis for the well shut-in and production test of continental shale during flowback.
The imbibition law of the Jurassic continental shale in Fuxing area is not clear， which brings great challenges to the production test after well shut-in. In addition， studies on the imbibition law and influencing factors of continental shale are insufficient.Therefore，the experiment on the imbibition law of the Jurassic continental shale in Fuxing area was conducted based on the lowfield nuclear magnetic resonance （NMR）. First， the differences in physical properties of shale of Lianggaoshan Formation and Dongyuemiao Member in Ziliujing Formation were tested and analyzed. Then， the changes in permeability and porosity before and after the imbibition were set as the evaluation indexes， and the influences of lithology， fluid， fluid pressure， and clay content on the imbibition law of the continental shale were analyzed. Besides， the wettability of the continental shale was evaluated. The experimental results show that compared with that of Dongyuemiao Member， the average porosity of shale of Lianggaoshan Formation is smaller， and the average permeability is larger； the average brittle mineral content is higher， and the average clay mineral content is lower. During the imbibition process of the Jurassic continental shale in Fuxing area， micro-fractures are induced by clay hydration， which provides additional imbibition channels. However， the imbibition ability of limestone is weaker than that of shale， and there are no micro-fractures during the imbibition； in addition， the shell limestone interlayer in the reservoir may inhibit the imbibition and micro-fracture propagation in the shale. The oil phase will enhance the micro-fracture propagation after the shale induces micro-fractures in the aqueous phase， and the complicated oil-water phase imbibition may be beneficial to the permeability improvement in the shale reservoir. Compared with atmospheric imbibition， pressureed imbibition has a limited effect on inducing micro-fractures and improving permeability， and the imbibition rate is larger； the imbibition equilibrium is earlier， but the imbibition amount is smaller. The influence of confining pressure on imbibition should be considered during well shut-in. The microfractures induced by hydration in shale with high clay mineral content are more significant， and the effect of improving permeability is more obvious. The imbibition rate and imbibition amount of shale in the oil phase are smaller than those in the aqueous phase，and the wettability of shale is hydrophilic. The experiment reveals the imbibition law and the characteristics of micro-fractures induced by the hydration of the Jurassic continental shale in Fuxing area， which provides a theoretical basis for the well shut-in and production test of continental shale during flowback.
2024, 31(6):127-139.
DOI: 10.13673/j.pgre.202302011
Abstract:
Flowback and early production of shale reservoirs usually show obvious characteristics of oil-water co-production after large-scale volume fracturing. Quantitative analysis of dynamic oil-water flowback and production has become a new method to explain fracture and reservoir parameters. However， the interpretation model and application of dynamic oil-water phase flowback and production are still insufficient at present. Based on the hypothesis of fracturing fluid occurrence after fracturing in shale reservoirs，this paper first established the flow equations of the water phase and oil phase considering fractures and then deduced the analytical solution and characteristic solution of the dynamic oil phase and water phase interpretation models by introducing pseudo-time and pseudo-pressure to linearize the equations. Finally， the paper developed a dynamic flowback and production interpretation method combining oil phase chart fitting and water phase linear analysis. The results show that in the log-log diagnostic curve， the oil phase flow exhibits linear flow in the stimulated zone with a slope of 1/2 and controlled flow at the stimulated zone boundary with a slope of 1， while the water phase flow exhibits linear flow in the fracture with a slope of 1/2 and controlled flow at the fracture boundary with a slope of 1. The established interpretation model of dynamic oil-water flowback and production can well explain the fracture and reservoir parameters. The half-length of fracture of the fracturing well， fracture conductivity， width and permeability of stimulated zones are well inversed based on the reservoir，fracturing， and dynamic data of a shale block in western China. Among them，the half-length of the fracture is in the range of 50-130 m； the fracture conductivity is in the range of 20-80 mD·m； the permeability of the stimulated zones is in the range of 0.01-0.05 mD； the width of the stimulated zones is in the range of 24-27 m. According to the inversion of fracture and stimulated zone parameters， the numerical simulation model of fractured horizontal well flowback and production is established. Moreover， the simulated output based on the interpretation results is in good agreement with the actual value， and the later predicted value is reasonable. The interpretation model of dynamic flowback and production established in this paper improves the dynamic analysis method of shale reservoirs and provides a basis for quantitative analysis of flowback and production characteristics of shale reservoirs， evaluation of fracturing effect， and formulation of efficient development countermeasures.
