Volume 28,Issue 5,2021 Table of Contents
2021, 28(5):1-12.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.001
Abstract:
Jiyang Depression is a typical continental faulted basin in eastern China. It has experienced 60 years of exploration and development and entered a fine exploration stage of complex subtle reservoirs. Given the high degree of exploration and resource discovery，small and hidden exploration targets，and other grave situations，it is necessary to deepen oil and gas exploration and realize large-scale storage increase and efficient exploration. After the systematical analysis of the existing exploration state and key problems，it is considered that the exploration degree in the Upper Submember and its upper strata of the Fourth Member of Shahejie Formation in Jiyang Depression is high，which is a mature field. The exploration degree in the Lower Submember and its lower strata of the Fourth Member of Shahejie Formation is low，which belongs to the “three-new”field. In addition，shale oil and gas resources have great potential，representing an alternative exploration field. In light of different exploration fields，corresponding exploration ideas are put forward，namely fine exploration in mature fields for stable reservoir increase，risk exploration and preliminary prospecting in the“three-new”fields for large-scale discovery，and in-source exploration of shale oil and gas fields for a long-term plan.
Jiyang Depression is a typical continental faulted basin in eastern China. It has experienced 60 years of exploration and development and entered a fine exploration stage of complex subtle reservoirs. Given the high degree of exploration and resource discovery，small and hidden exploration targets，and other grave situations，it is necessary to deepen oil and gas exploration and realize large-scale storage increase and efficient exploration. After the systematical analysis of the existing exploration state and key problems，it is considered that the exploration degree in the Upper Submember and its upper strata of the Fourth Member of Shahejie Formation in Jiyang Depression is high，which is a mature field. The exploration degree in the Lower Submember and its lower strata of the Fourth Member of Shahejie Formation is low，which belongs to the “three-new”field. In addition，shale oil and gas resources have great potential，representing an alternative exploration field. In light of different exploration fields，corresponding exploration ideas are put forward，namely fine exploration in mature fields for stable reservoir increase，risk exploration and preliminary prospecting in the“three-new”fields for large-scale discovery，and in-source exploration of shale oil and gas fields for a long-term plan.
2021, 28(5):13-21.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.002
Abstract:
After more than 30 years of exploration for coal gas in Jiyang Depression，breakthroughs have been made in Gubei，Huimin，Linqing，Chexi，and other areas，but large-scale reserves have not been formed. Therefore，it is necessary to further explore the main factors controlling the accumulations of coal gas. Based on the seismic survey，mud logging，well logging，and production test data，the genetic types of the Lower Paleozoic natural gas in the northern steep slope zone in Chexi Subsag，Chezhen Sag，Jiyang Depression（the northwest of Chezhen Sag）. In addition，the differences and main controlling factors of accumulation for the Lower Paleozoic coal gas reservoirs in the study area were analyzed. The results demonstrate that the Lower Paleozoic natural gas in the northwest of Chezhen Sag is coal gas，which mainly comes from thecoal-bearing strata of the Upper Paleozoic，leading to favorable geological conditions for accumulation. The coal-bearing strata have a buried depth generally over 4 100 m and have entered the stage of secondary hydrocarbon generation，and the differences in hydrocarbon generation quantity are determined by their buried depth and thickness. The fault displacement of adjacent faults plays a crucial role in coal gas accumulation：It dominates both trap-source connection and the width of the Lower Paleozoic reservoir，thereby directly determining the effectiveness of the trap. When the fault displacement of adjacent controlled faults is more than 150 m，the Lower Paleozoic trap in the hanging wall can be connected with the Upper Paleozoic source rock in the footwall. The coal gas from the Upper Paleozoic migrates along the fault into the Lower Paleozoic carbonate rock reservoir transformed by the fault，and then accumulates in the favorable trap near the source.
After more than 30 years of exploration for coal gas in Jiyang Depression，breakthroughs have been made in Gubei，Huimin，Linqing，Chexi，and other areas，but large-scale reserves have not been formed. Therefore，it is necessary to further explore the main factors controlling the accumulations of coal gas. Based on the seismic survey，mud logging，well logging，and production test data，the genetic types of the Lower Paleozoic natural gas in the northern steep slope zone in Chexi Subsag，Chezhen Sag，Jiyang Depression（the northwest of Chezhen Sag）. In addition，the differences and main controlling factors of accumulation for the Lower Paleozoic coal gas reservoirs in the study area were analyzed. The results demonstrate that the Lower Paleozoic natural gas in the northwest of Chezhen Sag is coal gas，which mainly comes from thecoal-bearing strata of the Upper Paleozoic，leading to favorable geological conditions for accumulation. The coal-bearing strata have a buried depth generally over 4 100 m and have entered the stage of secondary hydrocarbon generation，and the differences in hydrocarbon generation quantity are determined by their buried depth and thickness. The fault displacement of adjacent faults plays a crucial role in coal gas accumulation：It dominates both trap-source connection and the width of the Lower Paleozoic reservoir，thereby directly determining the effectiveness of the trap. When the fault displacement of adjacent controlled faults is more than 150 m，the Lower Paleozoic trap in the hanging wall can be connected with the Upper Paleozoic source rock in the footwall. The coal gas from the Upper Paleozoic migrates along the fault into the Lower Paleozoic carbonate rock reservoir transformed by the fault，and then accumulates in the favorable trap near the source.
