2017 Vol. 42, No. 8
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2017, 42(8): 1247-1262.
doi: 10.3799/dqkx.2017.518
Abstract:
With the development of oil and gas field, the complex reservoirs including low or ultra-low permeability reservoirs, heavy or ultra-heavy oil reservoirs, small fault block reservoirs, thin reservoirs, high water-cut reservoirs have been drawing increasing attention. Low-frequency vibration oil extraction technology has great potential for the complex reservoirs to improve the injection and output, because of its advantages of low cost, high effectivity, no formation damage and environmental pollution. Based on studying the outcomes in related fields at home and aboard, It is found the key lies in the theory of reservoir seepage dynamic mechanism under elastic waves to improve the field effect stability and optimize decision-making of low-frequency vibration oil extraction technology in this study. The generalization of the development of vibration coupled seepage mechanics can effectively distinguish the difference of seepage mechanics under vibration, elastic wave propagation theory in porous media and classical oil and gas seepage mechanics in aspects of the applied disciplines, source types, fluid flow equations, and boundary conditions. The main difficulties for quantitative description of mechanisms in dynamic flow in porous media by vibration coupled seepage mechanics are analyzed. Finally, key issues to be solved for the development of vibration coupled seepage mechanics are suggested.
With the development of oil and gas field, the complex reservoirs including low or ultra-low permeability reservoirs, heavy or ultra-heavy oil reservoirs, small fault block reservoirs, thin reservoirs, high water-cut reservoirs have been drawing increasing attention. Low-frequency vibration oil extraction technology has great potential for the complex reservoirs to improve the injection and output, because of its advantages of low cost, high effectivity, no formation damage and environmental pollution. Based on studying the outcomes in related fields at home and aboard, It is found the key lies in the theory of reservoir seepage dynamic mechanism under elastic waves to improve the field effect stability and optimize decision-making of low-frequency vibration oil extraction technology in this study. The generalization of the development of vibration coupled seepage mechanics can effectively distinguish the difference of seepage mechanics under vibration, elastic wave propagation theory in porous media and classical oil and gas seepage mechanics in aspects of the applied disciplines, source types, fluid flow equations, and boundary conditions. The main difficulties for quantitative description of mechanisms in dynamic flow in porous media by vibration coupled seepage mechanics are analyzed. Finally, key issues to be solved for the development of vibration coupled seepage mechanics are suggested.
2017, 42(8): 1263-1272.
doi: 10.3799/dqkx.2017.546
Abstract:
Simulation results of the reactive flow of the acid in the rock generally are used to optimize the operation of reservoir acidization so that the optimal injection rate is determined to stimulate the formation effectively with minimum cost. Many models have been developed based on variety of methods to study the reactive flow in carbonate reservoir during acidizing. However, these models are still short of scientific classification and systematization. According to the spatial scale of the study objects, the existing models for reactive flow in carbonate rocks are classified into three types, namely pore-scale model, core-scale model and wellbore-scale model in this study. The assumptions and limitations of each type are summarized. Based on the works we have done in the simulation of reactive flow in carbonate rock, the latest research progress and development trend of the core-scale model are presented in this paper. Besides, suggestions on the future studies on core-scale model are proposed, which include developing more accurate mathematical model, such as considering the effect of non-Darcy flow and the influence of stress, developing the efficient numerical algorithms to extend the computational domain to the whole reservoir, upscaling the core-scale model to obtain the optimal operating parameters during carbonate reservoir acidization.
Simulation results of the reactive flow of the acid in the rock generally are used to optimize the operation of reservoir acidization so that the optimal injection rate is determined to stimulate the formation effectively with minimum cost. Many models have been developed based on variety of methods to study the reactive flow in carbonate reservoir during acidizing. However, these models are still short of scientific classification and systematization. According to the spatial scale of the study objects, the existing models for reactive flow in carbonate rocks are classified into three types, namely pore-scale model, core-scale model and wellbore-scale model in this study. The assumptions and limitations of each type are summarized. Based on the works we have done in the simulation of reactive flow in carbonate rock, the latest research progress and development trend of the core-scale model are presented in this paper. Besides, suggestions on the future studies on core-scale model are proposed, which include developing more accurate mathematical model, such as considering the effect of non-Darcy flow and the influence of stress, developing the efficient numerical algorithms to extend the computational domain to the whole reservoir, upscaling the core-scale model to obtain the optimal operating parameters during carbonate reservoir acidization.
2017, 42(8): 1273-1286.
doi: 10.3799/dqkx.2017.101
Abstract:
Fractured carbonate reservoir is one of the most important reservoir types in the world, and its flow mechanisms has been a hot but challenging research topic in petroleum engineering. With the deepening exploration and development, many deep fractured marine carbon reservoirs have been discovered. However, the existing theories cannot accurately characterize the fluid flow mechanisms. Based on the extensive investigation on the existing theories and methods, the flow capacity characterization of fractures, the fluid exchange between different porous mediums and the mathematical models are reviewed systematically, and the prospect of future development and researches of flow theory in this kind of reservoir are also presented in this paper. Moreover, the results can be used to guide the development of similar reservoirs around the world.
Fractured carbonate reservoir is one of the most important reservoir types in the world, and its flow mechanisms has been a hot but challenging research topic in petroleum engineering. With the deepening exploration and development, many deep fractured marine carbon reservoirs have been discovered. However, the existing theories cannot accurately characterize the fluid flow mechanisms. Based on the extensive investigation on the existing theories and methods, the flow capacity characterization of fractures, the fluid exchange between different porous mediums and the mathematical models are reviewed systematically, and the prospect of future development and researches of flow theory in this kind of reservoir are also presented in this paper. Moreover, the results can be used to guide the development of similar reservoirs around the world.
2017, 42(8): 1287-1295.
doi: 10.3799/dqkx.2017.522
Abstract:
Seepage model experimentis widely utilized in many engineering fields such as geotechnical engineering and oil engineering since it can simulate the seepage process and movement law of fluid in porous media. While in the traditional seepage model experiment, due to the opacity of model medium, the specific seepage process, diffusion law and occurrence state of fluid cannot be observed directly. This paper presents the research progress of current visual seepage experiment, including its limitations. And a new technique of seepage experiment based on transparent rock-soil material, combining with optical observation method, tracer technique and digital imaging processing technology is proposed. In addition, the advantages and disadvantages between this technology and the traditional visual seepageexperiment are analyzed. Compared with the traditional seepage experiment, this technology can not only achieve the visual observation of the specific seepage process, but also has the advantages of invlovement of simple devices, easy operation and low cost, which indicates that it is feasible to use of this material to carry out visual observation of seepage experiment, laying a theoretical foundation for carrying out the visual seepage model experiment based on transparent rock-soil material.