Flowback and early production of shale reservoirs usually show obvious characteristics of oil-water co-production after large-scale volume fracturing. Quantitative analysis of dynamic oil-water flowback and production has become a new method to explain fracture and reservoir parameters. However， the interpretation model and application of dynamic oil-water phase flowback and production are still insufficient at present. Based on the hypothesis of fracturing fluid occurrence after fracturing in shale reservoirs，this paper first established the flow equations of the water phase and oil phase considering fractures and then deduced the analytical solution and characteristic solution of the dynamic oil phase and water phase interpretation models by introducing pseudo-time and pseudo-pressure to linearize the equations. Finally， the paper developed a dynamic flowback and production interpretation method combining oil phase chart fitting and water phase linear analysis. The results show that in the log-log diagnostic curve， the oil phase flow exhibits linear flow in the stimulated zone with a slope of 1/2 and controlled flow at the stimulated zone boundary with a slope of 1， while the water phase flow exhibits linear flow in the fracture with a slope of 1/2 and controlled flow at the fracture boundary with a slope of 1. The established interpretation model of dynamic oil-water flowback and production can well explain the fracture and reservoir parameters. The half-length of fracture of the fracturing well， fracture conductivity， width and permeability of stimulated zones are well inversed based on the reservoir，fracturing， and dynamic data of a shale block in western China. Among them，the half-length of the fracture is in the range of 50-130 m； the fracture conductivity is in the range of 20-80 mD·m； the permeability of the stimulated zones is in the range of 0.01-0.05 mD； the width of the stimulated zones is in the range of 24-27 m. According to the inversion of fracture and stimulated zone parameters， the numerical simulation model of fractured horizontal well flowback and production is established. Moreover， the simulated output based on the interpretation results is in good agreement with the actual value， and the later predicted value is reasonable. The interpretation model of dynamic flowback and production established in this paper improves the dynamic analysis method of shale reservoirs and provides a basis for quantitative analysis of flowback and production characteristics of shale reservoirs， evaluation of fracturing effect， and formulation of efficient development countermeasures.
2024, 31(6):140-152.
DOI: 10.13673/j.pgre.202306024
Abstract:
CO2 miscible displacement is essential for developing low permeability reservoirs. The theoretical basis of CO2 development in low permeability reservoirs is to understand the influence of complex structures of porous media， physical properties of fluid， and injection parameters on the displacement effect. The mathematical model of miscible displacement was established by coupling the fluid motion equation with the convection-diffusion equation. Two kinds of core pores with different structures were developed using a random four-parameter growth method， and the CO2 miscible displacement in complex porous media was simulated.The change rule of CO2 concentration in different pore structures and the formation and distribution of remaining oil were compared，and the influence of viscosity difference， density difference， and injection rate on the two-phase flow behavior was analyzed.Then， the theoretical production charts for different pore structures under the influence of viscosity and the theoretical trend charts of concentration and viscosity changes under different injection rates were obtained， and the characteristics of miscible displacement at the pore scale were clarified. The results show that ① there are four types of remaining oil in the miscible displacement process affected by pore structures： remaining oil at the blind end， remaining oil in clusters， remaining oil with partition， remaining oil at the tail of rock skeleton， and oil film； ② the influence of CO2 viscosity on the oil displacement is different in different pore structures.The remaining oil content in pores is about 78%，while that in porous media with large channels is about 56%， and the two pore structures adapt to their dominant viscosity； ③ the swept ranges change as the density of injected CO2 increases gradually. Specifically，the distribution ranges of CO2 in the pores decrease but increase in the large channels. The comparison of mixture densities under different viscosity ratio logs shows the mixture densities under the maximum viscosity ratio log is 1.12 times that under the minimum viscosity ratio log. The maximum concentration ratio in the porous media with large channels is about 260， and that in the porous media without large channels is 450； ④ increasing the injection rate could disrupt the original displacement pressure system，increase the driving capacity， effectively reduce the distribution of remaining oil， and then improve the oil displacement effect.
