Volume 27,Issue 3,2020 Table of Contents
2020, 27(3):1-12.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.001
Abstract:
Chengdao Oilfield is a large shallower sea oilfield with an annual output of 217×104 t during the Ninth Five-Year Plan period. Since the reservoir showing the middle to high water-cut state，the development contradictions have become prominent. The offshore engineering supporting conditions cannot meet the continuous and stable production requirements of the oilfield，and the oil production has declined significantly with an annual decline rate of 2.5%. Therefore，the development adjustment is imperative. In view of the key problems restricting the continuous and stable production of Chengdao Oilfield，the key technologies of development and adjustment are developed in 6 aspects and 12 items through continuous research on the following aspects：reservoir geology，drilling and completion technology，injection-production and transportation technology，offshore engineering support，and platform life extension. The thin reservoir of fluvial facies in shallower sea is described and the geologic modeling at oilfield scale is established in details. The dense cluster drilling and completion technology for high angle cluster well and protection technology for multizone reservoir with complex pressure-drop profile，zonal water injection technology for high-angle well with long-interval，measurement and adjustment integration technology，high-efficiency zonal sand control and long-life high-efficiency lifting production technologies for high-angle well with long-interval are developed. The integration platform for oil and gas production and well repair and high-efficiency oil-gas-water treatment technology are developed as well. Platform testing and reinforcement technology for life extension in complex shallower sea environment are constructed. The successful application of the above technologies has ensured the high-speed and efficient implementation of scale subdivision of strata and well patterns adjustment in Chengdao Oilfield. The oil production reached 336×104 t in 2019.
Chengdao Oilfield is a large shallower sea oilfield with an annual output of 217×104 t during the Ninth Five-Year Plan period. Since the reservoir showing the middle to high water-cut state，the development contradictions have become prominent. The offshore engineering supporting conditions cannot meet the continuous and stable production requirements of the oilfield，and the oil production has declined significantly with an annual decline rate of 2.5%. Therefore，the development adjustment is imperative. In view of the key problems restricting the continuous and stable production of Chengdao Oilfield，the key technologies of development and adjustment are developed in 6 aspects and 12 items through continuous research on the following aspects：reservoir geology，drilling and completion technology，injection-production and transportation technology，offshore engineering support，and platform life extension. The thin reservoir of fluvial facies in shallower sea is described and the geologic modeling at oilfield scale is established in details. The dense cluster drilling and completion technology for high angle cluster well and protection technology for multizone reservoir with complex pressure-drop profile，zonal water injection technology for high-angle well with long-interval，measurement and adjustment integration technology，high-efficiency zonal sand control and long-life high-efficiency lifting production technologies for high-angle well with long-interval are developed. The integration platform for oil and gas production and well repair and high-efficiency oil-gas-water treatment technology are developed as well. Platform testing and reinforcement technology for life extension in complex shallower sea environment are constructed. The successful application of the above technologies has ensured the high-speed and efficient implementation of scale subdivision of strata and well patterns adjustment in Chengdao Oilfield. The oil production reached 336×104 t in 2019.
2020, 27(3):13-19.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.002
Abstract:
As the hydrocarbon exploration advances into the deep and ultra-deep reservoirs，it is important to study the development rules of the favorable reservoirs in deep layers. The Xishanyao Formation of Yongjin Oilfield in Junggar Basin has a large burial depth，tight matrix，and it is overpressured. However，the properties of the oil-bearing intervals are favorable，and the overpressured fluid has complex correlation with the evolution of formation properties. Therefore，the attentions are focused on the evolution of key factors such as diagenesis，formation properties，pressure and oil-gas filling and their time-space matching of Xishanyao Formation in Yongjin Oilfield，to study the development mechanism of favorable reservoirs. The results show that the formation of high porosity zone is related to five factors including，low debris content，early overpressure filling，diagenesis inhibition，hydraulic fracturing，and secondary dissolution. The interaction mechanism is that the sand body with the low debris content is weakly compacted，in which the primary pores are well preserved，and the early overpressured hydrocarbon bearing fluid is preferentially injected into the primary high porosity zone to make its compaction delay comparing with sandstone with the high debris content. Due to the inhibition of hydrocarbon fluid filling and chlorite film，the porosity of the high-porosity oil-bearing section has remained basically unchanged，and the hydraulic fracture is formed at the same time by strong overpressure，which further improves the permeability of the reservoir. Depending on the fluid activity space provided by the primary pore and hydraulic fractures，the secondary dissolution pores of theprimaryporeswellpreservedorthefracturedevelopedsectionarewelldeveloped.Thetotalremainingporosityisabout 7%.