2021, 28(5):22-31.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.003
Abstract:
The reservoir fluid type is a key factor to evaluating productivity and identifying reserves scale during exploration and making development plans during production. Fast identification of reservoir fluid types while drilling can accelerate exploration and production. The fluid types of the Archaeozoic buried hill reservoir of M structure at the southwest margin of Bozhong Sag，Bohai Sea，East China are complex. According to the pressure-volume-temperature（PVT）phase analysis，four combined parameters based discriminant analysis and φ1 parameter based discriminant analysis were employed in identifying reservoir fluid types while drilling in the study area. The study demonstrates that the two methods based on standardized gas logging-while-drilling data witness poor consistency among the identified reservoir fluid types in the study area，while those relying on the test gas component from the well site obtain consistent and positive results. A model is built for the fitting relationship between the test gas component from the well site and standardized gas logging-while-drilling data，realizing the fast identification of fluid types in the buried hill reservoir while drilling and successful applications in the Archaeozoic buried hill reservoir of M structure at the southwest margin of Bozhong Sag.
The reservoir fluid type is a key factor to evaluating productivity and identifying reserves scale during exploration and making development plans during production. Fast identification of reservoir fluid types while drilling can accelerate exploration and production. The fluid types of the Archaeozoic buried hill reservoir of M structure at the southwest margin of Bozhong Sag，Bohai Sea，East China are complex. According to the pressure-volume-temperature（PVT）phase analysis，four combined parameters based discriminant analysis and φ1 parameter based discriminant analysis were employed in identifying reservoir fluid types while drilling in the study area. The study demonstrates that the two methods based on standardized gas logging-while-drilling data witness poor consistency among the identified reservoir fluid types in the study area，while those relying on the test gas component from the well site obtain consistent and positive results. A model is built for the fitting relationship between the test gas component from the well site and standardized gas logging-while-drilling data，realizing the fast identification of fluid types in the buried hill reservoir while drilling and successful applications in the Archaeozoic buried hill reservoir of M structure at the southwest margin of Bozhong Sag.
2021, 28(5):32-49.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.004
Abstract:
In recent years，China has made continuous breakthroughs in the field of deep marine carbonate petroleum reservoirs and reaped substantial achievements in exploration and development. However，the influence of strong reservoir heterogeneity on development effect appeared gradually as some deep reservoirs entered into the middle or final stage of the development. It is urgent to research reservoir heterogeneity to guide the adjustment and potential tapping of oil and gas reservoirs. Multiple media such as pores，fractures，and caves are widely developed in deep marine carbonate reservoirs. Their formation and evolution are controlled by multiple stages and geological factors and present coupling development，which brings strong multi-scale heterogeneous reservoirs. At the moment，the research on the heterogeneity of deep marine car? bonate reservoirs is still in its infancy. There are poor pertinence and applicability in the research on the heterogeneity of carbonate reservoirs，which refers to the relevant theories and research methods of clastic reservoir heterogeneity. For example，the hierarchical classification scheme of clastic reservoir heterogeneity is not completely suitable for deep marine carbonate reservoirs，and a recognized hierarchical classification scheme for carbonate reservoir heterogeneity has not been established so far. The heterogeneity of deep marine carbonate reservoirs is more complex，and there is a lack of systematic understanding of the formation mechanism and distribution law of multi-scale heterogeneity under the coupling development of different media. In addition，based on traditional methods，the prediction and characterization accuracy for the spatial distribution of deep carbonate reservoir heterogeneity is still difficult to meet the actual production needs. Therefore，this paper proposes the following three research directions：study the formation mechanism of multi-scale heterogeneity under the coupling control of a multi-media system and build the development model of multi-scale heterogeneity；establish an applicable classification scheme of deep marine carbonate strata（types）and continuously improve the prediction and characterization accuracy for the spatial distribution of multi-scale heterogeneity with new technical means；and investigate the mechanism of multi-scale heterogeneous seepage and clarify the influence of heterogeneity on development.
In recent years，China has made continuous breakthroughs in the field of deep marine carbonate petroleum reservoirs and reaped substantial achievements in exploration and development. However，the influence of strong reservoir heterogeneity on development effect appeared gradually as some deep reservoirs entered into the middle or final stage of the development. It is urgent to research reservoir heterogeneity to guide the adjustment and potential tapping of oil and gas reservoirs. Multiple media such as pores，fractures，and caves are widely developed in deep marine carbonate reservoirs. Their formation and evolution are controlled by multiple stages and geological factors and present coupling development，which brings strong multi-scale heterogeneous reservoirs. At the moment，the research on the heterogeneity of deep marine car? bonate reservoirs is still in its infancy. There are poor pertinence and applicability in the research on the heterogeneity of carbonate reservoirs，which refers to the relevant theories and research methods of clastic reservoir heterogeneity. For example，the hierarchical classification scheme of clastic reservoir heterogeneity is not completely suitable for deep marine carbonate reservoirs，and a recognized hierarchical classification scheme for carbonate reservoir heterogeneity has not been established so far. The heterogeneity of deep marine carbonate reservoirs is more complex，and there is a lack of systematic understanding of the formation mechanism and distribution law of multi-scale heterogeneity under the coupling development of different media. In addition，based on traditional methods，the prediction and characterization accuracy for the spatial distribution of deep carbonate reservoir heterogeneity is still difficult to meet the actual production needs. Therefore，this paper proposes the following three research directions：study the formation mechanism of multi-scale heterogeneity under the coupling control of a multi-media system and build the development model of multi-scale heterogeneity；establish an applicable classification scheme of deep marine carbonate strata（types）and continuously improve the prediction and characterization accuracy for the spatial distribution of multi-scale heterogeneity with new technical means；and investigate the mechanism of multi-scale heterogeneous seepage and clarify the influence of heterogeneity on development.