Seepage model experimentis widely utilized in many engineering fields such as geotechnical engineering and oil engineering since it can simulate the seepage process and movement law of fluid in porous media. While in the traditional seepage model experiment, due to the opacity of model medium, the specific seepage process, diffusion law and occurrence state of fluid cannot be observed directly. This paper presents the research progress of current visual seepage experiment, including its limitations. And a new technique of seepage experiment based on transparent rock-soil material, combining with optical observation method, tracer technique and digital imaging processing technology is proposed. In addition, the advantages and disadvantages between this technology and the traditional visual seepageexperiment are analyzed. Compared with the traditional seepage experiment, this technology can not only achieve the visual observation of the specific seepage process, but also has the advantages of invlovement of simple devices, easy operation and low cost, which indicates that it is feasible to use of this material to carry out visual observation of seepage experiment, laying a theoretical foundation for carrying out the visual seepage model experiment based on transparent rock-soil material.
2017, 42(8): 1296-1300.
doi: 10.3799/dqkx.2017.102
Abstract:
Vertical reorientation fracture is a new hydraulic fracturing technique, which has been proved very effective in oil recovery enhancement, particularly in anisotropic reservoirs. In this paper, an analytical model has been derived to evaluate the productivity of the refractured wells drilled in anisotropic reservoirs by using sink-superposition theory, and computing comparison has been presented for illustration. It is concluded that the angle between the orientation of the secondary fracture and that of the dominant permeability has a little effect on the productivity rate when wells are drilled in isotropic formation, but it does have a strong impact on the productivity enhancement when wells are drilled in anisotropic formation; fracture orientation angles can influence the inflow area of fluid from the formation into the fracture along the dominant permeability direction; and the bigger the inflow area, the larger the dimensionless productivity index. Therefore, it is suggested wells drilled in formation with strong anisotropic properties should be preferred candidates for refracture treatment in order to obtain better economic benefits.
Vertical reorientation fracture is a new hydraulic fracturing technique, which has been proved very effective in oil recovery enhancement, particularly in anisotropic reservoirs. In this paper, an analytical model has been derived to evaluate the productivity of the refractured wells drilled in anisotropic reservoirs by using sink-superposition theory, and computing comparison has been presented for illustration. It is concluded that the angle between the orientation of the secondary fracture and that of the dominant permeability has a little effect on the productivity rate when wells are drilled in isotropic formation, but it does have a strong impact on the productivity enhancement when wells are drilled in anisotropic formation; fracture orientation angles can influence the inflow area of fluid from the formation into the fracture along the dominant permeability direction; and the bigger the inflow area, the larger the dimensionless productivity index. Therefore, it is suggested wells drilled in formation with strong anisotropic properties should be preferred candidates for refracture treatment in order to obtain better economic benefits.
2017, 42(8): 1301-1313.
doi: 10.3799/dqkx.2017.551
Abstract:
Shale reservoirs have different types of pore spaces, however, relevant studies on measuring the apparent permeability (AP) of shale gas reservoirs with considering different pore space have not been reported. A stochastic permeability model is proposed based on the embedded discrete fracture model (EDFM) in this study, which includes four steps. (1) The spatial distribution model of natural fracture, organic matter and inorganic matter is established. (2) Different permeability calculation methods are selected for different types of pore space. (3) The numerical simulation model is established on the basis of EDFM, using the spatial distribution model and different permeability calculation methods. (4) The gas flow rate is obtained by numerical simulation method after giving different pressures at the inlet and outlet of the model. Then the AP of this shale gas reservoir can be measured through the Darcy's law. The results of the model are in good agreement with the experimental results reported in literature. The effect of different pore space types, distribution and some other characteristics were analyzed. Results show that the contribution of natural fractures to AP is greater than that of matrix pores. Therefore it is crucial to take the effect of different pore space types into account in the process of calculating shale gas AP.
Shale reservoirs have different types of pore spaces, however, relevant studies on measuring the apparent permeability (AP) of shale gas reservoirs with considering different pore space have not been reported. A stochastic permeability model is proposed based on the embedded discrete fracture model (EDFM) in this study, which includes four steps. (1) The spatial distribution model of natural fracture, organic matter and inorganic matter is established. (2) Different permeability calculation methods are selected for different types of pore space. (3) The numerical simulation model is established on the basis of EDFM, using the spatial distribution model and different permeability calculation methods. (4) The gas flow rate is obtained by numerical simulation method after giving different pressures at the inlet and outlet of the model. Then the AP of this shale gas reservoir can be measured through the Darcy's law. The results of the model are in good agreement with the experimental results reported in literature. The effect of different pore space types, distribution and some other characteristics were analyzed. Results show that the contribution of natural fractures to AP is greater than that of matrix pores. Therefore it is crucial to take the effect of different pore space types into account in the process of calculating shale gas AP.
2017, 42(8): 1314-1323.
doi: 10.3799/dqkx.2017.532
Abstract:
Hydraulic fracturing practices in shale reservoirs show that effective stimulated reservoir volume (ESRV) significantly affects the production of hydraulic fractured well. Therefore, estimating ESRV is an important prerequisite for the evaluation and production prediction of hydraulic fracturing wells in shale reservoirs. This paper introduces a representation elementary volume (REV) of orthogonal discrete fracture coupled dual-porosity matrixflow model to predict the volumetric flux of gas in shale reservoirs. The influence of fracture space and fracture width on gas migration was studied. Considering fractal characteristics of the fracture network in stimulated reservoir volume (SRV), fractal dimension was used to quantitatively evaluate the fracture space distribution. Combining the effective fracture space and fractal characteristic of fracture network, a new approach was proposed to evaluate the ESRV in shale reservoirs. The approach was used in Eagle Ford shale gas reservoir and the results show that the fracture space has a great influence on migration of adsorbed gas. Fracture network has a contribution to enhance absorbed and free gas recovery ratio when the fracture space is less than 0.20 m. The ESRV was evaluated in this paper and the results indicate that the ESRV accounts for 37.78% of the total SRV in shale gas reservoir. The ESRV was influenced by both secondary fracture distribution and effective fracture space, as a result of reservoir intrinsic property and hydraulic fracturing practices.