As the hydrocarbon exploration advances into the deep and ultra-deep reservoirs，it is important to study the development rules of the favorable reservoirs in deep layers. The Xishanyao Formation of Yongjin Oilfield in Junggar Basin has a large burial depth，tight matrix，and it is overpressured. However，the properties of the oil-bearing intervals are favorable，and the overpressured fluid has complex correlation with the evolution of formation properties. Therefore，the attentions are focused on the evolution of key factors such as diagenesis，formation properties，pressure and oil-gas filling and their time-space matching of Xishanyao Formation in Yongjin Oilfield，to study the development mechanism of favorable reservoirs. The results show that the formation of high porosity zone is related to five factors including，low debris content，early overpressure filling，diagenesis inhibition，hydraulic fracturing，and secondary dissolution. The interaction mechanism is that the sand body with the low debris content is weakly compacted，in which the primary pores are well preserved，and the early overpressured hydrocarbon bearing fluid is preferentially injected into the primary high porosity zone to make its compaction delay comparing with sandstone with the high debris content. Due to the inhibition of hydrocarbon fluid filling and chlorite film，the porosity of the high-porosity oil-bearing section has remained basically unchanged，and the hydraulic fracture is formed at the same time by strong overpressure，which further improves the permeability of the reservoir. Depending on the fluid activity space provided by the primary pore and hydraulic fractures，the secondary dissolution pores of theprimaryporeswellpreservedorthefracturedevelopedsectionarewelldeveloped.Thetotalremainingporosityisabout 7%.
2020, 27(3):20-31.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.003
Abstract:
Seven ultra-low permeability core samples of Yanchang Formation in Zhenbei area，Ordos Basin are selected to carry out casting thin section，scanning electron microscope（SEM），X-ray diffraction，high pressure mercury injection and nuclear magnetic resonance（NMR）experiments，respectively. The characteristics of pore throat distribution，pore type，mineral composition and its content of ultra-low permeability reservoirs are clarified. The fractal theory is used to study the fractal characteristics of reservoir pore throat，and the relationships between the fractal dimension and the reservoir physical properties，pore structure parameters as well as mineral composition and its content are systematically analyzed. The results show that the reservoir pore types are mainly residual intergranular pores，dissolution pores and intercrystalline pores.The mineral composition of the reservoir is dominated by quartz and feldspar，and the content of chlorite in clay mineral is the highest. According to the morphology of capillary pressure curve and displacement pressure，the reservoir pore structure can be divided into three types：Type I，Type II and Type III. The corresponding reservoir performance and percolation capacity become worse in turn，and the heterogeneity of pore structure gradually increases. The pore throat size distribution obtained by high pressure mercury injection has multi-fractal features. There are two obvious turning points in the fractal feature curve，which divides the pore space into macropores，mesopores and micropores. Compared with macropores and mesopores，the pore size distribution of micropores is relatively uniform and regular，and the corresponding fractal dimension is the smallest. NMR can provide a better characterization of the reservoir pore space. The pore throat distribution of the T2T2cutoff section
conform to the fractal structure，and the corresponding fractal dimension reflects the complexity of interconnected pores.The fractal dimension of reservoir pore throat has a good negative correlation with porosity and permeability，and also has a good correlation with pore structure parameters. The mineral composition and its content of reservoir are the internal factors that determine the size of fractal dimension，and then affect the reservoir quality and pore structure characteristics.
Seven ultra-low permeability core samples of Yanchang Formation in Zhenbei area，Ordos Basin are selected to carry out casting thin section，scanning electron microscope（SEM），X-ray diffraction，high pressure mercury injection and nuclear magnetic resonance（NMR）experiments，respectively. The characteristics of pore throat distribution，pore type，mineral composition and its content of ultra-low permeability reservoirs are clarified. The fractal theory is used to study the fractal characteristics of reservoir pore throat，and the relationships between the fractal dimension and the reservoir physical properties，pore structure parameters as well as mineral composition and its content are systematically analyzed. The results show that the reservoir pore types are mainly residual intergranular pores，dissolution pores and intercrystalline pores.The mineral composition of the reservoir is dominated by quartz and feldspar，and the content of chlorite in clay mineral is the highest. According to the morphology of capillary pressure curve and displacement pressure，the reservoir pore structure can be divided into three types：Type I，Type II and Type III. The corresponding reservoir performance and percolation capacity become worse in turn，and the heterogeneity of pore structure gradually increases. The pore throat size distribution obtained by high pressure mercury injection has multi-fractal features. There are two obvious turning points in the fractal feature curve，which divides the pore space into macropores，mesopores and micropores. Compared with macropores and mesopores，the pore size distribution of micropores is relatively uniform and regular，and the corresponding fractal dimension is the smallest. NMR can provide a better characterization of the reservoir pore space. The pore throat distribution of the T2
2020, 27(3):32-38.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.004
Abstract:
The natural fractures are important for oil and gas storage and transportation in the bedrock buried hill reservoirs.The fracture aperture is the key parameter for the reservoir quality characterization as well as reserves and productivity evaluation of buried hill reservoirs. In this study，a new fracture aperture prediction algorithm is proposed based on the ensemble learning algorithm. The samples are collected from the bedrock buried hill reservoirs in Basin B of Chad，Central Africa，and their fracture aperture data are extracted from the sample description，key well imaging logging，and fracture parameter interpretation. The same depth logging data are used as the feature variables to constitute the learning sample，and the K-means clustering algorithm is applied to reduce noise of the learning sample and eliminate abnormal data. Based on Support Vector Machine（SVM）regression and XGBoost regression algorithm，and by using random search to optimize model parameters，the fracture apertures are estimated according to the basic models combined by the ridge regression. The results show that the performance of the novel ensemble learning algorithm is better than that of the basic model，the root mean square error between the predicted and actual values of the test set is 0.047，and the correlation coefficient is 0.931.The algorithm improves the instability of the single regression algorithm，improves the generalization ability，and provides a new way for aperture prediction.
