Volume 26,Issue 2,2019 Table of Contents
2019, 26(2):1-6.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.001
Abstract:
Under the background of development strategy of energy revolution and low price，sustainable development in old oilfields is facing multiple challenges such as new energy extrusion，energy-saving and emission-reduction requirements，and low-cost development，etc. Based on systematic analysis on issues and challenges，new concept of green lowcost development of old oilfields was proposed，its connotation is to reduce the energy consumption in the process of producing crude oil as the key，and through co-optimizing the subsystem and multi-factors，to realize the lowest energy consumption and cost of unit oil and gas under the certain conditions of oil and gas production. Starting from the relationship between material and energy transformation，an integrated optimization model of production，energy consumption，cost and environment was proposed，and the green low-cost development mode was proposed for various types of oil reservoirs，various displacement media，various development methods and various development stages. It was applied to various types of oil reservoir as well. The practice shows that the green low-cost development is an effective way for the sustainable development in old oilfields.
Under the background of development strategy of energy revolution and low price，sustainable development in old oilfields is facing multiple challenges such as new energy extrusion，energy-saving and emission-reduction requirements，and low-cost development，etc. Based on systematic analysis on issues and challenges，new concept of green lowcost development of old oilfields was proposed，its connotation is to reduce the energy consumption in the process of producing crude oil as the key，and through co-optimizing the subsystem and multi-factors，to realize the lowest energy consumption and cost of unit oil and gas under the certain conditions of oil and gas production. Starting from the relationship between material and energy transformation，an integrated optimization model of production，energy consumption，cost and environment was proposed，and the green low-cost development mode was proposed for various types of oil reservoirs，various displacement media，various development methods and various development stages. It was applied to various types of oil reservoir as well. The practice shows that the green low-cost development is an effective way for the sustainable development in old oilfields.
2019, 26(2):7-13.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.002
Abstract:
Shale gas is a new type of efficient and clean energy. It has the feature of“self-generation and self-accumulation”，and it is hosted in organic-rich shale in various forms such as free gas，absorbed gas and solution gas. According to geochemical，well logging，mud logging and other data，the shale gas forming conditions in Shandong Province are systematically analyzed. It is believed that the marine-continental transitional shale with typeⅡ-Ⅲkerogen in Upper Paleozoic Shanxi-Taiyuan Formation，the lacustrine shale with typeⅡ-Ⅲ kerogen in the 2nd member of Kongdian Formation in Cenozoic，and the lacustrine shale with typeⅠ-Ⅱkerogen type in the 3rd member and the 4th member of Shahejie Formation in Cenozoic are favorable exploration strata of shale gas resources in Shandong Province. Based on the on-site desorption gas data extracted from the parameter wells，shale gas content calculation models suitable for Shandong Province are proposed，the total organic carbon is used to estimate the gas content of lacustrine facies and marine-continental transitional facies shale with typeⅡ-Ⅲ kerogen，and the gas/oil ratio is used to estimate the gas content of lacustrine shale with typeⅠ-Ⅱ kerogen. According to the identified key parameters of shale gas resource evaluation，the resources of favorable shale gas area in Shandong Province is estimated to be 1.42×1012 m3.
Shale gas is a new type of efficient and clean energy. It has the feature of“self-generation and self-accumulation”，and it is hosted in organic-rich shale in various forms such as free gas，absorbed gas and solution gas. According to geochemical，well logging，mud logging and other data，the shale gas forming conditions in Shandong Province are systematically analyzed. It is believed that the marine-continental transitional shale with typeⅡ-Ⅲkerogen in Upper Paleozoic Shanxi-Taiyuan Formation，the lacustrine shale with typeⅡ-Ⅲ kerogen in the 2nd member of Kongdian Formation in Cenozoic，and the lacustrine shale with typeⅠ-Ⅱkerogen type in the 3rd member and the 4th member of Shahejie Formation in Cenozoic are favorable exploration strata of shale gas resources in Shandong Province. Based on the on-site desorption gas data extracted from the parameter wells，shale gas content calculation models suitable for Shandong Province are proposed，the total organic carbon is used to estimate the gas content of lacustrine facies and marine-continental transitional facies shale with typeⅡ-Ⅲ kerogen，and the gas/oil ratio is used to estimate the gas content of lacustrine shale with typeⅠ-Ⅱ kerogen. According to the identified key parameters of shale gas resource evaluation，the resources of favorable shale gas area in Shandong Province is estimated to be 1.42×1012 m3.