Hydraulic fracturing practices in shale reservoirs show that effective stimulated reservoir volume (ESRV) significantly affects the production of hydraulic fractured well. Therefore, estimating ESRV is an important prerequisite for the evaluation and production prediction of hydraulic fracturing wells in shale reservoirs. This paper introduces a representation elementary volume (REV) of orthogonal discrete fracture coupled dual-porosity matrixflow model to predict the volumetric flux of gas in shale reservoirs. The influence of fracture space and fracture width on gas migration was studied. Considering fractal characteristics of the fracture network in stimulated reservoir volume (SRV), fractal dimension was used to quantitatively evaluate the fracture space distribution. Combining the effective fracture space and fractal characteristic of fracture network, a new approach was proposed to evaluate the ESRV in shale reservoirs. The approach was used in Eagle Ford shale gas reservoir and the results show that the fracture space has a great influence on migration of adsorbed gas. Fracture network has a contribution to enhance absorbed and free gas recovery ratio when the fracture space is less than 0.20 m. The ESRV was evaluated in this paper and the results indicate that the ESRV accounts for 37.78% of the total SRV in shale gas reservoir. The ESRV was influenced by both secondary fracture distribution and effective fracture space, as a result of reservoir intrinsic property and hydraulic fracturing practices.
2017, 42(8): 1324-1332.
doi: 10.3799/dqkx.2017.556
Abstract:
Numerical well test interpretation of massive multistage fractured horizontal wells can be used for the fracturing effect evaluation, which is very important for productivity evaluation. However, few field case studies have been conducted. Numerical solution of oil-water two-phase flow based on PEBI grid and description of stimulated reservoir volume (SRV) by main fractures with infinite conductivity and improved permeability of the region with minor fractures are used in combination to interpret the transient pressure of massive multistage fractured horizontal wells in tight oil reservoirs in Daqing oilfield. The interpretation and sensitivity analysis of permeability of exterior region show that the value of pressure derivative becomes smaller at early time and becomes larger at late time when the permeability of exterior region decreases, compared with pressure derivative without permeability modification, which indicates a turning point on the curves of pressure derivative. Prior to the turning point, the pressure derivative with smaller permeability in exterior region is relatively smaller, while after the point, the pressure derivative is larger. The time of appearance of the turning point is related to the magnitude of permeability between those of exterior and interior regions. Therefore, when good fitting of pressure derivative curves achieves at early time and bad fitting of pressure derivative curves at late time, adjustment of permeability of exterior region cannot wholly improve the fitting effect, and other parameters need to be adjusted to improve the fitting. This study can facilitate future transient pressure analysis for massive multistage fractured horizontal wells in tight oil reservoirs.
Numerical well test interpretation of massive multistage fractured horizontal wells can be used for the fracturing effect evaluation, which is very important for productivity evaluation. However, few field case studies have been conducted. Numerical solution of oil-water two-phase flow based on PEBI grid and description of stimulated reservoir volume (SRV) by main fractures with infinite conductivity and improved permeability of the region with minor fractures are used in combination to interpret the transient pressure of massive multistage fractured horizontal wells in tight oil reservoirs in Daqing oilfield. The interpretation and sensitivity analysis of permeability of exterior region show that the value of pressure derivative becomes smaller at early time and becomes larger at late time when the permeability of exterior region decreases, compared with pressure derivative without permeability modification, which indicates a turning point on the curves of pressure derivative. Prior to the turning point, the pressure derivative with smaller permeability in exterior region is relatively smaller, while after the point, the pressure derivative is larger. The time of appearance of the turning point is related to the magnitude of permeability between those of exterior and interior regions. Therefore, when good fitting of pressure derivative curves achieves at early time and bad fitting of pressure derivative curves at late time, adjustment of permeability of exterior region cannot wholly improve the fitting effect, and other parameters need to be adjusted to improve the fitting. This study can facilitate future transient pressure analysis for massive multistage fractured horizontal wells in tight oil reservoirs.
2017, 42(8): 1333-1339.
doi: 10.3799/dqkx.2017.506
Abstract:
The application interpretation of nuclear magnetic resonance (NMR) technology in unconventional reservoirs has been very controversial. A new interpretation method of NMR spectrum is proposed and applied to the unconventional reservoirs combining with the concept of seepage fluid. The results show that the left peak and right peak of nuclear magnetic resonance spectrum in tight oil and gas sandstone cores are continuous rather than entirely separated, which indicates that the properties of the differences between the easy-to-produce fluid and the difficult-to-produce fluid is not completely separated. But the nuclear magnetic resonance spectrum of shale and coal bed methane (CBM) reservoir cores is opposite to the above mentioned results. In cores of unconventional reservoirs, the difficult-to-produce fluid dominates, and the easy-to-produce fluid in tight oil and gas sandstone cores is more than that of shale and CBM reservoir cores. The recovery degree of tight oil and gas sandstone reservoirs mainly increases in the easy-to-produce fluid extraction, but the recovery degree of shale and CBM reservoirs mainly increases in the difficult-to-produce fluid extraction.
The application interpretation of nuclear magnetic resonance (NMR) technology in unconventional reservoirs has been very controversial. A new interpretation method of NMR spectrum is proposed and applied to the unconventional reservoirs combining with the concept of seepage fluid. The results show that the left peak and right peak of nuclear magnetic resonance spectrum in tight oil and gas sandstone cores are continuous rather than entirely separated, which indicates that the properties of the differences between the easy-to-produce fluid and the difficult-to-produce fluid is not completely separated. But the nuclear magnetic resonance spectrum of shale and coal bed methane (CBM) reservoir cores is opposite to the above mentioned results. In cores of unconventional reservoirs, the difficult-to-produce fluid dominates, and the easy-to-produce fluid in tight oil and gas sandstone cores is more than that of shale and CBM reservoir cores. The recovery degree of tight oil and gas sandstone reservoirs mainly increases in the easy-to-produce fluid extraction, but the recovery degree of shale and CBM reservoirs mainly increases in the difficult-to-produce fluid extraction.