The natural fractures are important for oil and gas storage and transportation in the bedrock buried hill reservoirs.The fracture aperture is the key parameter for the reservoir quality characterization as well as reserves and productivity evaluation of buried hill reservoirs. In this study，a new fracture aperture prediction algorithm is proposed based on the ensemble learning algorithm. The samples are collected from the bedrock buried hill reservoirs in Basin B of Chad，Central Africa，and their fracture aperture data are extracted from the sample description，key well imaging logging，and fracture parameter interpretation. The same depth logging data are used as the feature variables to constitute the learning sample，and the K-means clustering algorithm is applied to reduce noise of the learning sample and eliminate abnormal data. Based on Support Vector Machine（SVM）regression and XGBoost regression algorithm，and by using random search to optimize model parameters，the fracture apertures are estimated according to the basic models combined by the ridge regression. The results show that the performance of the novel ensemble learning algorithm is better than that of the basic model，the root mean square error between the predicted and actual values of the test set is 0.047，and the correlation coefficient is 0.931.The algorithm improves the instability of the single regression algorithm，improves the generalization ability，and provides a new way for aperture prediction.
2020, 27(3):39-47.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.005
Abstract:
The oolitic beach in the third member of Feixianguan Formation in Tongnanba area contains a large gas bearing area，but the poor understanding of the rules of efficient accumulation and enrichment restricts its efficient exploration and development. Based on the comprehensive use of the geological and geophysical data，combined with the fine structural interpretation and analysis of the typical high-yield and stable-production wells，the formation mechanism of the high-efficiency gas reservoirs in the third member of Feixianguan Formation in Tongnanba area was discussed，and their natural gas accumulation process were analyzed，finally the direction for future exploration was clarified. The formation of the high-efficiency gas reservoirs in the third member of Feixianguan Formation in Hebachang Gasfield is mainly controlled by three factors.The high-quality reservoir with the high-energy oolitic beach is the base of the formation of high-efficiency gas reservoirs.The effective source-storage communication through the cracks to source rocks is the key to the high-efficient gas reservoir formation. Today’s favorable structural background promotes the high-efficiency gas reservoir formation. Tongjiang area is located at wing of Tongnanba anticline，in which the high-quality oolitic beach in the third member of Feixianguan Formation develops and the faults to source rocks develop in belt and in row，the source rocks and preservation conditions are superior. It is a favorable area that is expected to achieve efficient exploration and development in the near future.
The oolitic beach in the third member of Feixianguan Formation in Tongnanba area contains a large gas bearing area，but the poor understanding of the rules of efficient accumulation and enrichment restricts its efficient exploration and development. Based on the comprehensive use of the geological and geophysical data，combined with the fine structural interpretation and analysis of the typical high-yield and stable-production wells，the formation mechanism of the high-efficiency gas reservoirs in the third member of Feixianguan Formation in Tongnanba area was discussed，and their natural gas accumulation process were analyzed，finally the direction for future exploration was clarified. The formation of the high-efficiency gas reservoirs in the third member of Feixianguan Formation in Hebachang Gasfield is mainly controlled by three factors.The high-quality reservoir with the high-energy oolitic beach is the base of the formation of high-efficiency gas reservoirs.The effective source-storage communication through the cracks to source rocks is the key to the high-efficient gas reservoir formation. Today’s favorable structural background promotes the high-efficiency gas reservoir formation. Tongjiang area is located at wing of Tongnanba anticline，in which the high-quality oolitic beach in the third member of Feixianguan Formation develops and the faults to source rocks develop in belt and in row，the source rocks and preservation conditions are superior. It is a favorable area that is expected to achieve efficient exploration and development in the near future.
2020, 27(3):48-56.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.006
Abstract:
In order to analyze the productivity of the multi-branched horizontal wells in the coalbed methane（CBM）reservoir，a productivity model for multi-branched horizontal wells in a CBM reservoir is proposed，which considers stress sensitivity in the cleat system and the unsteady diffusion in the matrix system based on the basic theory of the fluid flow mechanism through porous media. The mathematical model is solved through the methods of the point source function，Pedrosa transformation，Perturbation transformation，Laplace transformation，Finite cosine transformation，Element discretization，and Superposition principle. The typical production decline curve is plotted by Stehfest numerical inversion，which is divided into nine different flow regimes according to the characteristics of this curve. Also，the model validation and the comparison of the pseudo-steady diffusion and unsteady diffusion are conducted. Then sensitivity parameter analysis is carried out，such as the permeability modulus，length of branches and number of branches. We summarized the effect of different parameters on production performance. The related research enriches the studies of the production performance of multibranched horizontal wells in a CBM reservoir and provides certain theoretical guidance for the development of a CBM reservoir.
In order to analyze the productivity of the multi-branched horizontal wells in the coalbed methane（CBM）reservoir，a productivity model for multi-branched horizontal wells in a CBM reservoir is proposed，which considers stress sensitivity in the cleat system and the unsteady diffusion in the matrix system based on the basic theory of the fluid flow mechanism through porous media. The mathematical model is solved through the methods of the point source function，Pedrosa transformation，Perturbation transformation，Laplace transformation，Finite cosine transformation，Element discretization，and Superposition principle. The typical production decline curve is plotted by Stehfest numerical inversion，which is divided into nine different flow regimes according to the characteristics of this curve. Also，the model validation and the comparison of the pseudo-steady diffusion and unsteady diffusion are conducted. Then sensitivity parameter analysis is carried out，such as the permeability modulus，length of branches and number of branches. We summarized the effect of different parameters on production performance. The related research enriches the studies of the production performance of multibranched horizontal wells in a CBM reservoir and provides certain theoretical guidance for the development of a CBM reservoir.