2021, 28(5):50-56.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.005
Abstract:
Recently，Yangjiang Sag has become a new area that has made major breakthroughs in petroleum exploration in Pearl River Mouth Basin. To clarify the hydrocarbon generation potential and accumulation contribution of source rocks of Enping 21 Subsag in Yangjiang Sag，the sedimentary environment，source of organic matter，and hydrocarbon generation potential of source rocks of Wenchang Formation drilled in Yangjiang Sag were systematically analyzed，using methods combining inorganic element analysis with organic geochemical analysis in this paper. The sources of the discovered crude oil were identified and the accumulation contribution of source rocks in different sedimentary environments was estimated. The results show that Enping 21 Subsag is characterized by a humid-hot climate，and a deep freshwater lake basin with low salinity in a sub-reductive environment on the whole，and two sets of high-quality source rocks，including semi-deep to deep and shallow to semi-deep lacustrine source rocks，are developed during the deposition of Wenchang Formation. The oilsource correlation and the calculation of the proportion of crude oil from different sources in the reservoirs indicate that the crude oil from shallow to semi-deep lacustrine source rocks accounts for 85%，and that from semi-deep to deep source rocks only accounts for 15%. The shallow to semi-deep lacustrine source rocks also have strong hydrocarbon supply ability，and the shallow and small subsags developed with shallow to semi-deep lacustrine source rocks also have great petroleum resource potential.
Recently，Yangjiang Sag has become a new area that has made major breakthroughs in petroleum exploration in Pearl River Mouth Basin. To clarify the hydrocarbon generation potential and accumulation contribution of source rocks of Enping 21 Subsag in Yangjiang Sag，the sedimentary environment，source of organic matter，and hydrocarbon generation potential of source rocks of Wenchang Formation drilled in Yangjiang Sag were systematically analyzed，using methods combining inorganic element analysis with organic geochemical analysis in this paper. The sources of the discovered crude oil were identified and the accumulation contribution of source rocks in different sedimentary environments was estimated. The results show that Enping 21 Subsag is characterized by a humid-hot climate，and a deep freshwater lake basin with low salinity in a sub-reductive environment on the whole，and two sets of high-quality source rocks，including semi-deep to deep and shallow to semi-deep lacustrine source rocks，are developed during the deposition of Wenchang Formation. The oilsource correlation and the calculation of the proportion of crude oil from different sources in the reservoirs indicate that the crude oil from shallow to semi-deep lacustrine source rocks accounts for 85%，and that from semi-deep to deep source rocks only accounts for 15%. The shallow to semi-deep lacustrine source rocks also have strong hydrocarbon supply ability，and the shallow and small subsags developed with shallow to semi-deep lacustrine source rocks also have great petroleum resource potential.
2021, 28(5):57-63.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.006
Abstract:
Due to the fast lateral changes of tight conglomerate reservoirs in Mahu area，difficult prediction of the interwell structures and reservoirs，and low drilling ratios of high-quality reservoirs，the geological modeling based on multiparameter constrained inversion was employed to characterize the three-dimensional spatial distribution of high-quality reservoirs，providing a solid basis for early warning and control of horizontal wells. The early-warning marker bed was established on the oil pay，and the local velocity field and structure as well as the geological model were updated according to the actual drilling data of the marker bed. The changes in key parameters，including target depth and horizontal-section dip angles，were forewarned. According to the prediction results of lithological rhythms along the well trajectory and the variation in resistivity while drilling，the early risk warning of drilling out of high-quality reservoirs in horizontal sections was carried out in time to improve the accuracy of target entry and drilling ratios of for high-quality reservoirs. When the positive rhythm area was drilled，the resistivity drop reflected the topcut，at a risk of top drill-out，which required early warning and a smaller hole angle；when the anti-rhythm area was drilled，the resistivity declined rapidly，at a risk of bottom drill-out，which demanded early warning and a larger hole angle. The application results in Mahu area demonstrate that the early warning technology by geological modeling based on multiparameter constrained inversion for horizontal wells enhances the drilling ratios of oil pays by 7.4% and cut the drilling period by 8.7%.
