Volume 30,Issue 5,2023 Table of Contents
2023, 30(5):1-11.
DOI: 10.13673/j.pgre.202205033
Abstract:
In order to understand the paleo-karst cave genesis and fracture-cavity structures in Well TH10421 Block，which has high cumulative production in the thick coverage area of Upper Ordovician in Tahe Oilfield，the distribution characteristics of the surface water system，fracture characteristics，and spatial structure of caves in the area are clarified through paleo-geomorphic restoration，seismic attribute extraction，and fracture-cavity body carving. The fracture-cavity system in Well TH10421 Block is defined as a maze-type cave system caused by flood for the first time. According to the reservoir’s dynamic production characteristics，the connection relationship between fracture-cavity bodies of the maze-type cave system is analyzed. The results suggest that the conjugate secondary strike-slip fault network is developed in Well TH10421 Block，and gridded faults provide an initial dissolution channel for maze-type caves. In episode Ⅱ of the middle Caledonian movement，surface karst lakes provide a high-flow karst water supply， and the karst water infiltrates into Yijianfang Formation along the gridded faults to form maze-type caves. The dissolution of karst water along the faults has the characteristics of simultaneity and selectivity，which results in great differences in the dissolution degree of maze-type caves in Well TH10421 Block in terms of different fault directions and depths. The connectivity of the pipeline in the shallow cave in the east of maze-type caves is excellent，while that in the west of maze-type caves is poor，and the connectivity of the deep fracture-cavity is great.
In order to understand the paleo-karst cave genesis and fracture-cavity structures in Well TH10421 Block，which has high cumulative production in the thick coverage area of Upper Ordovician in Tahe Oilfield，the distribution characteristics of the surface water system，fracture characteristics，and spatial structure of caves in the area are clarified through paleo-geomorphic restoration，seismic attribute extraction，and fracture-cavity body carving. The fracture-cavity system in Well TH10421 Block is defined as a maze-type cave system caused by flood for the first time. According to the reservoir’s dynamic production characteristics，the connection relationship between fracture-cavity bodies of the maze-type cave system is analyzed. The results suggest that the conjugate secondary strike-slip fault network is developed in Well TH10421 Block，and gridded faults provide an initial dissolution channel for maze-type caves. In episode Ⅱ of the middle Caledonian movement，surface karst lakes provide a high-flow karst water supply， and the karst water infiltrates into Yijianfang Formation along the gridded faults to form maze-type caves. The dissolution of karst water along the faults has the characteristics of simultaneity and selectivity，which results in great differences in the dissolution degree of maze-type caves in Well TH10421 Block in terms of different fault directions and depths. The connectivity of the pipeline in the shallow cave in the east of maze-type caves is excellent，while that in the west of maze-type caves is poor，and the connectivity of the deep fracture-cavity is great.
2023, 30(5):12-21.
DOI: 10.13673/j.pgre.202206025
Abstract:
The dissolution and transformation of feldspar particles in acidic fluid environments are the important cause of the formation and evolution of secondary pores in sandstones. Such diagenesis has an important influence on the formation，evolution，and distribution of favorable reservoirs in deep oil-bearing basins. Authigenic kaolinite is the main diagenetic product in the transformation process of feldspar particles in acidic fluid environments. Its genetic mechanism and occurrence affect the types of reservoir pores formed during this process. Taking Shahejie Formation in Dongying Sag as an example，this paper used numerical simulation method based on the thermodynamics to clarify the formation process of authigenic kaolinite under different formation temperatures. In addition，it employed means such as cast thin sections and scanning electron microscopy to reveal the genetic mechanisms and feldspar transformation process in different diagenetic environments. The results show that when the formation temperature is higher than 120 ℃ ，the autogenic kaolinite in the reservoirs is the transformation product of gibbsite and feldspar. The secondary pores formed during this process are intercrystalline micropores of kaolinite，and the pore structure is the micropore-fine throat. When the formation temperature is lower than 120 ℃，the authigenic kaolinite in the reservoirs is the product of pore fluid precipitation or the combination of gibbsite and silica-containing particles. The secondary pores formed during this process are macropores resulting from feldspar particle dissolution，and the pore structure is the macropore-coarse throat.
The dissolution and transformation of feldspar particles in acidic fluid environments are the important cause of the formation and evolution of secondary pores in sandstones. Such diagenesis has an important influence on the formation，evolution，and distribution of favorable reservoirs in deep oil-bearing basins. Authigenic kaolinite is the main diagenetic product in the transformation process of feldspar particles in acidic fluid environments. Its genetic mechanism and occurrence affect the types of reservoir pores formed during this process. Taking Shahejie Formation in Dongying Sag as an example，this paper used numerical simulation method based on the thermodynamics to clarify the formation process of authigenic kaolinite under different formation temperatures. In addition，it employed means such as cast thin sections and scanning electron microscopy to reveal the genetic mechanisms and feldspar transformation process in different diagenetic environments. The results show that when the formation temperature is higher than 120 ℃ ，the autogenic kaolinite in the reservoirs is the transformation product of gibbsite and feldspar. The secondary pores formed during this process are intercrystalline micropores of kaolinite，and the pore structure is the micropore-fine throat. When the formation temperature is lower than 120 ℃，the authigenic kaolinite in the reservoirs is the product of pore fluid precipitation or the combination of gibbsite and silica-containing particles. The secondary pores formed during this process are macropores resulting from feldspar particle dissolution，and the pore structure is the macropore-coarse throat.