CO2 miscible displacement is essential for developing low permeability reservoirs. The theoretical basis of CO2 development in low permeability reservoirs is to understand the influence of complex structures of porous media， physical properties of fluid， and injection parameters on the displacement effect. The mathematical model of miscible displacement was established by coupling the fluid motion equation with the convection-diffusion equation. Two kinds of core pores with different structures were developed using a random four-parameter growth method， and the CO2 miscible displacement in complex porous media was simulated.The change rule of CO2 concentration in different pore structures and the formation and distribution of remaining oil were compared，and the influence of viscosity difference， density difference， and injection rate on the two-phase flow behavior was analyzed.Then， the theoretical production charts for different pore structures under the influence of viscosity and the theoretical trend charts of concentration and viscosity changes under different injection rates were obtained， and the characteristics of miscible displacement at the pore scale were clarified. The results show that ① there are four types of remaining oil in the miscible displacement process affected by pore structures： remaining oil at the blind end， remaining oil in clusters， remaining oil with partition， remaining oil at the tail of rock skeleton， and oil film； ② the influence of CO2 viscosity on the oil displacement is different in different pore structures.The remaining oil content in pores is about 78%，while that in porous media with large channels is about 56%， and the two pore structures adapt to their dominant viscosity； ③ the swept ranges change as the density of injected CO2 increases gradually. Specifically，the distribution ranges of CO2 in the pores decrease but increase in the large channels. The comparison of mixture densities under different viscosity ratio logs shows the mixture densities under the maximum viscosity ratio log is 1.12 times that under the minimum viscosity ratio log. The maximum concentration ratio in the porous media with large channels is about 260， and that in the porous media without large channels is 450； ④ increasing the injection rate could disrupt the original displacement pressure system，increase the driving capacity， effectively reduce the distribution of remaining oil， and then improve the oil displacement effect.
14 Assessment of oil displacement performance of new amine-ether
gemini surfactant and its application
2024, 31(6):153-159.
DOI: 10.13673/j.pgre.202404024
Abstract:
To address the challenges of low injection capacity， low fluid recovery rate， and low recovery in the water flooding development of low-permeability reservoirs in Shengli Oilfield， this paper proposed an oil displacement technology with new amineether gemini surfactants. The molecular structure was designed on the new amine-ether gemini surfactant for oil displacement， and the interfacial properties of different molecular structures were evaluated. The sample G-3 with the best interfacial properties was selected，and the emulsification and oil displacement performance were evaluated at different concentrations. The oil displacement mechanism was elucidated by combining micro etched glass models. The experimental results showed that the new amine-ether gemini surfactant with a concentration of 0.2% can reduce the interfacial tension between oil and water to 0.003 9 mN/m， forming the stable emulsion with crude oil， and the particle size of lotion drops is 12 μm. For the postflood core with a permeability of 6.966 mD， the G-3 solution of the new amine-ether gemini surfactant with a concentration of 0.2% is injected at 0.5 PV， and the recovery can increase by 9.6% and the pressure reduces by 17.4% after water flooding again. The micro oil displacement mechanisms are the reduction of the interfacial tension between oil and water and the residual oil emulsification and coalescence. A field test was conducted in the low-permeability block of Shengli Oilfield. After implementation， the injection capacity of the water wells in the block was doubled. The daily oil production of the oil wells was 5.7 t/d， and the water cut decreased by 11.0%. Up to June 2023， the cumulative oil production in the block had been 1 791 t， achieving good development effect.