Due to the fast lateral changes of tight conglomerate reservoirs in Mahu area，difficult prediction of the interwell structures and reservoirs，and low drilling ratios of high-quality reservoirs，the geological modeling based on multiparameter constrained inversion was employed to characterize the three-dimensional spatial distribution of high-quality reservoirs，providing a solid basis for early warning and control of horizontal wells. The early-warning marker bed was established on the oil pay，and the local velocity field and structure as well as the geological model were updated according to the actual drilling data of the marker bed. The changes in key parameters，including target depth and horizontal-section dip angles，were forewarned. According to the prediction results of lithological rhythms along the well trajectory and the variation in resistivity while drilling，the early risk warning of drilling out of high-quality reservoirs in horizontal sections was carried out in time to improve the accuracy of target entry and drilling ratios of for high-quality reservoirs. When the positive rhythm area was drilled，the resistivity drop reflected the topcut，at a risk of top drill-out，which required early warning and a smaller hole angle；when the anti-rhythm area was drilled，the resistivity declined rapidly，at a risk of bottom drill-out，which demanded early warning and a larger hole angle. The application results in Mahu area demonstrate that the early warning technology by geological modeling based on multiparameter constrained inversion for horizontal wells enhances the drilling ratios of oil pays by 7.4% and cut the drilling period by 8.7%.
2021, 28(5):64-73.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.007
Abstract:
Mishi Basin is located at the junction of the Yangtze Plate and Songpan-Ganzi orogenic belt. Its tectonic characteristics and genesis were studied with the combination of inversion and forward modeling. Affected by the Hercynian movement，the tectonic deformation in the basin was dominated by extensional faults. The Yangtze Plate subducted into Songpan-Ganzi orogenic belt in the Indosinian period，thus the tectonic deformation was dominated by compression and uplift in the basin and the part of the Triassic was denudated. The periphery in the basin continued to uplift in the Yanshanian period，while the internal structure was inherited. The basin entered a stage of rapid compression and uplift in Himalayan period. The typical tectonic characteristics were thrust faults and fault-related folds，and the internal tectonic deformation varied in the basin. The fault-bend deformation constrained by the basement-involved basin-controlling fault was dominant in the east，and the fault detachment deformation controlled by secondary faults was the typical feature in the western margin.The fault development pattern in the basin gradually expanded from the east in the basin to the west. In terms of genesis，from the Hercynian period to the Indosinian period，the basin was continuously compressed by the Yunnan-Qinghai-Tibet oceanic plate and the Pacific Plate，and the earliest Sikai fault was formed inside the basin. The basin appeared in its embryonic form in the Yanshanian period，and the extremely thick Jurassic and Cretaceous were deposited with Qiliba area as the center，with the periphery in the basin continuing to uplift. The basin was compressed by Songpan-Ganzi orogenic belt and Jinpingshan orogenic belt，thus the tectonic pattern in the basin with the coexistence of thrust faults and fault-related folds was formed in the Himalayan period.
Mishi Basin is located at the junction of the Yangtze Plate and Songpan-Ganzi orogenic belt. Its tectonic characteristics and genesis were studied with the combination of inversion and forward modeling. Affected by the Hercynian movement，the tectonic deformation in the basin was dominated by extensional faults. The Yangtze Plate subducted into Songpan-Ganzi orogenic belt in the Indosinian period，thus the tectonic deformation was dominated by compression and uplift in the basin and the part of the Triassic was denudated. The periphery in the basin continued to uplift in the Yanshanian period，while the internal structure was inherited. The basin entered a stage of rapid compression and uplift in Himalayan period. The typical tectonic characteristics were thrust faults and fault-related folds，and the internal tectonic deformation varied in the basin. The fault-bend deformation constrained by the basement-involved basin-controlling fault was dominant in the east，and the fault detachment deformation controlled by secondary faults was the typical feature in the western margin.The fault development pattern in the basin gradually expanded from the east in the basin to the west. In terms of genesis，from the Hercynian period to the Indosinian period，the basin was continuously compressed by the Yunnan-Qinghai-Tibet oceanic plate and the Pacific Plate，and the earliest Sikai fault was formed inside the basin. The basin appeared in its embryonic form in the Yanshanian period，and the extremely thick Jurassic and Cretaceous were deposited with Qiliba area as the center，with the periphery in the basin continuing to uplift. The basin was compressed by Songpan-Ganzi orogenic belt and Jinpingshan orogenic belt，thus the tectonic pattern in the basin with the coexistence of thrust faults and fault-related folds was formed in the Himalayan period.
2021, 28(5):74-80.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.008
Abstract:
The storage space of shale reservoirs is mainly composed of nanoscale pores，in which the shale oil occurrence can have important influence on its flow law. The full-scale pore size distribution of shale pore structure and the main-frequency pore diameter of nanoscale pores in Dongying Depression were obtained by the nuclear magnetic resonance freezethaw（NMRF）technology. With the well effluent composition of Well NX55 in Dongying Depression，the molecular dynamics simulation was used to establish a typical nanoscale pore model of Dongying Depression，with which the occurrence of shale oil in nanoscale pores of organic matter was studied. The study results show as follow：①The main-frequency pore diameter of nanoscale pores in shale reservoirs of Dongying Depression is 15 nm；②The density of crude oil in the organic nanoscale pores gradually decreases from surface to center；③The shale oil molecules can form a“quasi-solid”layer on the walls of organic nanoscale pores，and its density is about 1.1-3.15 times that of the free crude oil in the center of the pores；④The shale oil molecules are adsorbed in four layers in organic nanoscale pores. The thickness of the first layer is the largest，and the calculated proportion of absorbed shale oil in Dongying Depression is 19.8%.