2023, 30(5):22-30.
DOI: 10.13673/j.pgre.202111028
Abstract:
The laminated argillaceous limestone facies shale in the continental shale reservoirs of Jiyang Depression has good physical properties of reservoirs，but the mechanical properties of reservoirs have strong heterogeneity due to the dense laminae，which leads to the significant size effect of its mechanical parameters. The cores of the laminated argillaceous limestone-facies shale in Boxing Sag of Shengli Oilfield were taken as an example for systematic research on the mechanical properties of cores and the size effect of hydraulic fractures by three-dimensional finite-element numerical simulation. The results show that when the core size is less than 500 mm，the uniaxial compressive strength and modulus of elasticity have a significant size effect，and they have a negative exponential relationship with the core size under different confining pressures. The breakdown pressure of hydraulic fracturing decrease with the increase in the unit size. In Boxing Sag，when the unit size is 1.5 m，the breakdown pressure and stimulated reservoir volume（SRV）obtained by numerical calculation are closer to those of real formations. It is suggested that the unit grid with a unit size of less than 1.5 m should be used for simulation design under satisfied computational efficiency.
The laminated argillaceous limestone facies shale in the continental shale reservoirs of Jiyang Depression has good physical properties of reservoirs，but the mechanical properties of reservoirs have strong heterogeneity due to the dense laminae，which leads to the significant size effect of its mechanical parameters. The cores of the laminated argillaceous limestone-facies shale in Boxing Sag of Shengli Oilfield were taken as an example for systematic research on the mechanical properties of cores and the size effect of hydraulic fractures by three-dimensional finite-element numerical simulation. The results show that when the core size is less than 500 mm，the uniaxial compressive strength and modulus of elasticity have a significant size effect，and they have a negative exponential relationship with the core size under different confining pressures. The breakdown pressure of hydraulic fracturing decrease with the increase in the unit size. In Boxing Sag，when the unit size is 1.5 m，the breakdown pressure and stimulated reservoir volume（SRV）obtained by numerical calculation are closer to those of real formations. It is suggested that the unit grid with a unit size of less than 1.5 m should be used for simulation design under satisfied computational efficiency.
2023, 30(5):31-40.
DOI: 10.13673/j.pgre.202204016
Abstract:
Shale permeability and its distribution are vital to key projects in the energy and environment fields，such as shale oil and gas development，reserves estimate of conventional oil and gas reservoirs，sealing ability of caprock in underground gas storage and CO2 geological storage，geological disposal of nuclear waste，and reinjection safety of produced water from gas fields. The research on the characteristics of shale permeability is of extensive theoretical and engineering practical significance. Therefore，this study systematically summarized the research progress in the measurement methods and influencing factors of shale permeability. The analysis indicates that the shale permeability ranges from micro-darcy to nano-darcy，which is commonly measured by the steadystate method and pulse-decay method. The factors affecting shale permeability include but are not limited to the fluid type and saturation，mineral compositions，pore pressure，effective stress，experimental temperature，anisotropy，and fluid-rock chemical dissolution and precipitation interactions. The difference in fluid-rock interaction and the change in effective flow radii of pores under different conditions are the fundamental reasons for the permeability variation.
Shale permeability and its distribution are vital to key projects in the energy and environment fields，such as shale oil and gas development，reserves estimate of conventional oil and gas reservoirs，sealing ability of caprock in underground gas storage and CO2 geological storage，geological disposal of nuclear waste，and reinjection safety of produced water from gas fields. The research on the characteristics of shale permeability is of extensive theoretical and engineering practical significance. Therefore，this study systematically summarized the research progress in the measurement methods and influencing factors of shale permeability. The analysis indicates that the shale permeability ranges from micro-darcy to nano-darcy，which is commonly measured by the steadystate method and pulse-decay method. The factors affecting shale permeability include but are not limited to the fluid type and saturation，mineral compositions，pore pressure，effective stress，experimental temperature，anisotropy，and fluid-rock chemical dissolution and precipitation interactions. The difference in fluid-rock interaction and the change in effective flow radii of pores under different conditions are the fundamental reasons for the permeability variation.
2023, 30(5):41-48.
DOI: 10.13673/j.pgre.202210005
Abstract:
It is difficult to predict fractures quantitatively due to the different fracture genesis and complex development laws of fractures in offshore fractured oil and gas reservoirs with different lithologies.Techniques for quantitative characterization of fractured reservoirs with different lithology were proposed by many research methods based on fracture development characteristics of reservoirs：① Quantitative characterization technique of fractured glutenite reservoirs：the sedimentary evolution simulation and target simulation are combined to predict the distribution range of intra-gravel fractures and quantitatively characterize the micro-fractures of glutenite fractured reservoirs. ② Quantitative characterization technique of fractured metamorphic rock reservoirs：an unstructured mesh subdivision was introduced in modeling to quantitatively characterize the large，medium and small fractures and their coupling relationships with matrix. ③ Quantitative characterization technique of carbonate reservoirs：the dual-mode iteration technique was used to quantitatively characterize the distribution of microfractures on the base of the multi-information and multimeans reservoir evaluation. The application of these techniques in three oil and gas fields in Bohai Sea shows that these characterization techniques provide a solid quantitative basis in the study on development schemes，with numerically simulated fitting accuracy improved by about 20%. These techniques have successfully guided the efficient implementation of more than 10 development wells during oilfield adjustment，providing a reference for efficient development of similar fractured reservoirs.