2020, 27(3):57-63.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.007
Abstract:
There is permeability anisotropy due to the high-permeability channels in extra-low permeability reservoirs，which leads to the different percolation behaviors between injectors and producers compared with conventional reservoirs，and different adaptability of well pattern infilling. Based on the percolation behaviors of anisotropic reservoirs and infilled well pattern，the calculation formula of plane percolation field between injectors and producers is obtained by using the superposition principle. The linear displacement is introduced to analyze the adaptability of infilled well pattern in the anisotropic reservoir. The driving pressure gradient is used to characterize percentage of producing reserve，and the dimensionless incremental percentage of producing reserve is proposed. A quantitative characterization method for producing reserve between injectors and producers is established. The results show that the initial inverted nine-point well patterns are systematically infilled to row well patterns to form linear displacement，which can effectively improve the producing reserve in the extra-low permeability anisotropic reservoirs. When the initial well spacing is greater than 400 m，the potential of producing reserve between injectors and producers is improved significantly.
There is permeability anisotropy due to the high-permeability channels in extra-low permeability reservoirs，which leads to the different percolation behaviors between injectors and producers compared with conventional reservoirs，and different adaptability of well pattern infilling. Based on the percolation behaviors of anisotropic reservoirs and infilled well pattern，the calculation formula of plane percolation field between injectors and producers is obtained by using the superposition principle. The linear displacement is introduced to analyze the adaptability of infilled well pattern in the anisotropic reservoir. The driving pressure gradient is used to characterize percentage of producing reserve，and the dimensionless incremental percentage of producing reserve is proposed. A quantitative characterization method for producing reserve between injectors and producers is established. The results show that the initial inverted nine-point well patterns are systematically infilled to row well patterns to form linear displacement，which can effectively improve the producing reserve in the extra-low permeability anisotropic reservoirs. When the initial well spacing is greater than 400 m，the potential of producing reserve between injectors and producers is improved significantly.
8 Reasonable well spacing for CO2 miscible flooding in low-permeability reservoirs of Shengli Oilfield
2020, 27(3):64-69.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.008
Abstract:
Considering the complexity of optimizing well spacing with component numerical simulation，and the insufficiency of capturing reservoir heterogeneity and oil viscosity changing with space in CO2 flooding with conventional well spacing calculation methods，through a large number of experiments，the relationship between the threshold pressure gradient（TPG）and the permeability of low-permeability reservoir in Shengli Oilfield is obtained by regression. Based on the non-Darcy theory and considering the reservoir heterogeneity，reduced viscosity of crude oil by CO2 flooding，convection，diffusion and adsorption，a mathematical model of injector-producer pressure difference of line well pattern in CO2 miscible flooding is established，and methods to determine the critical flow well spacing and the reasonable production well spacing are proposed. Taking a low-permeability reservoir in Shengli Oilfield as an example，the critical flow well spacing for CO2 miscible flooding is calculated. The results indicate that when the permeability increases to a certain value，TPG stably decreases with the increase of permeability. When the apparent permeability decreases to a certain value，TPG sharply increases with the decrease of permeability. For the low-permeability reservoirs in Shengli Oilfield，with the increase of injector-producer pressure difference，the reasonable production well spacing gradually increases，and the calculated reasonable production well spacing is consistent with the actual injector-producer well spacing，which verifies the reliability of the calculation method in this paper.
Considering the complexity of optimizing well spacing with component numerical simulation，and the insufficiency of capturing reservoir heterogeneity and oil viscosity changing with space in CO2 flooding with conventional well spacing calculation methods，through a large number of experiments，the relationship between the threshold pressure gradient（TPG）and the permeability of low-permeability reservoir in Shengli Oilfield is obtained by regression. Based on the non-Darcy theory and considering the reservoir heterogeneity，reduced viscosity of crude oil by CO2 flooding，convection，diffusion and adsorption，a mathematical model of injector-producer pressure difference of line well pattern in CO2 miscible flooding is established，and methods to determine the critical flow well spacing and the reasonable production well spacing are proposed. Taking a low-permeability reservoir in Shengli Oilfield as an example，the critical flow well spacing for CO2 miscible flooding is calculated. The results indicate that when the permeability increases to a certain value，TPG stably decreases with the increase of permeability. When the apparent permeability decreases to a certain value，TPG sharply increases with the decrease of permeability. For the low-permeability reservoirs in Shengli Oilfield，with the increase of injector-producer pressure difference，the reasonable production well spacing gradually increases，and the calculated reasonable production well spacing is consistent with the actual injector-producer well spacing，which verifies the reliability of the calculation method in this paper.