To address the challenges of low injection capacity， low fluid recovery rate， and low recovery in the water flooding development of low-permeability reservoirs in Shengli Oilfield， this paper proposed an oil displacement technology with new amineether gemini surfactants. The molecular structure was designed on the new amine-ether gemini surfactant for oil displacement， and the interfacial properties of different molecular structures were evaluated. The sample G-3 with the best interfacial properties was selected，and the emulsification and oil displacement performance were evaluated at different concentrations. The oil displacement mechanism was elucidated by combining micro etched glass models. The experimental results showed that the new amine-ether gemini surfactant with a concentration of 0.2% can reduce the interfacial tension between oil and water to 0.003 9 mN/m， forming the stable emulsion with crude oil， and the particle size of lotion drops is 12 μm. For the postflood core with a permeability of 6.966 mD， the G-3 solution of the new amine-ether gemini surfactant with a concentration of 0.2% is injected at 0.5 PV， and the recovery can increase by 9.6% and the pressure reduces by 17.4% after water flooding again. The micro oil displacement mechanisms are the reduction of the interfacial tension between oil and water and the residual oil emulsification and coalescence. A field test was conducted in the low-permeability block of Shengli Oilfield. After implementation， the injection capacity of the water wells in the block was doubled. The daily oil production of the oil wells was 5.7 t/d， and the water cut decreased by 11.0%. Up to June 2023， the cumulative oil production in the block had been 1 791 t， achieving good development effect.
2024, 31(6):160-167.
DOI: 10.13673/j.pgre.202307001
Abstract:
In view of the difficulties in formation energy replenishment and failed injection and production by water drive in lowpermeability reservoirs， Shengli Oilfield proposed a water injection technology based on pressure drive for low-permeability reservoirs according to the technical requirements for increasing liquid production and stable oil production in the oilfield. Pressure drive could effectively increase the water injection volume through high-pressure water injection. Field tests showed that a certain scale of fractures was formed in the reservoir during the pressure drive. However， the breakdown pressure and fracture propagation law caused by pressure drive were still unclear. Five pressure drive experiments were carried out using natural sandstone and true triaxial hydraulic fracturing platforms to optimize field construction parameters. The influence of injection rate on breakdown pressure and fracture geometry caused by pressure drive was studied， and that of injection modes on fracture geometry was analyzed. The causes were analyzed using the porous elasticity theory. The experimental results showed that there are both obvious fracture initiation pressure and breakdown pressure during the pressure drive. Fracture development presents three stages： elastic deformation， microfracture development， and instability failure. The fracture initiation pressure is basically unchanged， and the breakdown pressure gradually decreases with the increase in injection rate. The H-F model can be used to predict the fracture initiation pressure， and the H-W model can be used to predict the upper limit of the breakdown pressure. The direction of fracture propagation caused by pressure drive is greatly affected by rock heterogeneity， which affects the pore pressure field near the wellbore and thereby changes the stress field so that the fracture propagation is no longer perpendicular to the minimum geostress. The angles between the branch fracture and the main fracture are large during injection with a constant rate， forming a fishbone-like fracture； the branch fracture is nearly parallel to the main fracture， and the fracture zones are formed on both sides of the main fractures during injection with a variable rates.
In view of the difficulties in formation energy replenishment and failed injection and production by water drive in lowpermeability reservoirs， Shengli Oilfield proposed a water injection technology based on pressure drive for low-permeability reservoirs according to the technical requirements for increasing liquid production and stable oil production in the oilfield. Pressure drive could effectively increase the water injection volume through high-pressure water injection. Field tests showed that a certain scale of fractures was formed in the reservoir during the pressure drive. However， the breakdown pressure and fracture propagation law caused by pressure drive were still unclear. Five pressure drive experiments were carried out using natural sandstone and true triaxial hydraulic fracturing platforms to optimize field construction parameters. The influence of injection rate on breakdown pressure and fracture geometry caused by pressure drive was studied， and that of injection modes on fracture geometry was analyzed. The causes were analyzed using the porous elasticity theory. The experimental results showed that there are both obvious fracture initiation pressure and breakdown pressure during the pressure drive. Fracture development presents three stages： elastic deformation， microfracture development， and instability failure. The fracture initiation pressure is basically unchanged， and the breakdown pressure gradually decreases with the increase in injection rate. The H-F model can be used to predict the fracture initiation pressure， and the H-W model can be used to predict the upper limit of the breakdown pressure. The direction of fracture propagation caused by pressure drive is greatly affected by rock heterogeneity， which affects the pore pressure field near the wellbore and thereby changes the stress field so that the fracture propagation is no longer perpendicular to the minimum geostress. The angles between the branch fracture and the main fracture are large during injection with a constant rate， forming a fishbone-like fracture； the branch fracture is nearly parallel to the main fracture， and the fracture zones are formed on both sides of the main fractures during injection with a variable rates.