It is difficult to predict fractures quantitatively due to the different fracture genesis and complex development laws of fractures in offshore fractured oil and gas reservoirs with different lithologies.Techniques for quantitative characterization of fractured reservoirs with different lithology were proposed by many research methods based on fracture development characteristics of reservoirs：① Quantitative characterization technique of fractured glutenite reservoirs：the sedimentary evolution simulation and target simulation are combined to predict the distribution range of intra-gravel fractures and quantitatively characterize the micro-fractures of glutenite fractured reservoirs. ② Quantitative characterization technique of fractured metamorphic rock reservoirs：an unstructured mesh subdivision was introduced in modeling to quantitatively characterize the large，medium and small fractures and their coupling relationships with matrix. ③ Quantitative characterization technique of carbonate reservoirs：the dual-mode iteration technique was used to quantitatively characterize the distribution of microfractures on the base of the multi-information and multimeans reservoir evaluation. The application of these techniques in three oil and gas fields in Bohai Sea shows that these characterization techniques provide a solid quantitative basis in the study on development schemes，with numerically simulated fitting accuracy improved by about 20%. These techniques have successfully guided the efficient implementation of more than 10 development wells during oilfield adjustment，providing a reference for efficient development of similar fractured reservoirs.
2023, 30(5):49-56.
DOI: 10.13673/j.pgre.202203010
Abstract:
The rock samples of the typical faults（zones）of Manasi River profile，Houxia profile，and Dabancheng profile were examined in terms of their mineralogical and geochemical components. On this basis，the geochemical distribution and differences in the rare earth elements were analyzed for the fault zone fillings of different trends，and the source and tectonic environment of the fillings of Yilin Heibiergen Fault Zone were studied and assessed. The results showed that the characteristics of the veins of fault zone fillings near Yilin Heibiergen Fault Zone in the study area are similar to those of the rare earth elements of whole rock，demonstrating the relative accumulation of light rare earth elements. The fillings of the nearly EW-trending fault zone came from the deep crust and formed relatively early，which were mainly at the convergence boundary of the plates and resulted from the hydrothermal process of hypo magma. The fillings of the NE-SW trending fault zone，formed relatively late，were developed at the convergence edge of plates and in the tectonic environment of intra-continental collisions，which were the results of shallow crust activities.
The rock samples of the typical faults（zones）of Manasi River profile，Houxia profile，and Dabancheng profile were examined in terms of their mineralogical and geochemical components. On this basis，the geochemical distribution and differences in the rare earth elements were analyzed for the fault zone fillings of different trends，and the source and tectonic environment of the fillings of Yilin Heibiergen Fault Zone were studied and assessed. The results showed that the characteristics of the veins of fault zone fillings near Yilin Heibiergen Fault Zone in the study area are similar to those of the rare earth elements of whole rock，demonstrating the relative accumulation of light rare earth elements. The fillings of the nearly EW-trending fault zone came from the deep crust and formed relatively early，which were mainly at the convergence boundary of the plates and resulted from the hydrothermal process of hypo magma. The fillings of the NE-SW trending fault zone，formed relatively late，were developed at the convergence edge of plates and in the tectonic environment of intra-continental collisions，which were the results of shallow crust activities.
2023, 30(5):57-62.
DOI: 10.13673/j.pgre.202211044
Abstract:
Quantitative study on oil generated overpressure is the key to calculating the dynamics of oil and gas reservoirs and determining the distribution of oil and gas. The existing calculation methods of oil generated overpressure are low in calculation accuracy and complex，which affect their rapid applications in exploration. In this study，according to the comprehensive analysis of hydrocarbon generation characteristics of type I organic matter，a new mathematical model of oil generated overpressure was established.The model was used to calculate the oil generated overpressure of Chang7 source rock in Xifeng Oilfield of Ordos Basin and analyze the influence of different parameters on the oil generated overpressure. The results show that the oil generated overpressure of Chang7 source rock in Xifeng Oilfield is 4.6-14.8 MPa，and the formation pressure is similar to the previous calculation results，which indicates that the model is highly reliable. The sensitivity analysis of rock parameters shows that the rock compressibility factor has the greatest influence on the oil generated overpressure，with a value of 99.056%，followed by the total organic carbon content， with a value of 0.342%. The influence of hydrocarbon generation factor and kerogen oil-generating conversion efficiency on the oil generated overpressure is 0.261% and 0.250%，respectively，and the porosity and formation pressure have a relatively small effect on the oil generated overpressure，which is 0.09% and 0.001%，respectively. The model also reveals that higher formation pressure is not conducive to oil generated overpressure，and higher formation pressure makes the oil generated overpressure smaller.