2017, 42(8): 1340-1347.
doi: 10.3799/dqkx.2017.527
Abstract:
Yinggehai basin X area belongs to high-temperature and high-pressure gas reservoir, so that the content of dissolved gas in water is very large. However, the changing characteristics of gas-water interface and water invasion regularity is unknown because of the releasing of dissolved gas in water. In this paper, the variation of dissolved gas in water of different formations in X was tested through PVT facilities using natural gas and formation water. The sand packed model with visualization was designed to investigate the influence of water-soluble gas on gas-water interface. Results show that the solubility of water-soluble gas is affected by temperature, pressure, salinity and the components of natural gas, gradually increases with the increase of pressure, decreases with the increase of the temperature at first and then increases and the inflection point temperature is about 80-90℃. The solubility of water-soluble gas is 22.5 m3/m3, and 8.7 m3/m3 for X-1 and X-2 under condition of 145℃, 54 MPa respectively. Sand packed model with visualization experiment shows that the gas-water interface increases obviously in the process of natural depletion because of migration with gas releasing from the water, the pressure decreasing of formation water and capillary force. Numerical simulation of gas reservoir shows that gas-water interface of reservoir with high solubility of water-soluble gas increase faster and the water breakthrough time is earlier than those reservoirs with low solubility of water-soluble gas. During 10 years forecast period, water breakthrough in X-1 is about 800 days earlier, 800 m faster on the plane and 7.3 m faster on the vertical, considering water-soluble gas. And for X-2, those are 300 days, 500 m and 7.0 m respectively.
Yinggehai basin X area belongs to high-temperature and high-pressure gas reservoir, so that the content of dissolved gas in water is very large. However, the changing characteristics of gas-water interface and water invasion regularity is unknown because of the releasing of dissolved gas in water. In this paper, the variation of dissolved gas in water of different formations in X was tested through PVT facilities using natural gas and formation water. The sand packed model with visualization was designed to investigate the influence of water-soluble gas on gas-water interface. Results show that the solubility of water-soluble gas is affected by temperature, pressure, salinity and the components of natural gas, gradually increases with the increase of pressure, decreases with the increase of the temperature at first and then increases and the inflection point temperature is about 80-90℃. The solubility of water-soluble gas is 22.5 m3/m3, and 8.7 m3/m3 for X-1 and X-2 under condition of 145℃, 54 MPa respectively. Sand packed model with visualization experiment shows that the gas-water interface increases obviously in the process of natural depletion because of migration with gas releasing from the water, the pressure decreasing of formation water and capillary force. Numerical simulation of gas reservoir shows that gas-water interface of reservoir with high solubility of water-soluble gas increase faster and the water breakthrough time is earlier than those reservoirs with low solubility of water-soluble gas. During 10 years forecast period, water breakthrough in X-1 is about 800 days earlier, 800 m faster on the plane and 7.3 m faster on the vertical, considering water-soluble gas. And for X-2, those are 300 days, 500 m and 7.0 m respectively.
2017, 42(8): 1348-1355.
doi: 10.3799/dqkx.2017.103
Abstract:
The formation heterogeneity causes uneven sweeping of waterflooding. Different degrees of prevailing water flowing are generated due to different sizes of pores and throats. During the middle-late stage of water flooding, it is hard to move the remaining oil since it is scattered in the pores and throats. The EOR (enhanced oil recovery) study is mainly concerned with methods both to inhibit different sized prevailing flowing channels, and to keep oil flowing path free of plugging, which can ensure production efficiency of remaining oil. In this study, the pore-scale microscopic heterogeneous models with real pore structure were established, and different oil displacing mechanisms were compared between continuous phase viscous fluid, such as conventional polymer and crosslinked polymer gel, and micro-nano soft microgel particle dispersion. Results show that the traditional polymer flooding cannot differentiate between high and low permeability or big and small pore, because it relies on viscosity to increase the flowing resistance of all the swept area and it is hard to move the remaining oil when the viscosity is high to some extent. The soft microgel particle dispersion is a type of low viscosity dispersion fluid, and the particles have priority to access relatively big pore and throat, to temporarily inhibit the flowing, and at the same time, the water can be diverted into the relatively small pore and throat, to push the remaining oil out as a piston. The process is repeated continuously. The lab results were analyzed from the view of mobility adjustment in this paper, and it is concluded that the conventional continuous phase driving fluid modified mobility by increasing injection water viscosity, while the soft microgel particle dispersion achieved efficient mobility adjustment by decreasing the relative permeability of injection water and accordingly increased the oil permeable ability.
The formation heterogeneity causes uneven sweeping of waterflooding. Different degrees of prevailing water flowing are generated due to different sizes of pores and throats. During the middle-late stage of water flooding, it is hard to move the remaining oil since it is scattered in the pores and throats. The EOR (enhanced oil recovery) study is mainly concerned with methods both to inhibit different sized prevailing flowing channels, and to keep oil flowing path free of plugging, which can ensure production efficiency of remaining oil. In this study, the pore-scale microscopic heterogeneous models with real pore structure were established, and different oil displacing mechanisms were compared between continuous phase viscous fluid, such as conventional polymer and crosslinked polymer gel, and micro-nano soft microgel particle dispersion. Results show that the traditional polymer flooding cannot differentiate between high and low permeability or big and small pore, because it relies on viscosity to increase the flowing resistance of all the swept area and it is hard to move the remaining oil when the viscosity is high to some extent. The soft microgel particle dispersion is a type of low viscosity dispersion fluid, and the particles have priority to access relatively big pore and throat, to temporarily inhibit the flowing, and at the same time, the water can be diverted into the relatively small pore and throat, to push the remaining oil out as a piston. The process is repeated continuously. The lab results were analyzed from the view of mobility adjustment in this paper, and it is concluded that the conventional continuous phase driving fluid modified mobility by increasing injection water viscosity, while the soft microgel particle dispersion achieved efficient mobility adjustment by decreasing the relative permeability of injection water and accordingly increased the oil permeable ability.