2024, 31(6):168-178.
DOI: 10.13673/j.pgre.202311009
Abstract:
Fractured-vuggy carbonate reservoirs are characterized by low porosity， low permeability， and strong heterogeneity. Acid fracturing is the primary technical means to increase the production of this kind of reservoir， and the key to fracturing reconstruction is to communicate fractured-vuggy reservoir efficiently. However， due to the influence of heterogeneity and randomly distributed vugs， the fracture propagation paths are complicated during acid fracturing， and the law of fracture-vug interaction is not clear. Therefore， laboratory experiments were carried out to study the changes in porosity， permeability， and mechanical properties of carbonate rocks before and after acid etching. The experimental results showed that acid-rock reaction significantly influences rock mechanics parameters. With a 15% mass fraction of gelled acid as an example， core porosity and permeability increase； the compressive strength and elastic modulus of cores decrease by 42% and 60%， and Poisson’s ratio increases by 25% after acid etching. Then， the rock’s physical and mechanical evolution equation was introduced into the classical cohesive model， and a fracture propagation model considering acid-rock reaction was established. The model was compared with the conventional hydraulic fracture propagation model and the laboratory physical simulation experiment of acid fracturing， and the effectiveness and correctness of the model were verified. Finally， the model was used to study the effects of horizontal in-situ stress difference， vug size， and injection displacement on fracture propagation path. The simulation results showed that ① Artificial fractures tend to penetrate small vugs， bypass medium vugs， and communicate with large vugs. ②It is helpful for the communication between fractures and vugs when the horizontal stress difference exceeds 5 MPa and the injection displacement exceeds 0.057 m3/s. ③ The acid-rock reaction can significantly improve the fractured-vuggy communication efficiency， and the fracture propagation area by acid fracturing is twice that by conventional hydraulic fracturing when the injection displacement is 0.1 m3/s. Therefore， in order to improve the fractured-vuggy communication efficiency and acid fracturing effect， the injection displacement should be appropriately increased when stimulating the carbonate reservoir with high stress difference.
Fractured-vuggy carbonate reservoirs are characterized by low porosity， low permeability， and strong heterogeneity. Acid fracturing is the primary technical means to increase the production of this kind of reservoir， and the key to fracturing reconstruction is to communicate fractured-vuggy reservoir efficiently. However， due to the influence of heterogeneity and randomly distributed vugs， the fracture propagation paths are complicated during acid fracturing， and the law of fracture-vug interaction is not clear. Therefore， laboratory experiments were carried out to study the changes in porosity， permeability， and mechanical properties of carbonate rocks before and after acid etching. The experimental results showed that acid-rock reaction significantly influences rock mechanics parameters. With a 15% mass fraction of gelled acid as an example， core porosity and permeability increase； the compressive strength and elastic modulus of cores decrease by 42% and 60%， and Poisson’s ratio increases by 25% after acid etching. Then， the rock’s physical and mechanical evolution equation was introduced into the classical cohesive model， and a fracture propagation model considering acid-rock reaction was established. The model was compared with the conventional hydraulic fracture propagation model and the laboratory physical simulation experiment of acid fracturing， and the effectiveness and correctness of the model were verified. Finally， the model was used to study the effects of horizontal in-situ stress difference， vug size， and injection displacement on fracture propagation path. The simulation results showed that ① Artificial fractures tend to penetrate small vugs， bypass medium vugs， and communicate with large vugs. ②It is helpful for the communication between fractures and vugs when the horizontal stress difference exceeds 5 MPa and the injection displacement exceeds 0.057 m3/s. ③ The acid-rock reaction can significantly improve the fractured-vuggy communication efficiency， and the fracture propagation area by acid fracturing is twice that by conventional hydraulic fracturing when the injection displacement is 0.1 m3/s. Therefore， in order to improve the fractured-vuggy communication efficiency and acid fracturing effect， the injection displacement should be appropriately increased when stimulating the carbonate reservoir with high stress difference.
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