Quantitative study on oil generated overpressure is the key to calculating the dynamics of oil and gas reservoirs and determining the distribution of oil and gas. The existing calculation methods of oil generated overpressure are low in calculation accuracy and complex，which affect their rapid applications in exploration. In this study，according to the comprehensive analysis of hydrocarbon generation characteristics of type I organic matter，a new mathematical model of oil generated overpressure was established.The model was used to calculate the oil generated overpressure of Chang7 source rock in Xifeng Oilfield of Ordos Basin and analyze the influence of different parameters on the oil generated overpressure. The results show that the oil generated overpressure of Chang7 source rock in Xifeng Oilfield is 4.6-14.8 MPa，and the formation pressure is similar to the previous calculation results，which indicates that the model is highly reliable. The sensitivity analysis of rock parameters shows that the rock compressibility factor has the greatest influence on the oil generated overpressure，with a value of 99.056%，followed by the total organic carbon content， with a value of 0.342%. The influence of hydrocarbon generation factor and kerogen oil-generating conversion efficiency on the oil generated overpressure is 0.261% and 0.250%，respectively，and the porosity and formation pressure have a relatively small effect on the oil generated overpressure，which is 0.09% and 0.001%，respectively. The model also reveals that higher formation pressure is not conducive to oil generated overpressure，and higher formation pressure makes the oil generated overpressure smaller.
2023, 30(5):63-66.
DOI: 10.13673/j.pgre.202209004
Abstract:
For a new gas well， it is an important work to test the pressure drawdown curve of the bottom-hole flowing pressure under the condition of stable gas well production. The pressure drawdown curves of gas wells can be divided into the unsteady state stage， transition stage， and pseudosteady state stage. The unsteady state stage is also called the elastic one phase， and the pseudosteady state stage is called the elastic two phase. The former test data can be used to determine the effective permeability of gas reservoirs and the skin coefficient of gas wells； the latter test data are mainly used to evaluate the original gas in place controlled by a gas well. However， for tight and low permeability gas reservoirs， the production of a gas well after fracturing cannot remain stable and is decreasing. The elastic two phase method relationships of the pseudosteady stage of the pressure drawdown curves with a variable production which are expressed by pressure and pressure-squared respectively are proposed in this paper，and they can be used to evaluate the original gas in place of the volumetric gas reservoir. The practical application shows that these two methods are practical and effective， and the evaluation results are basically the same.
For a new gas well， it is an important work to test the pressure drawdown curve of the bottom-hole flowing pressure under the condition of stable gas well production. The pressure drawdown curves of gas wells can be divided into the unsteady state stage， transition stage， and pseudosteady state stage. The unsteady state stage is also called the elastic one phase， and the pseudosteady state stage is called the elastic two phase. The former test data can be used to determine the effective permeability of gas reservoirs and the skin coefficient of gas wells； the latter test data are mainly used to evaluate the original gas in place controlled by a gas well. However， for tight and low permeability gas reservoirs， the production of a gas well after fracturing cannot remain stable and is decreasing. The elastic two phase method relationships of the pseudosteady stage of the pressure drawdown curves with a variable production which are expressed by pressure and pressure-squared respectively are proposed in this paper，and they can be used to evaluate the original gas in place of the volumetric gas reservoir. The practical application shows that these two methods are practical and effective， and the evaluation results are basically the same.
2023, 30(5):67-75.
DOI: 10.13673/j.pgre.202304024
Abstract:
Unbalanced water flooding can easily occur due to the influence of reservoir heterogeneity and development measures. Based on the statistical method，the Christiansen uniformity coefficient is used to quantitatively evaluate the balanced water flooding degree during the development of multi-layer reservoirs. A mathematical model for optimizing multi-layer injection and production parameters is established to maximize balanced water flooding，and the covariance matrix adaptive intelligent evolution algorithm is used to solve the problem. A collaborative optimization method of injection and production parameters for multi-layer reservoirs based on water flooding is developed，and its reliability is verified by an example. The new method is applied to the typical well group of Shengtuo T142 reservoir in Shengli Oilfield. By comparing the results before and after the optimization of intelligent collaborative stratified injection and production parameter，it is found that the Christiansen uniformity coefficient by the original scheme is improved by 3.49%. The cumulative oil production is increased by 1.024 × 104m3 ，and the water cut is decreased by1.34%. The results show that this method can accurately control the production and injection allocation between layers，effectively improve the balanced water flooding between layers and wells，and realize the accurate matching between injection and production parameters and remaining oil distribution.
Unbalanced water flooding can easily occur due to the influence of reservoir heterogeneity and development measures. Based on the statistical method，the Christiansen uniformity coefficient is used to quantitatively evaluate the balanced water flooding degree during the development of multi-layer reservoirs. A mathematical model for optimizing multi-layer injection and production parameters is established to maximize balanced water flooding，and the covariance matrix adaptive intelligent evolution algorithm is used to solve the problem. A collaborative optimization method of injection and production parameters for multi-layer reservoirs based on water flooding is developed，and its reliability is verified by an example. The new method is applied to the typical well group of Shengtuo T142 reservoir in Shengli Oilfield. By comparing the results before and after the optimization of intelligent collaborative stratified injection and production parameter，it is found that the Christiansen uniformity coefficient by the original scheme is improved by 3.49%. The cumulative oil production is increased by 1.024 × 104m3 ，and the water cut is decreased by1.34%. The results show that this method can accurately control the production and injection allocation between layers，effectively improve the balanced water flooding between layers and wells，and realize the accurate matching between injection and production parameters and remaining oil distribution.