2020, 27(3):70-78.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.009
Abstract:
To better understand the remaining oil distribution in heavy oil reservoir with the unconsolidation sandstone before and after the infilling of the inverted nine-spot well pattern，the physical experiments were conducted to analyze the flow field and displacement efficiency after the infilling of inverted nine-spot well pattern using the three-dimensional physical model based on the practical reservoir petrophysical characters in well group. The variation of the pressure field，saturation field and displacement efficiency were obtained and analyzed after the infilling of inverted nine-spot well pattern.Before infilling，the regions with better reservoir properties have higher displacement efficiency and bigger growth rate of displacement efficiency. After infilling，the displacement efficiency became lower because of the water breakthrough at the area with better reservoir properties within a certain range of permeability. Infilling of well pattern and changing producers to injectors can improve the controlling degree of the water flooding and enhance oil recovery of 11.8%. For the reservoirs with the edge and bottom water before infilling，the remaining oil is vertically enriched in the middle and upper layers，and the remaining oil is horizontally distributed in the areas with the poor reservoir properties and regions between the edge wells and corner wells. After infilling，the remaining oil is distributed in the low-permeability regions between the producers and infill wells.
To better understand the remaining oil distribution in heavy oil reservoir with the unconsolidation sandstone before and after the infilling of the inverted nine-spot well pattern，the physical experiments were conducted to analyze the flow field and displacement efficiency after the infilling of inverted nine-spot well pattern using the three-dimensional physical model based on the practical reservoir petrophysical characters in well group. The variation of the pressure field，saturation field and displacement efficiency were obtained and analyzed after the infilling of inverted nine-spot well pattern.Before infilling，the regions with better reservoir properties have higher displacement efficiency and bigger growth rate of displacement efficiency. After infilling，the displacement efficiency became lower because of the water breakthrough at the area with better reservoir properties within a certain range of permeability. Infilling of well pattern and changing producers to injectors can improve the controlling degree of the water flooding and enhance oil recovery of 11.8%. For the reservoirs with the edge and bottom water before infilling，the remaining oil is vertically enriched in the middle and upper layers，and the remaining oil is horizontally distributed in the areas with the poor reservoir properties and regions between the edge wells and corner wells. After infilling，the remaining oil is distributed in the low-permeability regions between the producers and infill wells.
2020, 27(3):79-84.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.010
Abstract:
After the strong-alkali ASP system is injected into the reservoirs，the chemical reactions and physical changes take place between the alkali and mineral composition. The strong alkali dissolves the rock surface，and the dissolution products and clay particles migrate and precipitate on the flow channel of the reservoir，which causes great damage to the fluid flow. Taking Block A of Daqing Oilfield as a case，through percolation experiment by using the scanning electron microscope（SEM）and energy spectrum analysis，the damage mechanism of the strong alkali to formation and the change of mineral composition after dissolution are analyzed based on the dissolution of alkali to mineral composition，and then the influence on the core percolation ability is discussed. The core percolation experiment shows that the injection pressure increases about 140 kPa and the core permeability decreases about 18% after the long-term displacement using strong-alkali ASP system. Due to the dissolution caused by the strong alkali and percolation erosion，the original pore structure of the core is strongly destroyed，and the crystal structures of the kaolinite and montmorillonite etc. are destroyed also. After longtime displacement，the sediment formed after the alkali solution reaction and the clay particles detached migrate and stick to the surface of the pore throat channel，which causes the decrease of the core permeability. The results of SEM show that the surface characteristics of the rock minerals change before and after displacement，and the element content changes with the particle migration，which further verifies the effect of the strong-alkali ASP system on core permeability.
After the strong-alkali ASP system is injected into the reservoirs，the chemical reactions and physical changes take place between the alkali and mineral composition. The strong alkali dissolves the rock surface，and the dissolution products and clay particles migrate and precipitate on the flow channel of the reservoir，which causes great damage to the fluid flow. Taking Block A of Daqing Oilfield as a case，through percolation experiment by using the scanning electron microscope（SEM）and energy spectrum analysis，the damage mechanism of the strong alkali to formation and the change of mineral composition after dissolution are analyzed based on the dissolution of alkali to mineral composition，and then the influence on the core percolation ability is discussed. The core percolation experiment shows that the injection pressure increases about 140 kPa and the core permeability decreases about 18% after the long-term displacement using strong-alkali ASP system. Due to the dissolution caused by the strong alkali and percolation erosion，the original pore structure of the core is strongly destroyed，and the crystal structures of the kaolinite and montmorillonite etc. are destroyed also. After longtime displacement，the sediment formed after the alkali solution reaction and the clay particles detached migrate and stick to the surface of the pore throat channel，which causes the decrease of the core permeability. The results of SEM show that the surface characteristics of the rock minerals change before and after displacement，and the element content changes with the particle migration，which further verifies the effect of the strong-alkali ASP system on core permeability.
2020, 27(3):85-90.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.011
Abstract:
In order to study the effect of polymer retention on conformance control and production performance in an ultralow permeability heterogeneous reservoir，the artificial heterogeneous core models are used to perform a series of polymer conformance control experiments followed by production under the natural energy. Based on the novel designed experimental apparatus for reservoirs with an edge and bottom water and produced by the natural energy，the similarity simulation for the production characteristics of a practical oilfield is achieved in laboratory. The effect of polymer retention rate on water channeling control，reservoir pressure maintaining，oil production stabilization and enhanced oil recovery were analyzed.The results show that the increase of the polymer retention in the high-permeability layer is helpful to control water channeling，inhibit the decline rate of reservoir pressure，and extend the relatively high production period of production wells.Additionally，the oil recovery and the rate of polymer retention are non-monotonic，namely，there is an optimal retention rate（RC）to reach the highest oil recovery. Taking the optimal retention rate of polymer as the benchmark，higher or lower polymer retention rate leads to an obvious decline in oil recovery. For the target reservoir，the laboratory results show that the optimal polymer retention rate are 70% to 82%，and the optimal polymer injection volume are 0.3 PV to 0.6 PV（PV represents the pore volume of the high-permeability layer）. An effective conformance control technology for an ultra-low permeability heterogeneous reservoir needs to provide both optimal polymer injection volume and polymer retention rate.