The storage space of shale reservoirs is mainly composed of nanoscale pores，in which the shale oil occurrence can have important influence on its flow law. The full-scale pore size distribution of shale pore structure and the main-frequency pore diameter of nanoscale pores in Dongying Depression were obtained by the nuclear magnetic resonance freezethaw（NMRF）technology. With the well effluent composition of Well NX55 in Dongying Depression，the molecular dynamics simulation was used to establish a typical nanoscale pore model of Dongying Depression，with which the occurrence of shale oil in nanoscale pores of organic matter was studied. The study results show as follow：①The main-frequency pore diameter of nanoscale pores in shale reservoirs of Dongying Depression is 15 nm；②The density of crude oil in the organic nanoscale pores gradually decreases from surface to center；③The shale oil molecules can form a“quasi-solid”layer on the walls of organic nanoscale pores，and its density is about 1.1-3.15 times that of the free crude oil in the center of the pores；④The shale oil molecules are adsorbed in four layers in organic nanoscale pores. The thickness of the first layer is the largest，and the calculated proportion of absorbed shale oil in Dongying Depression is 19.8%.
2021, 28(5):81-86.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.009
Abstract:
Thermal recovery，gas flooding，and chemical flooding are widely used in China and abroad and are still the three main application technologies for enhanced oil recovery（EOR）. With the wider and deeper application of EOR technology，traditional EOR technologies are facing increasing challenges. This paper systematically summarized and analyzed the progress in the development and application of new technologies for EOR from new materials，new fields，and new methods.Functional polymers，dimethyl ether，and nano-materials were highlighted as new materials；CO2 miscible flooding in residual oil resources，chemical flooding in offshore oil fields，and EOR methods in unconventional shale oil reservoirs were focused as new fields；new methods concentrated on technology combination，such as alkali-emulsion-polymer composite flooding，sonication technology，and low-salinity water-alternate-surfactant injection. In the future，we will explore a new generation of new technologies for EOR，with the core of“low cost，green and low carbon，and revolutionary breakthroughs”.
Thermal recovery，gas flooding，and chemical flooding are widely used in China and abroad and are still the three main application technologies for enhanced oil recovery（EOR）. With the wider and deeper application of EOR technology，traditional EOR technologies are facing increasing challenges. This paper systematically summarized and analyzed the progress in the development and application of new technologies for EOR from new materials，new fields，and new methods.Functional polymers，dimethyl ether，and nano-materials were highlighted as new materials；CO2 miscible flooding in residual oil resources，chemical flooding in offshore oil fields，and EOR methods in unconventional shale oil reservoirs were focused as new fields；new methods concentrated on technology combination，such as alkali-emulsion-polymer composite flooding，sonication technology，and low-salinity water-alternate-surfactant injection. In the future，we will explore a new generation of new technologies for EOR，with the core of“low cost，green and low carbon，and revolutionary breakthroughs”.
2021, 28(5):87-93.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.010
Abstract:
At the late stage of water flooding，the invalid circulation of injected water in fault-block reservoirs makes it difficult to increase pressure. The proposed combined flooding technology of CO2 gas cap and artificial edge water is considered as an effective solution to this problem. In order to study the pressure recovery of combined flooding reservoir，the relationship between pressure recovery rates and injection rates，as well as the optimization of water injection rate，gas injection rate and injection time were studied. Indoor experiments were conducted to evaluate the qualitative relationship of pressure recovery rates with gas injection volumes/rates and injection rate ratios between gas and water. Based on numerical simulation，single-factor analysis and orthogonal experiment design were combined to verify the experimental results. The quantitative relationship of the pressure recovery rates with the above three factors was established by response surface analysis，and the correlation prediction model was regressed. Finally，the technical policies for combined flooding were comparatively optimized. The research results show that the combined flooding effect is positively correlated with the injection rates，gas injection volumes/rates，and injection rate ratios between gas and water，and it is most sensitive to the gas injection rates. There are optimal gas/water injection rates for combined flooding and an optimal matching relationship between them，and then a chart for determining the injection timing for combined flooding is given.
At the late stage of water flooding，the invalid circulation of injected water in fault-block reservoirs makes it difficult to increase pressure. The proposed combined flooding technology of CO2 gas cap and artificial edge water is considered as an effective solution to this problem. In order to study the pressure recovery of combined flooding reservoir，the relationship between pressure recovery rates and injection rates，as well as the optimization of water injection rate，gas injection rate and injection time were studied. Indoor experiments were conducted to evaluate the qualitative relationship of pressure recovery rates with gas injection volumes/rates and injection rate ratios between gas and water. Based on numerical simulation，single-factor analysis and orthogonal experiment design were combined to verify the experimental results. The quantitative relationship of the pressure recovery rates with the above three factors was established by response surface analysis，and the correlation prediction model was regressed. Finally，the technical policies for combined flooding were comparatively optimized. The research results show that the combined flooding effect is positively correlated with the injection rates，gas injection volumes/rates，and injection rate ratios between gas and water，and it is most sensitive to the gas injection rates. There are optimal gas/water injection rates for combined flooding and an optimal matching relationship between them，and then a chart for determining the injection timing for combined flooding is given.