2023, 30(5):76-83.
DOI: 10.13673/j.cnki.cn37-1359/te.202209053
Abstract:
The fracture-cavity reservoirs in Tahe Oilfield are faced with prominent problems，such as unidirectional effects and gas channeling after nitrogen flooding. In order to effectively control gas channeling and expand the swept volume，a new reinforced foam system with high temperature resistance and high salt tolerance，namely a dual-crosslinked high polymer gel foam system is developed. In addition，reinforced foam with nitrogen flooding flooding tests are carried out in the eastern old area of Tahe Oilfield.Laboratory experiments and field tests show that the new reinforced foam system is synthesized by 0.3% mass concentration of anionic-nonionic/anionic composite synergistic foaming system and 0.7% mass concentration of polymer gel foam-stabilizing system.The aggregations of gel macromolecules undergo a secondary cross-linking on the liquid film of the foam，forming a dual-crosslinked high polymer gel foam system. The reinforced foam system can be strongly stable under the reservoir conditions with a temperature of 140 °C，a salinity of 240 g/L，and an oil saturation of 50%. It is suitable for the geological conditions of fracture-cavity reservoirs in Tahe Oilfield. The reinforced foam test with nitrogen flooding is carried out in 10 wells in Tahe Oilfield. Specifically，gas channeling is effectively controlled，and the swept volume is expanded in nine wells，with the production increasing significantly. Therefore，it is proved that the reinforced foam with nitrogen flooding technology is a feasible way to enhance oil recovery of fracture cavity reservoirs.
The fracture-cavity reservoirs in Tahe Oilfield are faced with prominent problems，such as unidirectional effects and gas channeling after nitrogen flooding. In order to effectively control gas channeling and expand the swept volume，a new reinforced foam system with high temperature resistance and high salt tolerance，namely a dual-crosslinked high polymer gel foam system is developed. In addition，reinforced foam with nitrogen flooding flooding tests are carried out in the eastern old area of Tahe Oilfield.Laboratory experiments and field tests show that the new reinforced foam system is synthesized by 0.3% mass concentration of anionic-nonionic/anionic composite synergistic foaming system and 0.7% mass concentration of polymer gel foam-stabilizing system.The aggregations of gel macromolecules undergo a secondary cross-linking on the liquid film of the foam，forming a dual-crosslinked high polymer gel foam system. The reinforced foam system can be strongly stable under the reservoir conditions with a temperature of 140 °C，a salinity of 240 g/L，and an oil saturation of 50%. It is suitable for the geological conditions of fracture-cavity reservoirs in Tahe Oilfield. The reinforced foam test with nitrogen flooding is carried out in 10 wells in Tahe Oilfield. Specifically，gas channeling is effectively controlled，and the swept volume is expanded in nine wells，with the production increasing significantly. Therefore，it is proved that the reinforced foam with nitrogen flooding technology is a feasible way to enhance oil recovery of fracture cavity reservoirs.
2023, 30(5):84-91.
DOI: 10.13673/j.pgre.202210001
Abstract:
Recently，breakthroughs have been made in the exploration and development of Jurassic lacustrine shale oil reservoirs in the central Sichuan Basin，whereas the overall output of shale oil wells is not enough to meet the requirements of commercial development.After the fracturing of shale oil wells，shut-in are generally adopted to use fracturing fluid to imbibe and displace crude oil in the formation. However，the range of imbibition and the key influencing factors of fracturing fluid into shale matrix pores during the shut-in period are still unclear. In this paper，a model of shale matrix fluid imbibition and invasion depth was built，which took into account fracturing fluid residue clogging，positive hydraulic pressure difference，capillary force，and flow pressure. The model was verified by the monitoring data of core NMR stratified T2 spectrum，and the average error is 14.17%. Example analysis shows that within 90 days of shut-in，the imbibition range of fracturing fluid into matrix pores is less than 0.72 m. Surface wetting modification（hydrophobic to hydrophilic）effectively improves the imbibition range of fracturing fluid，while the influence of oil-water interfacial tension is relatively weak. According to the relation curve between shut-in time and imbibition invasion depth，the recom‐mended shut-in time is about 40-50 days.
Recently，breakthroughs have been made in the exploration and development of Jurassic lacustrine shale oil reservoirs in the central Sichuan Basin，whereas the overall output of shale oil wells is not enough to meet the requirements of commercial development.After the fracturing of shale oil wells，shut-in are generally adopted to use fracturing fluid to imbibe and displace crude oil in the formation. However，the range of imbibition and the key influencing factors of fracturing fluid into shale matrix pores during the shut-in period are still unclear. In this paper，a model of shale matrix fluid imbibition and invasion depth was built，which took into account fracturing fluid residue clogging，positive hydraulic pressure difference，capillary force，and flow pressure. The model was verified by the monitoring data of core NMR stratified T2 spectrum，and the average error is 14.17%. Example analysis shows that within 90 days of shut-in，the imbibition range of fracturing fluid into matrix pores is less than 0.72 m. Surface wetting modification（hydrophobic to hydrophilic）effectively improves the imbibition range of fracturing fluid，while the influence of oil-water interfacial tension is relatively weak. According to the relation curve between shut-in time and imbibition invasion depth，the recom‐mended shut-in time is about 40-50 days.