2017, 42(8): 1356-1363.
doi: 10.3799/dqkx.2017.537
Abstract:
Diffusion is one of the key steps of methane transport in coal seam, yet our understanding of it is still insufficient. Taking the high rank coal bed methane (CBM) reservoir in the southern Qinshui basin, China as the study area, the patterns and quantitative characterization of methane diffusion in coal seam were analyzed based on microflows and nanoflows mechanics theory; the influence of diffusion property on gas production in coal seams of different coal textures was studied by using a numerical simulation software (Simed) in this study. Results show that the diffusion of methane in coal is driven by a chemical potential gradient and the diffusion modes include bulk diffusion, Knudsen diffusion and configurational diffusion. Various diffusion modes coexist and vary during the extraction of coalbed methane; the diffusion coefficient is influenced by temperature, gas pressure, gas type, moisture and pore structure of coal matrix, and the size of micropore varies due to the adsorption of methane and thereby the diffusion path will be transformed; the dynamic adsorption of methane on the coal matrix determines that methane diffusion in coal is a non-equillibrium process and that the diffusion coefficient is a function of adsorbed gas concentration; the results of numerical simulation based on quasi-steady diffusion show that the diffusion property has a slight influence on the long-term cumulative gas production while it exerts a significant effect on the short-term gas rate; if the diffusion coefficient is low, that is, the sorption time constant is relatively high, the peak gas rate will be relatively low while the gas rate will be relatively high in a period of time after reaching the peak gas rate; the gas production is more sensitive to sorption time constant for the low-permeability tectonically deformed coal seam than for the high-permeability one.
Diffusion is one of the key steps of methane transport in coal seam, yet our understanding of it is still insufficient. Taking the high rank coal bed methane (CBM) reservoir in the southern Qinshui basin, China as the study area, the patterns and quantitative characterization of methane diffusion in coal seam were analyzed based on microflows and nanoflows mechanics theory; the influence of diffusion property on gas production in coal seams of different coal textures was studied by using a numerical simulation software (Simed) in this study. Results show that the diffusion of methane in coal is driven by a chemical potential gradient and the diffusion modes include bulk diffusion, Knudsen diffusion and configurational diffusion. Various diffusion modes coexist and vary during the extraction of coalbed methane; the diffusion coefficient is influenced by temperature, gas pressure, gas type, moisture and pore structure of coal matrix, and the size of micropore varies due to the adsorption of methane and thereby the diffusion path will be transformed; the dynamic adsorption of methane on the coal matrix determines that methane diffusion in coal is a non-equillibrium process and that the diffusion coefficient is a function of adsorbed gas concentration; the results of numerical simulation based on quasi-steady diffusion show that the diffusion property has a slight influence on the long-term cumulative gas production while it exerts a significant effect on the short-term gas rate; if the diffusion coefficient is low, that is, the sorption time constant is relatively high, the peak gas rate will be relatively low while the gas rate will be relatively high in a period of time after reaching the peak gas rate; the gas production is more sensitive to sorption time constant for the low-permeability tectonically deformed coal seam than for the high-permeability one.
2017, 42(8): 1364-1372.
doi: 10.3799/dqkx.2017.542
Abstract:
With the development of economy and the rising demand for oil resources, the exploitation of viscous oil, bitumen and oil shale is an important challenge for the oil industry while the recoverable reserves of conventional crude is decreasing constantly. The viscous oil resources of our country is rich, but the polymer flooding is the main method enhancing viscous oil recovery due to restrictions of non-available steam generation facilities off-shore. So it is significant to study on micro flow mechanism deeply for further enhancing viscous oil recovery. The existing study on the polymer flow mechanism is mainly limited to the single phase flow in micro pore, and little study of viscoelastic polymer and oil two-phase flow characteristic has been done especially with viscous oil. In this study, we develop two phases of viscoelastic polymer and viscous oil solver on the OpenFOAM platform based on computational fluid dynamics, and we study the mechanism of viscoelastic polymer flooding viscous oil based on the solver. In this paper, the contraction model and mathematical model is established, including the continuity equation, momentum equation and constitutive equation of two phases, and interface equation solved by VOF (volume of fluid) method. The solver of viscoelastic and power law fluid is developed based on OpenFOAM. The saturation, velocity and stress distribution is drawn with different elastic polymer solutions. The results show that the front breakthrough time is slower, the sweep efficiency is larger and displacement efficiency is higher than water flooding. The elasticity of polymer can enhance oil recovery. The larger is the elasticity, the smaller the dead oil area in convex corner. The stronger of elasticity is, the lager of normal stress is. The elasticity can make the most of displacement oil when the polymer flows in contraction of the model. The results of this paper can supply the theoretical support basis on polymer design and filter, it is significant for implementation of polymer flooding in oil field.
With the development of economy and the rising demand for oil resources, the exploitation of viscous oil, bitumen and oil shale is an important challenge for the oil industry while the recoverable reserves of conventional crude is decreasing constantly. The viscous oil resources of our country is rich, but the polymer flooding is the main method enhancing viscous oil recovery due to restrictions of non-available steam generation facilities off-shore. So it is significant to study on micro flow mechanism deeply for further enhancing viscous oil recovery. The existing study on the polymer flow mechanism is mainly limited to the single phase flow in micro pore, and little study of viscoelastic polymer and oil two-phase flow characteristic has been done especially with viscous oil. In this study, we develop two phases of viscoelastic polymer and viscous oil solver on the OpenFOAM platform based on computational fluid dynamics, and we study the mechanism of viscoelastic polymer flooding viscous oil based on the solver. In this paper, the contraction model and mathematical model is established, including the continuity equation, momentum equation and constitutive equation of two phases, and interface equation solved by VOF (volume of fluid) method. The solver of viscoelastic and power law fluid is developed based on OpenFOAM. The saturation, velocity and stress distribution is drawn with different elastic polymer solutions. The results show that the front breakthrough time is slower, the sweep efficiency is larger and displacement efficiency is higher than water flooding. The elasticity of polymer can enhance oil recovery. The larger is the elasticity, the smaller the dead oil area in convex corner. The stronger of elasticity is, the lager of normal stress is. The elasticity can make the most of displacement oil when the polymer flows in contraction of the model. The results of this paper can supply the theoretical support basis on polymer design and filter, it is significant for implementation of polymer flooding in oil field.