2021, 28(5):94-99.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.011
Abstract:
For tight oil reservoirs，based on flow experiments and theoretical analysis，a new method for characterizing nonlinear percolation in tight oil reservoirs percolationwas developed. Based on the characteristics of dynamic resistance gradient in the percolation process of tight oil reservoirspercolation，this method adopted the flow experiment with reservoir cores to obtain three characterization parameters including starting pressure gradient，pseudo-starting pressure gradient，and measured liquid permeability. Thus，a new characterization model of nonlinear percolation in tight oil reservoirspercolation，i.e.，dynamic resistance gradient model，was built and verified on a single-well scale. The research results show that with the increase in displacement pressure，the dynamic resistance gradient gradually increases and is linearly correlated to the logarithm of the displacement pressure gradient. The mathematical characterization of nonlinear percolation is related to three parameters，namely starting pressure gradient，pseudo-starting pressure gradient，and measured liquid permeability.According to the three parameters，the characterization of nonlinear percolation in tight oil reservoirs was established based on flow experiments. From the perspective of reservoir application，the proposed characterization model is more accurate than the Darcy model and the pseudo-starting pressure gradient model.
For tight oil reservoirs，based on flow experiments and theoretical analysis，a new method for characterizing nonlinear percolation in tight oil reservoirs percolationwas developed. Based on the characteristics of dynamic resistance gradient in the percolation process of tight oil reservoirspercolation，this method adopted the flow experiment with reservoir cores to obtain three characterization parameters including starting pressure gradient，pseudo-starting pressure gradient，and measured liquid permeability. Thus，a new characterization model of nonlinear percolation in tight oil reservoirspercolation，i.e.，dynamic resistance gradient model，was built and verified on a single-well scale. The research results show that with the increase in displacement pressure，the dynamic resistance gradient gradually increases and is linearly correlated to the logarithm of the displacement pressure gradient. The mathematical characterization of nonlinear percolation is related to three parameters，namely starting pressure gradient，pseudo-starting pressure gradient，and measured liquid permeability.According to the three parameters，the characterization of nonlinear percolation in tight oil reservoirs was established based on flow experiments. From the perspective of reservoir application，the proposed characterization model is more accurate than the Darcy model and the pseudo-starting pressure gradient model.
2021, 28(5):100-108.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.012
Abstract:
After long-term waterflooding development，anisotropic oil reservoirs often show uneven planar flooding and poor development effects. How to effectively adjust the well pattern is the key to redirection of waterflooding fluid flow，enhanced producing reserves，and balanced flooding development. The infill horizontal wells between diagonal oil wells with the inverted nine-point vertical well pattern are adopted，and the conformal transformation and the principle of mirror reflection of seepage mechanics are employed to create a seepage model of the injection-production pattern of diagonal infill horizontal wells. In addition，a method to evaluate the producing reserves capacity and effect of the injection-production well pattern is proposed. In light of the actual parameters of the oilfield，the law of producing reserves in the injection-production unit after horizontal well infill is analyzed in the reservoirs with anisotropic permeabilities. With regard to the effect of producing reserves and development conditions，the reasonable length and development system of diagonal infill horizontal wells between wells in anisotropic reservoirs have been determined. The results show that the horizontal well infill mode has good adaptability in the reservoirs with anisotropic permeabilities；the reasonable horizontal well infill length is about 0.5 times the diagonal interwell length of the original well pattern.
After long-term waterflooding development，anisotropic oil reservoirs often show uneven planar flooding and poor development effects. How to effectively adjust the well pattern is the key to redirection of waterflooding fluid flow，enhanced producing reserves，and balanced flooding development. The infill horizontal wells between diagonal oil wells with the inverted nine-point vertical well pattern are adopted，and the conformal transformation and the principle of mirror reflection of seepage mechanics are employed to create a seepage model of the injection-production pattern of diagonal infill horizontal wells. In addition，a method to evaluate the producing reserves capacity and effect of the injection-production well pattern is proposed. In light of the actual parameters of the oilfield，the law of producing reserves in the injection-production unit after horizontal well infill is analyzed in the reservoirs with anisotropic permeabilities. With regard to the effect of producing reserves and development conditions，the reasonable length and development system of diagonal infill horizontal wells between wells in anisotropic reservoirs have been determined. The results show that the horizontal well infill mode has good adaptability in the reservoirs with anisotropic permeabilities；the reasonable horizontal well infill length is about 0.5 times the diagonal interwell length of the original well pattern.
2021, 28(5):109-115.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.013
Abstract:
A pilot test of the layer and well pattern interchange was carried out in Ng3-4 strata in the north of the west area of Gudao Oilfield. The layer and well pattern interchange altered the fluid flow direction and increased the swept volume.After the layer and well pattern interchange，the marked results of development and adjustment were achieved in the block，but the results varied greatly between individual wells. The Tanimoto coefficient was used to calculate the vector similarity between the fields of two discriminant parameters，i.e. the displacement pressure gradient and the water-oil seepage velocity ratio，and the water consumption control index was introduced to evaluate the response mechanism of the variable streamline. According to the response characteristics of oil wells，the responses were summarized into immediate response，delayed response，repeated response and no response. The research results of the response mechanism demonstrate that the streamline position of the existing strata where oil wells are located in and the differential distribution of oil and water in the well area directly affect the production status of remaining oil and the control degree of the high water consumption zones through the oil wells after the layer and well pattern interchange. As a result，the production of the oil wells is influenced after the layer and well pattern interchange.