2023, 30(5):92-99.
DOI: 10.13673/j.pgre.202209022
Abstract:
By investigating the research and application of microbial technology in shale oil and gas reservoir development in other countries， the principle， technology， and application of plugging removal technology by indigenous microorganisms in shale oil and gas reservoirs and DNA sequencing diagnosis technology in shale formation are introduced in detail. At the same time， the principle and research progress of enhanced shale oil and gas recovery and transformation of shale reservoir rock by microorganisms are analyzed. The results show that there are microorganisms in shale oil and gas reservoirs. Based on the degradation of macromolecular organic matter by reservoir microorganisms and the detection and analysis of specific microorganism DNA in reservoirs，the plugging removal technology by indigenous microorganisms in shale oil and gas reservoirs and DNA sequencing diagnosis technology in shale formation have been applied in the field， and excellent results have been obtained in improving shale oil and gas productivity and high-efficiency reservoir description. Based on the improvement of crude oil flow ability by microorganisms in reservoirs and that of reservoir rock properties， studies on enhanced shale oil and gas recovery and transformation of shale reservoir rock by microorganisms have shown a very good application prospect. At present， the development of shale oil and gas reservoirs in China is in the stage of rapid growth， so it is necessary to learn from the experience of foreign countries and explore microbial development technology in accordance with the characteristics of shale oil and gas in China.
By investigating the research and application of microbial technology in shale oil and gas reservoir development in other countries， the principle， technology， and application of plugging removal technology by indigenous microorganisms in shale oil and gas reservoirs and DNA sequencing diagnosis technology in shale formation are introduced in detail. At the same time， the principle and research progress of enhanced shale oil and gas recovery and transformation of shale reservoir rock by microorganisms are analyzed. The results show that there are microorganisms in shale oil and gas reservoirs. Based on the degradation of macromolecular organic matter by reservoir microorganisms and the detection and analysis of specific microorganism DNA in reservoirs，the plugging removal technology by indigenous microorganisms in shale oil and gas reservoirs and DNA sequencing diagnosis technology in shale formation have been applied in the field， and excellent results have been obtained in improving shale oil and gas productivity and high-efficiency reservoir description. Based on the improvement of crude oil flow ability by microorganisms in reservoirs and that of reservoir rock properties， studies on enhanced shale oil and gas recovery and transformation of shale reservoir rock by microorganisms have shown a very good application prospect. At present， the development of shale oil and gas reservoirs in China is in the stage of rapid growth， so it is necessary to learn from the experience of foreign countries and explore microbial development technology in accordance with the characteristics of shale oil and gas in China.
2023, 30(5):100-109.
DOI: 10.13673/j.pgre.202210027
Abstract:
In view of the shortcomings of the equal-diameter capillary bundle model，this paper theoretically derives the multi-segment imbibition formula of the variable-diameter capillary under the liquid-liquid system considering pressure difference and solidliquid wall effect by using the sectioning method. In addition，the paper studies the influence of changes in different capillary geometry and fluid properties on the imbibition-displacement of the variable-diameter capillaries and develops a random variable-diameter capillary bundle model through Python，so as to deduce calculation methods of the recovery and water cut based on this model. The results show that the increase in pressure differences leads to the decrease in the differences of the imbibition velocities between variable-diameter capillary segments，and the imbibition-displacement of the variable-diameter capillaries is directional. The recovery and water cut calculated based on the random variable-diameter capillary bundle model are in good agreement with the real core displacement data from experiments，and the contribution of the imbibition effects to the total recovery reaches 19.97%.
In view of the shortcomings of the equal-diameter capillary bundle model，this paper theoretically derives the multi-segment imbibition formula of the variable-diameter capillary under the liquid-liquid system considering pressure difference and solidliquid wall effect by using the sectioning method. In addition，the paper studies the influence of changes in different capillary geometry and fluid properties on the imbibition-displacement of the variable-diameter capillaries and develops a random variable-diameter capillary bundle model through Python，so as to deduce calculation methods of the recovery and water cut based on this model. The results show that the increase in pressure differences leads to the decrease in the differences of the imbibition velocities between variable-diameter capillary segments，and the imbibition-displacement of the variable-diameter capillaries is directional. The recovery and water cut calculated based on the random variable-diameter capillary bundle model are in good agreement with the real core displacement data from experiments，and the contribution of the imbibition effects to the total recovery reaches 19.97%.
2023, 30(5):110-118.