2017, 42(8): 1373-1378.
doi: 10.3799/dqkx.2017.104
Abstract:
The pore structures and connections in unconventional oil and gas resources are very complex, the size of which may vary several orders of magnitude from millimeter to nanometer. And gas transport process depends on both microstructure characteristics and gas properties in the multiscale porous media. As gas transport in multiscale porous media may involve multiple transport mechanisms such as no-slip and slip flow, transition flow, Knudsen and molecular diffusion, it is difficult to characterize the gas transport with continuum theory. Since it has been proven that natural pore structures indicate fractal scaling laws, fractal geometry is employed in this study to model the multiscale pore structures. The fractal dimensions are introduced to characterize the pore size distribution and tortuous flow path, and a mesoscopic model is developed to study the gas transport in multiscale porous media. The effective permeability and diffusion coefficient of multiscale porous media are derived and presented, and the effect of microstructures and gas properties on the equivalent transport properties is also discussed. This study may be helpful for the development of seepage theory and understanding the output mechanisms of unconventional oil and gas reservoirs.
The pore structures and connections in unconventional oil and gas resources are very complex, the size of which may vary several orders of magnitude from millimeter to nanometer. And gas transport process depends on both microstructure characteristics and gas properties in the multiscale porous media. As gas transport in multiscale porous media may involve multiple transport mechanisms such as no-slip and slip flow, transition flow, Knudsen and molecular diffusion, it is difficult to characterize the gas transport with continuum theory. Since it has been proven that natural pore structures indicate fractal scaling laws, fractal geometry is employed in this study to model the multiscale pore structures. The fractal dimensions are introduced to characterize the pore size distribution and tortuous flow path, and a mesoscopic model is developed to study the gas transport in multiscale porous media. The effective permeability and diffusion coefficient of multiscale porous media are derived and presented, and the effect of microstructures and gas properties on the equivalent transport properties is also discussed. This study may be helpful for the development of seepage theory and understanding the output mechanisms of unconventional oil and gas reservoirs.
2017, 42(8): 1379-1385.
doi: 10.3799/dqkx.2017.550
Abstract:
Tight oil reservoirs mainly include tight limestone and tight sandstone, and there are significant differences in their microscopic characteristics. However, there are relatively fewer comparative studies on tight limestone and tight sandstone, so it is very important to study micro-pore characteristics and recoverability of different lithology tight oil reservoirs. By combining cryogenic nitrogen adsorption surface area, nuclear magnetic resonance and high pressure mercury technology, this paper comprehensively described the pore structure differences between tight limestone and tight sandstone from various scales including nano scale, submicron scale and micro scale, analyzed the effect of pores at different scales on permeability and fluid occurrence state, and studied the difference of the starting pressure gradient and the effect of throat on the starting pressure gradient. Taking the central Sichuan limestone and Changqing sandstone as an example, the results show that the tight oil reservoirs have development potential with permeability of more than 0.01 mD, in tight limestone, the submicron and micron scale pores are important reservoir and flow spaces, and in tight sandstone the micron scale pores are important reservoir and flow spaces, which are key to effective development. Based on numerous microscopic experimental analysis and low permeability reservoir evaluation methods, 8 grading evaluation parameters of tight reservoir were proposed and grading evaluation boundaries were determined, which is of great significance to determine the target of tight reservoirs and select the preferred blocks to build capacity.
Tight oil reservoirs mainly include tight limestone and tight sandstone, and there are significant differences in their microscopic characteristics. However, there are relatively fewer comparative studies on tight limestone and tight sandstone, so it is very important to study micro-pore characteristics and recoverability of different lithology tight oil reservoirs. By combining cryogenic nitrogen adsorption surface area, nuclear magnetic resonance and high pressure mercury technology, this paper comprehensively described the pore structure differences between tight limestone and tight sandstone from various scales including nano scale, submicron scale and micro scale, analyzed the effect of pores at different scales on permeability and fluid occurrence state, and studied the difference of the starting pressure gradient and the effect of throat on the starting pressure gradient. Taking the central Sichuan limestone and Changqing sandstone as an example, the results show that the tight oil reservoirs have development potential with permeability of more than 0.01 mD, in tight limestone, the submicron and micron scale pores are important reservoir and flow spaces, and in tight sandstone the micron scale pores are important reservoir and flow spaces, which are key to effective development. Based on numerous microscopic experimental analysis and low permeability reservoir evaluation methods, 8 grading evaluation parameters of tight reservoir were proposed and grading evaluation boundaries were determined, which is of great significance to determine the target of tight reservoirs and select the preferred blocks to build capacity.
2017, 42(8): 1386-1393.
doi: 10.3799/dqkx.2017.105
Abstract:
It is essential to understand methane mass transport through micro/nano pores in shale for the reservoir evaluation and gas production prediction. There distributes large numbers of pores, including micropores, mesopores and macropores. Kerogen, as the organic matter in shale, is rich in micro/meso-pores with width less than 50 nm. Multiple gas transport mechanisms coexist in porous media with complex pore size distribution, including viscous flow and Knudsen diffusion of free gas, and surface diffusion of adsorbed gas. During pressure depletion of a reservoir, the adsorbed gas desorbs into pore space as additional "free gas", and meanwhile, diffuses along the surface of nanopores in porous media. In this paper, experimental and calculated results for the gas transport in nanopores of shale matrix are presented, accounting for the effect on dynamic transport process of surface diffusion. The main conclusions are:(1) the equilibrium time for gas transport process decreases very quickly with temperature and less gas produced under higher temperature; (2) higher saturation pressure could accelerate the process and increase the amount of produced gas; (3) the mathematical model considers the effect of kerogen on the methane transport. Compared with the models not considering the effect of kerogen, the model presented in this paper fits the experimental results better. This study provides an experimental investigation of the methane mass transport through shale matrix considering the effect of kerogen, which is a relatively simple but information-rich technique for the assessment of shale gas targets.
It is essential to understand methane mass transport through micro/nano pores in shale for the reservoir evaluation and gas production prediction. There distributes large numbers of pores, including micropores, mesopores and macropores. Kerogen, as the organic matter in shale, is rich in micro/meso-pores with width less than 50 nm. Multiple gas transport mechanisms coexist in porous media with complex pore size distribution, including viscous flow and Knudsen diffusion of free gas, and surface diffusion of adsorbed gas. During pressure depletion of a reservoir, the adsorbed gas desorbs into pore space as additional "free gas", and meanwhile, diffuses along the surface of nanopores in porous media. In this paper, experimental and calculated results for the gas transport in nanopores of shale matrix are presented, accounting for the effect on dynamic transport process of surface diffusion. The main conclusions are:(1) the equilibrium time for gas transport process decreases very quickly with temperature and less gas produced under higher temperature; (2) higher saturation pressure could accelerate the process and increase the amount of produced gas; (3) the mathematical model considers the effect of kerogen on the methane transport. Compared with the models not considering the effect of kerogen, the model presented in this paper fits the experimental results better. This study provides an experimental investigation of the methane mass transport through shale matrix considering the effect of kerogen, which is a relatively simple but information-rich technique for the assessment of shale gas targets.