A pilot test of the layer and well pattern interchange was carried out in Ng3-4 strata in the north of the west area of Gudao Oilfield. The layer and well pattern interchange altered the fluid flow direction and increased the swept volume.After the layer and well pattern interchange，the marked results of development and adjustment were achieved in the block，but the results varied greatly between individual wells. The Tanimoto coefficient was used to calculate the vector similarity between the fields of two discriminant parameters，i.e. the displacement pressure gradient and the water-oil seepage velocity ratio，and the water consumption control index was introduced to evaluate the response mechanism of the variable streamline. According to the response characteristics of oil wells，the responses were summarized into immediate response，delayed response，repeated response and no response. The research results of the response mechanism demonstrate that the streamline position of the existing strata where oil wells are located in and the differential distribution of oil and water in the well area directly affect the production status of remaining oil and the control degree of the high water consumption zones through the oil wells after the layer and well pattern interchange. As a result，the production of the oil wells is influenced after the layer and well pattern interchange.
2021, 28(5):116-123.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.014
Abstract:
The complex fracture networks produced by hydraulic fracturing are crucial to the higher gas/oil production capacity from tight reservoirs. In this study，the physical simulation experiments on hydraulic fracturing were conducted by a true triaxial test system with the oil shale samples from the Triassic Yanchang Formation，and 3D CT reconstruction was performed on the fracture networks of the samples before and after fracturing. The complexity of the fracture networks were quantitatively described on the basis of the fractal theory and the digital image processing technology. The results indicate that the change rate of the fractal dimension of fracture networks are 0.45%-3.64% before and after fracturing based on the cube covering method. A negative correlation is always between the change rates of the fractal dimension and the horizontal stress ratio. Moreover，the change rate of the fractal dimension grows first and then declines as the fracturing fluid viscosity varies，and it reaches the maximum at the fluid viscosity of 5.0 mPa·s. A low horizontal stress ratio and a low fluid viscosity can intensify the complicated morphology of fracture networks，while over low or high fracturing fluid viscosity restrains the formation of fracture networks.
The complex fracture networks produced by hydraulic fracturing are crucial to the higher gas/oil production capacity from tight reservoirs. In this study，the physical simulation experiments on hydraulic fracturing were conducted by a true triaxial test system with the oil shale samples from the Triassic Yanchang Formation，and 3D CT reconstruction was performed on the fracture networks of the samples before and after fracturing. The complexity of the fracture networks were quantitatively described on the basis of the fractal theory and the digital image processing technology. The results indicate that the change rate of the fractal dimension of fracture networks are 0.45%-3.64% before and after fracturing based on the cube covering method. A negative correlation is always between the change rates of the fractal dimension and the horizontal stress ratio. Moreover，the change rate of the fractal dimension grows first and then declines as the fracturing fluid viscosity varies，and it reaches the maximum at the fluid viscosity of 5.0 mPa·s. A low horizontal stress ratio and a low fluid viscosity can intensify the complicated morphology of fracture networks，while over low or high fracturing fluid viscosity restrains the formation of fracture networks.
2021, 28(5):124-130.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.015
Abstract:
The reservoir，wellbore and pipe network are major links in a development and production system of oil and gas fields. Traditional numerical simulation methods mainly simulate the fluid flow in the reservoir，while the coupling simulation based on reservoir-wellbore-pipe network integration reflects fluid supply capacity of the reservoir，lifting capacity of the wellbore，and gathering and transportation capacity of the pipe network at the same time. It is of great significance to accurate prediction of the production situation and the whole process optimization of a production system. By studying the construction method of a wellbore-pipe network model and the adaptability of multiphase pipe flow correlations，we realized the flow simulation and flow assurance simulation in the wellbore and the pipe network. An integrated model was built through node links，and the flow relationships between key nodes were coupled to develop a coupling simulation method based on reservoir-wellbore-pipe network integration，enabling the whole process simulation of oil and gas field development. In the West A Block of Chengdao Oilfield，the production system，proration，injection allocation，and other aspects were optimized according to the actual production demand and constraints of offshore oil fields. In addition，the whole process optimization based on the integration model maximized the production benefit of the oil and gas field development system.
The reservoir，wellbore and pipe network are major links in a development and production system of oil and gas fields. Traditional numerical simulation methods mainly simulate the fluid flow in the reservoir，while the coupling simulation based on reservoir-wellbore-pipe network integration reflects fluid supply capacity of the reservoir，lifting capacity of the wellbore，and gathering and transportation capacity of the pipe network at the same time. It is of great significance to accurate prediction of the production situation and the whole process optimization of a production system. By studying the construction method of a wellbore-pipe network model and the adaptability of multiphase pipe flow correlations，we realized the flow simulation and flow assurance simulation in the wellbore and the pipe network. An integrated model was built through node links，and the flow relationships between key nodes were coupled to develop a coupling simulation method based on reservoir-wellbore-pipe network integration，enabling the whole process simulation of oil and gas field development. In the West A Block of Chengdao Oilfield，the production system，proration，injection allocation，and other aspects were optimized according to the actual production demand and constraints of offshore oil fields. In addition，the whole process optimization based on the integration model maximized the production benefit of the oil and gas field development system.