DOI: 10.13673/j.pgre.202208031
Abstract:
Changing the wettability of reservoirs near condensate gas wells is an effective method to reduce condensate plugging. The crystal structures，surface functional groups，surface morphology，and particle sizes of Fe 3 O 4-PT nanoparticles are characterized by the coprecipitation method based on the synthetic polythiophene encapsulated Fe 3 O4 nanoparticles（Fe 3O 4-PT）. Through experiments of static wetting contact angle measurement，static imbibition，single-phase flow，and two-phase flow，this paper studies the changes in rock wettability，water oil imbibition，single-phase flow before and after nanoparticle treatment，and the change characteristics of gas-oil two-phase relative permeability curves. Additionally，the feasibility of Fe 3 O 4-PT nanoparticles to improve reverse condensate plugging is comprehensively evaluated. The experimental results show that the polythiophene coating will not change the original structure of Fe 3 O4 nanoparticles but enhance the original diffraction peak intensity. The average particle size of Fe 3 O 4-PT nanoparticles is 17.2 nm. After nanofluid treatment，the wettability of rock changes from liquid wetting to gas wetting or neutral wetting. The contact angle between water and condensate on the rock surface first increases and then decreases with the increasing nanoparticle concentration，and increases with the rising temperature. However，it is little affected by pressure and decreases with the increase in salt concentration. The water and condensate imbibition volumes decrease 69.2% and 64.3% respectively. The maximum pressure drops in single-phase water drive or oil drive are reduced by 28.9% and 46.7% respectively. In two-phase flow，the gas-oil two-phase co-permeability areas widen and the isotonic points shift to the upper left. The irreducible water saturation and remaining oil saturation decrease，and the two-phase relative permeability increases significantly. Fe 3 O 4-PT nanoparticles can reduce the imbibition efficiency and flow resistance of water and oil，increase condensate fluidity，and improve gas and oil production，thus effectively improving reverse condensate damage.
Changing the wettability of reservoirs near condensate gas wells is an effective method to reduce condensate plugging. The crystal structures，surface functional groups，surface morphology，and particle sizes of Fe 3 O 4-PT nanoparticles are characterized by the coprecipitation method based on the synthetic polythiophene encapsulated Fe 3 O4 nanoparticles（Fe 3O 4-PT）. Through experiments of static wetting contact angle measurement，static imbibition，single-phase flow，and two-phase flow，this paper studies the changes in rock wettability，water oil imbibition，single-phase flow before and after nanoparticle treatment，and the change characteristics of gas-oil two-phase relative permeability curves. Additionally，the feasibility of Fe 3 O 4-PT nanoparticles to improve reverse condensate plugging is comprehensively evaluated. The experimental results show that the polythiophene coating will not change the original structure of Fe 3 O4 nanoparticles but enhance the original diffraction peak intensity. The average particle size of Fe 3 O 4-PT nanoparticles is 17.2 nm. After nanofluid treatment，the wettability of rock changes from liquid wetting to gas wetting or neutral wetting. The contact angle between water and condensate on the rock surface first increases and then decreases with the increasing nanoparticle concentration，and increases with the rising temperature. However，it is little affected by pressure and decreases with the increase in salt concentration. The water and condensate imbibition volumes decrease 69.2% and 64.3% respectively. The maximum pressure drops in single-phase water drive or oil drive are reduced by 28.9% and 46.7% respectively. In two-phase flow，the gas-oil two-phase co-permeability areas widen and the isotonic points shift to the upper left. The irreducible water saturation and remaining oil saturation decrease，and the two-phase relative permeability increases significantly. Fe 3 O 4-PT nanoparticles can reduce the imbibition efficiency and flow resistance of water and oil，increase condensate fluidity，and improve gas and oil production，thus effectively improving reverse condensate damage.
2023, 30(5):119-129.
DOI: 10.13673/j.pgre.202212024
Abstract:
In the later stage of thermal composite recovery of heavy oil，although particle plugging and adjustment operations have obvious effects on further enhancing oil recovery，the influence of the thermal composite fluid remaining in the reservoir on the settling characteristics of plugging agent particles is still unclear，which limits the application of particle suspension systems in this stage. Therefore，based on the particle settling velocity theory，the basic physical properties of the particle suspension system and the inherent laws of the particle settling velocity are studied. Through the particle suspension experiment and Zeta potential experiment，the settling characteristics and mechanism of suspended particles under different factors are analyzed. The results show that a larger ratio of the particle size to the pore diameter indicates greater particle settling velocity；when pH = 5 or pH = 7，the stability of the particle suspension system is better；when pH = 9，the particle suspension system produces obvious coagulation and sedimentation phenomenon；anionic or nonionic surfactants have little effect on the stability of the particle suspension system，while cationic surfactants and particle suspension system produce flocculation. However，as the pH value decreases，the flocculation weakens，and when the pH value is 3，no flocculation occurs. Therefore，choosing a suitable particle suspension system is of great significance to the success or failure of deep plugging and adjustment operations in the later stage of thermal composite recovery of heavy oil.
In the later stage of thermal composite recovery of heavy oil，although particle plugging and adjustment operations have obvious effects on further enhancing oil recovery，the influence of the thermal composite fluid remaining in the reservoir on the settling characteristics of plugging agent particles is still unclear，which limits the application of particle suspension systems in this stage. Therefore，based on the particle settling velocity theory，the basic physical properties of the particle suspension system and the inherent laws of the particle settling velocity are studied. Through the particle suspension experiment and Zeta potential experiment，the settling characteristics and mechanism of suspended particles under different factors are analyzed. The results show that a larger ratio of the particle size to the pore diameter indicates greater particle settling velocity；when pH = 5 or pH = 7，the stability of the particle suspension system is better；when pH = 9，the particle suspension system produces obvious coagulation and sedimentation phenomenon；anionic or nonionic surfactants have little effect on the stability of the particle suspension system，while cationic surfactants and particle suspension system produce flocculation. However，as the pH value decreases，the flocculation weakens，and when the pH value is 3，no flocculation occurs. Therefore，choosing a suitable particle suspension system is of great significance to the success or failure of deep plugging and adjustment operations in the later stage of thermal composite recovery of heavy oil.