2017, 42(8): 1394-1402.
doi: 10.3799/dqkx.2017.106
Abstract:
Hydraulic fracturing is the main development method of low permeability reservoir, so it is important to the engineering to address the issue. By combining the fluid-structure interaction theory with fracture mechanics, the propagation of hydraulic fracture is simulated in this paper. Discrete fracture model and generalized J integral are introduced in the proposed model to calculate the flux across the fracture-matrix interface and fracture parameters, respectively. To ensure high precision and efficient simulation, the adaptive mesh refinement technology is introduced in the grids near the crack tip. The results show that the matrix permeability and viscosity of fracturing fluid mainly influence the final shape of hydraulic fracture, while the elastic modulus of rock mainly influence the fracture width. For fracture trucks, the maximum working pressure can generally meet the demand for fracturing production, and the maximum output power and maximum output flow are the main factors limiting the fracturing capacity.
Hydraulic fracturing is the main development method of low permeability reservoir, so it is important to the engineering to address the issue. By combining the fluid-structure interaction theory with fracture mechanics, the propagation of hydraulic fracture is simulated in this paper. Discrete fracture model and generalized J integral are introduced in the proposed model to calculate the flux across the fracture-matrix interface and fracture parameters, respectively. To ensure high precision and efficient simulation, the adaptive mesh refinement technology is introduced in the grids near the crack tip. The results show that the matrix permeability and viscosity of fracturing fluid mainly influence the final shape of hydraulic fracture, while the elastic modulus of rock mainly influence the fracture width. For fracture trucks, the maximum working pressure can generally meet the demand for fracturing production, and the maximum output power and maximum output flow are the main factors limiting the fracturing capacity.
2017, 42(8): 1403-1412.
doi: 10.3799/dqkx.2017.107
Abstract:
The ground temperature is higher and the pore pressure gradually decreases in the process of gas extraction in deep coal seams, however there are few studies on the coupling effect of temperature and pore pressure on the permeability of coal. Seepage experiments on the raw coal from Guizhou mining area are carried out by the self-developed triaxial seepage equipment with an adjustable outlet pressure to study the influence of pore pressure and temperature on the permeability. A permeability matching model with temperature effect is also developed in this study. An exponential relationship between the permeability and pore pressure is found and presented. The results show that the permeability decreases with increasing pore pressure, and it decreases as the differential pressure increases. Also, the permeability of coal seam decreases with increased temperature, and the decreasing rate and magnitude of permeability are different under different temperatures. Therefore, the differential pressure should be as small as possible to reduce the error and help develop the permeability model with different boundary conditions in the physical simulation experiments of coalbed methane (CBM) extraction. As the temperature increases, the mutation coefficient of temperature increases. While, the mutation coefficient of temperature decreases as pore pressure increases. It has been found these two characteristics that the mutation coefficient of temperature is not a constant in the whole stage and the realistic model matching with a variable cleat compressibility coefficient can reflect the development process of CBM.
The ground temperature is higher and the pore pressure gradually decreases in the process of gas extraction in deep coal seams, however there are few studies on the coupling effect of temperature and pore pressure on the permeability of coal. Seepage experiments on the raw coal from Guizhou mining area are carried out by the self-developed triaxial seepage equipment with an adjustable outlet pressure to study the influence of pore pressure and temperature on the permeability. A permeability matching model with temperature effect is also developed in this study. An exponential relationship between the permeability and pore pressure is found and presented. The results show that the permeability decreases with increasing pore pressure, and it decreases as the differential pressure increases. Also, the permeability of coal seam decreases with increased temperature, and the decreasing rate and magnitude of permeability are different under different temperatures. Therefore, the differential pressure should be as small as possible to reduce the error and help develop the permeability model with different boundary conditions in the physical simulation experiments of coalbed methane (CBM) extraction. As the temperature increases, the mutation coefficient of temperature increases. While, the mutation coefficient of temperature decreases as pore pressure increases. It has been found these two characteristics that the mutation coefficient of temperature is not a constant in the whole stage and the realistic model matching with a variable cleat compressibility coefficient can reflect the development process of CBM.
2017, 42(8): 1413-1420.
doi: 10.3799/dqkx.2017.519
Abstract:
It is significant to explore fluid crossflow rule of various medium in fractured-cavity reservoirs for effective development of crude oil in large-scale partially filled cavity. Based on the filling characteristics of the large size cavity in fractured-cavity reservoir, a fluid flow mathematical model for wells drilled in large-scale partially filled cavity in fractured-cavity reservoir has been proposed in this paper. The Laplace transformation and Stehfest numerical inversion are applied to analyze the crossflow rule in the partially filled cavity. The fluid crossflow characteristic curve for the partially filled cavity has been obtained and studied in this paper. The results show that the process of the flow for the partially filled cavity can be divided into four sections, including the earlier period and middle-early period flow for the crossflow between the matrix system and unfilled part of the cavity, the middle-late period and the later period flow for the crossflow between the filler of the cavity and unfilled part of the cavity. In middle-early flow period, the crossflow between the matrix system and unfilled part of the cavity reaches the quasi steady state. And the crossflow between the filler of the cavity and unfilled part of the cavity reaches the quasi steady state at the later period. Gravity is one of the main factors that influences the typical crossflow characteristic curve, leading to the decrease of the crossflow between the filler and the unfilled part of the cavity. However, the inter-porosity flow between the matrix and the unfilled part of the cavity has no relation with gravity. In addition, the cross flow characteristic curve is greatly affected by filling degree of the cavity, the energy parameters of the filler of the cavity and the energy parameters of the matrix. The methods and results of this research can facilitate further studies on the crossflow characteristics of the partially filled cavity in fractured-cavity reservoirs.