In order to study the effect of polymer retention on conformance control and production performance in an ultralow permeability heterogeneous reservoir，the artificial heterogeneous core models are used to perform a series of polymer conformance control experiments followed by production under the natural energy. Based on the novel designed experimental apparatus for reservoirs with an edge and bottom water and produced by the natural energy，the similarity simulation for the production characteristics of a practical oilfield is achieved in laboratory. The effect of polymer retention rate on water channeling control，reservoir pressure maintaining，oil production stabilization and enhanced oil recovery were analyzed.The results show that the increase of the polymer retention in the high-permeability layer is helpful to control water channeling，inhibit the decline rate of reservoir pressure，and extend the relatively high production period of production wells.Additionally，the oil recovery and the rate of polymer retention are non-monotonic，namely，there is an optimal retention rate（RC）to reach the highest oil recovery. Taking the optimal retention rate of polymer as the benchmark，higher or lower polymer retention rate leads to an obvious decline in oil recovery. For the target reservoir，the laboratory results show that the optimal polymer retention rate are 70% to 82%，and the optimal polymer injection volume are 0.3 PV to 0.6 PV（PV represents the pore volume of the high-permeability layer）. An effective conformance control technology for an ultra-low permeability heterogeneous reservoir needs to provide both optimal polymer injection volume and polymer retention rate.
2020, 27(3):91-99.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.012
Abstract:
Due to the relatively high viscosity of the injected chemical solution and high flow resistance，the test shows that the liquid production index in the polymer/viscosity reducer flooding after the injection of the chemical agent generally decreases compared with that in the water flooding stage，and it is difficult to meet the preset requirements. At present，there is no feasible method to predict the liquid production capacity in the polymer/viscosity reducer flooding，which seriously restricts the application of chemical flooding technology in heavy oil reservoirs in Shengli Oilfield. Based on the mathematical statistics and reservoir numerical simulation methods，a numerical simulation model is first established by taking Block Ng3-4 in the eastern part of Gudao Oilfield as an example. Then，the effects of factors on dimensionless liquid production index are investigated. Finally，a quantitative characterization model for the dimensionless liquid production index is established based on the simulation results，and the dynamic methods for the liquid production capacity in the polymer/viscosity reducer flooding are formed. The research results show that the quantitative characterization model for the dimensionless liquid production index is concise in mathematical form，and the meaning of the uncertain coefficients in the model is clear.The proposed dynamic prediction method can better fit the dynamic field data.
Due to the relatively high viscosity of the injected chemical solution and high flow resistance，the test shows that the liquid production index in the polymer/viscosity reducer flooding after the injection of the chemical agent generally decreases compared with that in the water flooding stage，and it is difficult to meet the preset requirements. At present，there is no feasible method to predict the liquid production capacity in the polymer/viscosity reducer flooding，which seriously restricts the application of chemical flooding technology in heavy oil reservoirs in Shengli Oilfield. Based on the mathematical statistics and reservoir numerical simulation methods，a numerical simulation model is first established by taking Block Ng3-4 in the eastern part of Gudao Oilfield as an example. Then，the effects of factors on dimensionless liquid production index are investigated. Finally，a quantitative characterization model for the dimensionless liquid production index is established based on the simulation results，and the dynamic methods for the liquid production capacity in the polymer/viscosity reducer flooding are formed. The research results show that the quantitative characterization model for the dimensionless liquid production index is concise in mathematical form，and the meaning of the uncertain coefficients in the model is clear.The proposed dynamic prediction method can better fit the dynamic field data.
2020, 27(3):100-105.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.013
Abstract:
In order to further improve the performance of deep profile control using gel particles，the adaptability evaluation of gel particles for deep profile controlling is carried out according to the reservoir characteristics of strong heterogeneity and rich residual oil after long-term water flooding. The evolution process of the pore throat radius during the long-term water injection is quantitatively determined by NMR experiment，and the relationship between the matching factor（δ）and migration-plugging is established based on the quantitative microporous membrane filtration experiment. The deep migration，profile improvement and capability of enhanced oil recovery（EOR）by gel particles are verified by the dynamic physical experiments. The results show that the matching relationship between the gel particle radius and pore throat plays an important role in the depth of deep profile controlling. When δ is between 1.0 and 3.0，the gel particles are the most effective for deep profile controlling. The gel particles can effectively plug the high-permeability layers in the form of retention，adsorption and bridging，and the profile improvement rate of the heterogeneous core can reach 97.2%. The comparison experiment of three-layer heterogeneous core shows that under the best matching relation，the gel particles have good ability of deep migration and plugging，and the recovery factor can be improved up to 29.3%.