2021, 28(5):131-136.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.016
Abstract:
During CO2 flooding in low permeability reservoirs，solid-phase deposition may damage the reservoirs. The current measurement methods cannot quantitatively characterize the solid-phase deposition in a direct and accurate manner.With this regard，a new microscopic visualized experimental method for solid-phase deposition was proposed for comparative analysis of solid-phase deposition between different development modes，and the experiment was performed on solidphase deposition with different CO2 injection rates and injection pressure levels. The results show that the solid-phase deposition is mainly composed of colloid and asphaltene. Specific threshold pressure is observed in the solid-phase deposition of CO2 flooding，and the deposition area is mainly located in the miscible area. The deposition law shows a trend of slowly increasing，rapidly rising，and gradually slowing down，and the precipitation and dissolution process of solid-phase deposition is reversible to a certain extent. According to the experimental results，the injection pressure level for CO2 flooding should be lower than the threshold pressure of solid-phase deposition to inhibit it significantly and reduce the damage of solid-phase deposition to the reservoirs during CO2 flooding. The field applications of experimental results effectively reduce the damage to the reservoirs and increase the potential for sustainable development of the oilfield.
During CO2 flooding in low permeability reservoirs，solid-phase deposition may damage the reservoirs. The current measurement methods cannot quantitatively characterize the solid-phase deposition in a direct and accurate manner.With this regard，a new microscopic visualized experimental method for solid-phase deposition was proposed for comparative analysis of solid-phase deposition between different development modes，and the experiment was performed on solidphase deposition with different CO2 injection rates and injection pressure levels. The results show that the solid-phase deposition is mainly composed of colloid and asphaltene. Specific threshold pressure is observed in the solid-phase deposition of CO2 flooding，and the deposition area is mainly located in the miscible area. The deposition law shows a trend of slowly increasing，rapidly rising，and gradually slowing down，and the precipitation and dissolution process of solid-phase deposition is reversible to a certain extent. According to the experimental results，the injection pressure level for CO2 flooding should be lower than the threshold pressure of solid-phase deposition to inhibit it significantly and reduce the damage of solid-phase deposition to the reservoirs during CO2 flooding. The field applications of experimental results effectively reduce the damage to the reservoirs and increase the potential for sustainable development of the oilfield.
2021, 28(5):137-142.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.05.017
Abstract:
The imbibition oil recovery uses the capillary pressure of low-permeability reservoirs to enhance the oil-water displacement between matrices and fractures，thereby effectively improving the recovery factor. At present，there is a lack of systematic studies on the basic laws of imbibition oil recovery，and its main controlling factors are not clear. A high-temperature and high-pressure imbibition instrument was adopted，with the imbibition recovery factor as an indicator，to systematically evaluate the influence of seven parameters of three types，including reservoir characteristics，fluid properties，and boundary conditions，on the spontaneous imbibition of cores. The weight of each influencing factor was analyzed by grey relational analysis. The results show that the imbibition recovery of low-permeability reservoirs decreases with the increase in core permeability and length. Lower oil-water interfacial tension and stronger hydrophilicity of rock surfaces lead to a higher imbibition recovery. A higher temperature results in lower viscosity of crude oil and stronger imbibition effect，with the imbibition recovery on the increase. The imbibition recovery of cores open at both ends is higher than that of cores open on the side. More fractures bring about a higher imbibition recovery. The weight of each influencing factor in descending order is rock wettability，oil-water interfacial tension，number of fractures，reservoir temperature，end-face opening position，core permeability，and core length. Among them，oil-water interfacial tension，rock wettability，and number of fractures are the main controlling factors of imbibition oil recovery as their correlations with imbibition recovery are all above 0.95.
The imbibition oil recovery uses the capillary pressure of low-permeability reservoirs to enhance the oil-water displacement between matrices and fractures，thereby effectively improving the recovery factor. At present，there is a lack of systematic studies on the basic laws of imbibition oil recovery，and its main controlling factors are not clear. A high-temperature and high-pressure imbibition instrument was adopted，with the imbibition recovery factor as an indicator，to systematically evaluate the influence of seven parameters of three types，including reservoir characteristics，fluid properties，and boundary conditions，on the spontaneous imbibition of cores. The weight of each influencing factor was analyzed by grey relational analysis. The results show that the imbibition recovery of low-permeability reservoirs decreases with the increase in core permeability and length. Lower oil-water interfacial tension and stronger hydrophilicity of rock surfaces lead to a higher imbibition recovery. A higher temperature results in lower viscosity of crude oil and stronger imbibition effect，with the imbibition recovery on the increase. The imbibition recovery of cores open at both ends is higher than that of cores open on the side. More fractures bring about a higher imbibition recovery. The weight of each influencing factor in descending order is rock wettability，oil-water interfacial tension，number of fractures，reservoir temperature，end-face opening position，core permeability，and core length. Among them，oil-water interfacial tension，rock wettability，and number of fractures are the main controlling factors of imbibition oil recovery as their correlations with imbibition recovery are all above 0.95.
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