It is significant to explore fluid crossflow rule of various medium in fractured-cavity reservoirs for effective development of crude oil in large-scale partially filled cavity. Based on the filling characteristics of the large size cavity in fractured-cavity reservoir, a fluid flow mathematical model for wells drilled in large-scale partially filled cavity in fractured-cavity reservoir has been proposed in this paper. The Laplace transformation and Stehfest numerical inversion are applied to analyze the crossflow rule in the partially filled cavity. The fluid crossflow characteristic curve for the partially filled cavity has been obtained and studied in this paper. The results show that the process of the flow for the partially filled cavity can be divided into four sections, including the earlier period and middle-early period flow for the crossflow between the matrix system and unfilled part of the cavity, the middle-late period and the later period flow for the crossflow between the filler of the cavity and unfilled part of the cavity. In middle-early flow period, the crossflow between the matrix system and unfilled part of the cavity reaches the quasi steady state. And the crossflow between the filler of the cavity and unfilled part of the cavity reaches the quasi steady state at the later period. Gravity is one of the main factors that influences the typical crossflow characteristic curve, leading to the decrease of the crossflow between the filler and the unfilled part of the cavity. However, the inter-porosity flow between the matrix and the unfilled part of the cavity has no relation with gravity. In addition, the cross flow characteristic curve is greatly affected by filling degree of the cavity, the energy parameters of the filler of the cavity and the energy parameters of the matrix. The methods and results of this research can facilitate further studies on the crossflow characteristics of the partially filled cavity in fractured-cavity reservoirs.
2017, 42(8): 1421-1430.
doi: 10.3799/dqkx.2017.543
Abstract:
Studies on the adsorption mechanism of shale gas are of great significance to shale gas accumulation and reserves evaluation. Methane is in supercritical state at conditions under formation temperature and pressure, so the adsorption of shale gas is supercritical adsorption, however, its mechanismis still controversial. Based on Ono-Kondo lattice model, micropore structure and supercritical adsorption curves of Longmaxi shales were analyzed, combining with low temperature N2 adsorption and high pressure CH4 adsorption experiments. The results show that its pore size is small but specific surface area is large, and adsorbed gas may mainly exist in the micro-mesopores. The excess adsorption capacity will reach a maximum value when the pressure reaches about 10 MPa, and then the excess adsorption capacity decreases with the increase of pressure. The decreasing phenomenon is not abnormal, but the essential characteristics of excess adsorption capacity of supercritical methane. The fitting effect of the high pressure isothermal adsorption curves by Ono-Kondo lattice model is very good with its correlation coefficient above 0.99, indicating that the model can characterize the process of supercritical methane adsorption. Based on the fitted absorbed phase density of methane, the excess adsorption was converted into absolute adsorption. Then the number of adsorbed molecular layers under formation temperature and pressure was calculated and they are all less than 1, showing that the methane molecules are not entirely covered on the whole pore wall. Considering the influence of supercritical fluid properties, adsorption capacity and pore structure of shale, the adsorption mechanism of shale gas should be monolayer adsorption instead of two-layer or multilayer adsorption.
Studies on the adsorption mechanism of shale gas are of great significance to shale gas accumulation and reserves evaluation. Methane is in supercritical state at conditions under formation temperature and pressure, so the adsorption of shale gas is supercritical adsorption, however, its mechanismis still controversial. Based on Ono-Kondo lattice model, micropore structure and supercritical adsorption curves of Longmaxi shales were analyzed, combining with low temperature N2 adsorption and high pressure CH4 adsorption experiments. The results show that its pore size is small but specific surface area is large, and adsorbed gas may mainly exist in the micro-mesopores. The excess adsorption capacity will reach a maximum value when the pressure reaches about 10 MPa, and then the excess adsorption capacity decreases with the increase of pressure. The decreasing phenomenon is not abnormal, but the essential characteristics of excess adsorption capacity of supercritical methane. The fitting effect of the high pressure isothermal adsorption curves by Ono-Kondo lattice model is very good with its correlation coefficient above 0.99, indicating that the model can characterize the process of supercritical methane adsorption. Based on the fitted absorbed phase density of methane, the excess adsorption was converted into absolute adsorption. Then the number of adsorbed molecular layers under formation temperature and pressure was calculated and they are all less than 1, showing that the methane molecules are not entirely covered on the whole pore wall. Considering the influence of supercritical fluid properties, adsorption capacity and pore structure of shale, the adsorption mechanism of shale gas should be monolayer adsorption instead of two-layer or multilayer adsorption.
2017, 42(8): 1431-1440.
doi: 10.3799/dqkx.2017.108
Abstract:
During the process of tight oil exploration, counter current imbibition effect is significantly different due to the presence of complex fracture network and flow characteristics in tight oil reservoirs. But at present, there is no proper model to simulate counter-current imbibition in fractured reservoir considering the characteristics of tight oil formation. In order to solve this problem, PEBI grids are used to match the complex fracture network, natural fractures and matrix are idealized as dual-porosity medium, rate of mass transfer of imbibition between matrix and fractures is treated as source or sink term in dual porosity model. A new semi analytical model for the calculation of mass transfer function of counter-current imbibition in the presence of complex fracture network is established by using radial integration boundary element method (RIBEM). In addition, to reflect the flow characteristics of tight oil, relative permeability and capillary pressure curve with the effect of boundary layer considered, and mixed wettability have also used in the mass transfer model. Besides, we show the capacity and practical application of the model with a field example from tight oil reservoir. From simulated results, it is concluded that counter-current imbibition plays an important role in improving the oil recovery and the existence of boundary layer reduces the contribution of imbibition to oil production dramatically.
During the process of tight oil exploration, counter current imbibition effect is significantly different due to the presence of complex fracture network and flow characteristics in tight oil reservoirs. But at present, there is no proper model to simulate counter-current imbibition in fractured reservoir considering the characteristics of tight oil formation. In order to solve this problem, PEBI grids are used to match the complex fracture network, natural fractures and matrix are idealized as dual-porosity medium, rate of mass transfer of imbibition between matrix and fractures is treated as source or sink term in dual porosity model. A new semi analytical model for the calculation of mass transfer function of counter-current imbibition in the presence of complex fracture network is established by using radial integration boundary element method (RIBEM). In addition, to reflect the flow characteristics of tight oil, relative permeability and capillary pressure curve with the effect of boundary layer considered, and mixed wettability have also used in the mass transfer model. Besides, we show the capacity and practical application of the model with a field example from tight oil reservoir. From simulated results, it is concluded that counter-current imbibition plays an important role in improving the oil recovery and the existence of boundary layer reduces the contribution of imbibition to oil production dramatically.