In order to further improve the performance of deep profile control using gel particles，the adaptability evaluation of gel particles for deep profile controlling is carried out according to the reservoir characteristics of strong heterogeneity and rich residual oil after long-term water flooding. The evolution process of the pore throat radius during the long-term water injection is quantitatively determined by NMR experiment，and the relationship between the matching factor（δ）and migration-plugging is established based on the quantitative microporous membrane filtration experiment. The deep migration，profile improvement and capability of enhanced oil recovery（EOR）by gel particles are verified by the dynamic physical experiments. The results show that the matching relationship between the gel particle radius and pore throat plays an important role in the depth of deep profile controlling. When δ is between 1.0 and 3.0，the gel particles are the most effective for deep profile controlling. The gel particles can effectively plug the high-permeability layers in the form of retention，adsorption and bridging，and the profile improvement rate of the heterogeneous core can reach 97.2%. The comparison experiment of three-layer heterogeneous core shows that under the best matching relation，the gel particles have good ability of deep migration and plugging，and the recovery factor can be improved up to 29.3%.
2020, 27(3):106-112.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.014
Abstract:
As a oil displacement agent，the foam has dual mechanisms，including the profile control and oil displacement.The heterogeneous microscopic model with the permeability ratio of 1∶3 and the parallel sand-packed pipe model are used to study the microscopic mechanism of the oil displacement and fluid flow diversion of the foam，and to evaluate the effect on oil displacement efficiency. The results of the displacement experiments using the heterogeneous microscopic model show that there are three significant percolation zones for the foam flooding，including the mixed gas-water flooding，surfactant flooding and foam flooding. The formation of the mixed gas-water flooding zone is due to the unstable defoaming of the foam，gas separation from the foam liquid and gas channeling. The foam fluid precipitated by the bursting of the bubble flows behind the gas and emulsifies the crude oil，and then the surfactant flooding zone is formed. The mixed gas-water flooding and surfactant flooding can reduce the residual oil saturation and ensure subsequently injected foam stable to play a role in the profile control and oil displacement，and then the foam flooding zone is formed. In the process of water flooding，foam flooding and subsequent water flooding，the sweep efficiency of the high-permeability zone of the heterogeneous microscopic model is increased from 52.4% to 100% and then decreased to 74.3%. The low-permeability zone is no longer effective after the swept area of the subsequent water flooding decreases and breaks through into high permeability zones，which means that the plugging effect of the foam flooding has an effective plugging period in the subsequent water flooding，and there are no plugging effect after the effective plugging period. In the process of parallel sand-packed pipe displacement experiment with the same permeability ratio，the change of the fluid diversion rates and oil displacement efficiency with water flooding，foam flooding and subsequent water flooding is consistent with the result of the microscopic displacement mechanism analysis，which further verifies the results of the displacement experiment with the heterogeneous microscopic model.
As a oil displacement agent，the foam has dual mechanisms，including the profile control and oil displacement.The heterogeneous microscopic model with the permeability ratio of 1∶3 and the parallel sand-packed pipe model are used to study the microscopic mechanism of the oil displacement and fluid flow diversion of the foam，and to evaluate the effect on oil displacement efficiency. The results of the displacement experiments using the heterogeneous microscopic model show that there are three significant percolation zones for the foam flooding，including the mixed gas-water flooding，surfactant flooding and foam flooding. The formation of the mixed gas-water flooding zone is due to the unstable defoaming of the foam，gas separation from the foam liquid and gas channeling. The foam fluid precipitated by the bursting of the bubble flows behind the gas and emulsifies the crude oil，and then the surfactant flooding zone is formed. The mixed gas-water flooding and surfactant flooding can reduce the residual oil saturation and ensure subsequently injected foam stable to play a role in the profile control and oil displacement，and then the foam flooding zone is formed. In the process of water flooding，foam flooding and subsequent water flooding，the sweep efficiency of the high-permeability zone of the heterogeneous microscopic model is increased from 52.4% to 100% and then decreased to 74.3%. The low-permeability zone is no longer effective after the swept area of the subsequent water flooding decreases and breaks through into high permeability zones，which means that the plugging effect of the foam flooding has an effective plugging period in the subsequent water flooding，and there are no plugging effect after the effective plugging period. In the process of parallel sand-packed pipe displacement experiment with the same permeability ratio，the change of the fluid diversion rates and oil displacement efficiency with water flooding，foam flooding and subsequent water flooding is consistent with the result of the microscopic displacement mechanism analysis，which further verifies the results of the displacement experiment with the heterogeneous microscopic model.
2020, 27(3):113-119.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.015
Abstract:
Block Fan142 in Zhenglizhuang Oilfield is a typical low porosity，extra-low permeability beach-bar sand reservoir with the rapid production decline and low recovery during the elastic development period. In order to study the feasibility of CO2 miscible flooding in the extra-low permeability beach-bar sand reservoirs，a pilot test was carried out in Well Group F142-7-X4 of the Block Fan142. The results show that CO2 has a good effect on reducing viscosity and swelling formation oil，which can dramatically improve oil recovery. By using numerical simulation，the formation pressure may be restored through the optimization design of CO2 flooding. The higher recovery and economic benefit of the well group may be obtained at the conditions of the inverted seven-point pattern，the cyclic injection and production，and maintaining formation pressure at 1.3MMP. The field test results show that CO2 has a good injection capacity and the formation pressure of the well group is significantly restored. A good stimulation performance is achieved. The oil exchange rate by gas injection of the well group at the miscible phase is 0.44 t/t and oil recovery factor of well group is increased by 6.2%. The CO2 miscible flooding is an effective means to improve the recovery of the extra-low permeability reservoirs.