16 A new simulation method to study transport mechanism of water-gas dispersion system in porous media
2023, 30(5):130-138.
DOI: 10.13673/j.pgre.202207012
Abstract:
The water-gas dispersion system can effectively change flow channels of formation oil，inhibit the channeling of displacement fluid，expand the swept volume of the water-gas dispersion system in reservoirs，and enhance the producing effect of the remaining oil. Since it is difficult to directly observe the flow of the water-gas dispersion system in porous media，there are few studies on the transport mechanism of the water-gas dispersion system in porous media. The author proposes a new simulation method to study the transport of the water-gas dispersion system in porous media. The level set method and the gas-liquid two-phase flow are adopted，and the coupled numerical calculation software COMSOL Multiphysics is employed for research. The mechanisms of the Jamin effect，coalescence，and division of the water-gas dispersion system in the pore throat are simulated and studied. The influencing factors of dynamic pressures during the transport of the water-gas dispersion system are discussed，and the morphological changes of the dispersed-phase bubble during the coalescence process are analyzed. The dynamic characteristics of the water-gas dispersion system during division in the pore throat are studied. The result shows that numerical simulation can intuitively reflect the transport mechanism of the water-gas dispersion system in the porous media.
The water-gas dispersion system can effectively change flow channels of formation oil，inhibit the channeling of displacement fluid，expand the swept volume of the water-gas dispersion system in reservoirs，and enhance the producing effect of the remaining oil. Since it is difficult to directly observe the flow of the water-gas dispersion system in porous media，there are few studies on the transport mechanism of the water-gas dispersion system in porous media. The author proposes a new simulation method to study the transport of the water-gas dispersion system in porous media. The level set method and the gas-liquid two-phase flow are adopted，and the coupled numerical calculation software COMSOL Multiphysics is employed for research. The mechanisms of the Jamin effect，coalescence，and division of the water-gas dispersion system in the pore throat are simulated and studied. The influencing factors of dynamic pressures during the transport of the water-gas dispersion system are discussed，and the morphological changes of the dispersed-phase bubble during the coalescence process are analyzed. The dynamic characteristics of the water-gas dispersion system during division in the pore throat are studied. The result shows that numerical simulation can intuitively reflect the transport mechanism of the water-gas dispersion system in the porous media.
2023, 30(5):139-146.
DOI: 10.13673/j.pgre.202211036
Abstract:
The average formation pressure is a significant indicator of reservoir development and the foundation for reservoir capacity analysis and dynamic evaluation， which reflects the dynamic aspects of the reservoir development process. However， the conventional shut-in method of measuring the average formation pressure affects production and is inefficient. Therefore， how to obtain the average formation pressure changing with the reservoir production conveniently and quickly is of great significance for the whole reservoir. The conventional method of calculating the average formation pressure does not consider the water influx because the reservoir bottoms with both gas cap and bottom water are connected to the strong water body. Thus， this method is no longer suitable for the reservoirs with gas cap and bottom water. Considering the characteristics of the reservoirs with gas cap and bottom water，this study proposes a new water influx calculation method，namely the fitting deficit volume method to predict water intrusion， which is combined with the material balance method and the function of average formation pressure is established. By solving this function， the average formation pressure in the production process can be obtained. The comparison with the numerical simulation results shows that the relative deviation between the average formation pressure calculated by this method and the numerical simulation is small，only 0.054%. The findings demonstrate that the method does not require a shut-in of the wells， has no effects on production，and just calls for readily available dynamic and static information. It is simple to use and has a high degree of accuracy. It can be concluded that the method can obtain the average formation pressure economically and efficiently. Based on the average formation pressure， the drive index of the reservoir and the phase recovery can be calculated， which provides an important basis for the subsequent development of the reservoir.
The average formation pressure is a significant indicator of reservoir development and the foundation for reservoir capacity analysis and dynamic evaluation， which reflects the dynamic aspects of the reservoir development process. However， the conventional shut-in method of measuring the average formation pressure affects production and is inefficient. Therefore， how to obtain the average formation pressure changing with the reservoir production conveniently and quickly is of great significance for the whole reservoir. The conventional method of calculating the average formation pressure does not consider the water influx because the reservoir bottoms with both gas cap and bottom water are connected to the strong water body. Thus， this method is no longer suitable for the reservoirs with gas cap and bottom water. Considering the characteristics of the reservoirs with gas cap and bottom water，this study proposes a new water influx calculation method，namely the fitting deficit volume method to predict water intrusion， which is combined with the material balance method and the function of average formation pressure is established. By solving this function， the average formation pressure in the production process can be obtained. The comparison with the numerical simulation results shows that the relative deviation between the average formation pressure calculated by this method and the numerical simulation is small，only 0.054%. The findings demonstrate that the method does not require a shut-in of the wells， has no effects on production，and just calls for readily available dynamic and static information. It is simple to use and has a high degree of accuracy. It can be concluded that the method can obtain the average formation pressure economically and efficiently. Based on the average formation pressure， the drive index of the reservoir and the phase recovery can be calculated， which provides an important basis for the subsequent development of the reservoir.
Online Submit
Reviewer
Editor
Reader
Quick Search
External Links