Block Fan142 in Zhenglizhuang Oilfield is a typical low porosity，extra-low permeability beach-bar sand reservoir with the rapid production decline and low recovery during the elastic development period. In order to study the feasibility of CO2 miscible flooding in the extra-low permeability beach-bar sand reservoirs，a pilot test was carried out in Well Group F142-7-X4 of the Block Fan142. The results show that CO2 has a good effect on reducing viscosity and swelling formation oil，which can dramatically improve oil recovery. By using numerical simulation，the formation pressure may be restored through the optimization design of CO2 flooding. The higher recovery and economic benefit of the well group may be obtained at the conditions of the inverted seven-point pattern，the cyclic injection and production，and maintaining formation pressure at 1.3MMP. The field test results show that CO2 has a good injection capacity and the formation pressure of the well group is significantly restored. A good stimulation performance is achieved. The oil exchange rate by gas injection of the well group at the miscible phase is 0.44 t/t and oil recovery factor of well group is increased by 6.2%. The CO2 miscible flooding is an effective means to improve the recovery of the extra-low permeability reservoirs.
16 A new well test model for horizontal wells by stimulated reservoir volume in shale gas reservoirs
2020, 27(3):120-128.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.016
Abstract:
The stimulated reservoir volume has become a critical technology for the development of the unconventional oil and gas reservoirs. It is very important to propose well test models characterizing the complex fracture networks. Based on the assumption of orthogonal fracture networks，a new well test model is proposed for the horizontal wells by the stimulated reservoir volume considering the complex fracture networks. Laplace transformation is used to obtain the analytical solution of the model，and the solution is validated with the numerical simulation. The effect of fracture networks parameters on type curves is analyzed. The results show that the analytical model can successfully characterize the complex fracture networks，and the computation is precise，so the model is suitable for the well test analysis for the horizontal wells by the stimulated reservoir volume. There are five flow regimes for the horizontal wells by the stimulated reservoir volume：wellbore storage，linear flow in the artificial fractures，crossflow between the secondary fractures and artificial fractures，linear flow in the matrix and boundary-controlled flow respectively. The parameters of the fracture network have a great impact on characteristics of the type curves，and the different parameters have influence on the different flow regimes.
The stimulated reservoir volume has become a critical technology for the development of the unconventional oil and gas reservoirs. It is very important to propose well test models characterizing the complex fracture networks. Based on the assumption of orthogonal fracture networks，a new well test model is proposed for the horizontal wells by the stimulated reservoir volume considering the complex fracture networks. Laplace transformation is used to obtain the analytical solution of the model，and the solution is validated with the numerical simulation. The effect of fracture networks parameters on type curves is analyzed. The results show that the analytical model can successfully characterize the complex fracture networks，and the computation is precise，so the model is suitable for the well test analysis for the horizontal wells by the stimulated reservoir volume. There are five flow regimes for the horizontal wells by the stimulated reservoir volume：wellbore storage，linear flow in the artificial fractures，crossflow between the secondary fractures and artificial fractures，linear flow in the matrix and boundary-controlled flow respectively. The parameters of the fracture network have a great impact on characteristics of the type curves，and the different parameters have influence on the different flow regimes.
2020, 27(3):129-138.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.03.017
Abstract:
The development process of the temperature monitoring technology under the intelligent well completion (IWC)conditions，especially the latest research works of the theoretical models for the temperature monitoring technology，provides reference for further application and in-depth theoretical research of the downhole temperature monitoring technology.The mainstream temperature sensors currently used in oilfields include the permanent downhole electronic pressure/temperature sensors and distributed optical fiber temperature sensors. Due to the strong environmental adaptability and the distributed characteristics of temperature data，the distributed optical fiber temperature sensors have been more widely used. Six major application for the temperature monitoring technology include：gas lift monitoring，flow profile interpretation，gas-water coning diagnostics，heavy oil thermal recovery monitoring，stimulation monitoring and evaluation，and reservoir property inversion analysis and so on. The theoretical research works showed the rapid progresses in stimulation monitoring and evaluation as well as reservoir property inversion analysis. The transient temperature analysis has been established gradually.The temperature models for multi-stage，multi-cluster horizontal fractured well have also been improved greatly based on the conventional temperature model in fractured wells，which could be used for both temperature simulation and fracturing evaluation inversion.
The development process of the temperature monitoring technology under the intelligent well completion (IWC)conditions，especially the latest research works of the theoretical models for the temperature monitoring technology，provides reference for further application and in-depth theoretical research of the downhole temperature monitoring technology.The mainstream temperature sensors currently used in oilfields include the permanent downhole electronic pressure/temperature sensors and distributed optical fiber temperature sensors. Due to the strong environmental adaptability and the distributed characteristics of temperature data，the distributed optical fiber temperature sensors have been more widely used. Six major application for the temperature monitoring technology include：gas lift monitoring，flow profile interpretation，gas-water coning diagnostics，heavy oil thermal recovery monitoring，stimulation monitoring and evaluation，and reservoir property inversion analysis and so on. The theoretical research works showed the rapid progresses in stimulation monitoring and evaluation as well as reservoir property inversion analysis. The transient temperature analysis has been established gradually.The temperature models for multi-stage，multi-cluster horizontal fractured well have also been improved greatly based on the conventional temperature model in fractured wells，which could be used for both temperature simulation and fracturing evaluation inversion.
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