2019, 26(2):14-23.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.003
Abstract:
A set of organic-rich shale formation developed in the Late Ordovician-Early Silurian in Dingshan area，southeastern Sichuan Basin. According to the drilled wells，it is revealed that this area has good shale gas exploration and development prospects. However，the exploration gas test results after fracturing in the exploratory wells differ significantly. The “six properties”，known as the gas reservoir organic geochemistry，the gas-bearing property，the lithology and mineral composition，the brittleness（fractability），the physical properties and the heterogeneity（anisotropy），and the sedimentary environment of the Wufeng-Longmaxi Formation were studied by means of radioactive elements logging，organic geochemistry analysis，core description，whole rock X-ray diffraction，scanning electron microscope，physical property test，field gas content test，etc. The results show that the shale sedimentary environment of Wufeng-Longmaxi Formation is marine anoxic reduction environment，based on the results of radioactive elements（Th/U<7，V/Ni>1.0 and V（/ V+Ni）>0.56）. From the top to the bottom，the shale lithology changes from gray black silty limestone and clay to black anoxic shale that is rich in carbonaceous and graptolite，accompanied with an increasing trend in brittle mineral content，TOC，Ro and gas content. At the bottom of the target shale layer，the brittleness index is higher than 50%；the TOC is larger than 2%；the Ro is higher than 2%，the gas content is more than 3 m3/t；and the organic matter type is mainly type I kerogen，which is generally in the late mature stage and the post mature stage. The porosity of inorganic matter is generally smaller than that of organic matter，and the vertical permeability is much smaller than the horizontal permeability in different formation conditions. An anoxic and occlusive reduction environment is the basis for the enrichment of organic matter. A good preservation condition is the key to shale gas accumulation.
A set of organic-rich shale formation developed in the Late Ordovician-Early Silurian in Dingshan area，southeastern Sichuan Basin. According to the drilled wells，it is revealed that this area has good shale gas exploration and development prospects. However，the exploration gas test results after fracturing in the exploratory wells differ significantly. The “six properties”，known as the gas reservoir organic geochemistry，the gas-bearing property，the lithology and mineral composition，the brittleness（fractability），the physical properties and the heterogeneity（anisotropy），and the sedimentary environment of the Wufeng-Longmaxi Formation were studied by means of radioactive elements logging，organic geochemistry analysis，core description，whole rock X-ray diffraction，scanning electron microscope，physical property test，field gas content test，etc. The results show that the shale sedimentary environment of Wufeng-Longmaxi Formation is marine anoxic reduction environment，based on the results of radioactive elements（Th/U<7，V/Ni>1.0 and V（/ V+Ni）>0.56）. From the top to the bottom，the shale lithology changes from gray black silty limestone and clay to black anoxic shale that is rich in carbonaceous and graptolite，accompanied with an increasing trend in brittle mineral content，TOC，Ro and gas content. At the bottom of the target shale layer，the brittleness index is higher than 50%；the TOC is larger than 2%；the Ro is higher than 2%，the gas content is more than 3 m3/t；and the organic matter type is mainly type I kerogen，which is generally in the late mature stage and the post mature stage. The porosity of inorganic matter is generally smaller than that of organic matter，and the vertical permeability is much smaller than the horizontal permeability in different formation conditions. An anoxic and occlusive reduction environment is the basis for the enrichment of organic matter. A good preservation condition is the key to shale gas accumulation.
2019, 26(2):24-31.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.004
Abstract:
Dingshan area is a hot field in the exploration and development of shale gas in Southeastern Sichuan in recent years，preservation conditions are important for the accumulation of shale gas after its generation. Through the analysis of structure factors such as fracture characteristics，structure location and shape，and other non-tectonic factors such as shale gas roof and floor condition，depth and formation pressure coefficient，hydrogeology and gas composition，the shale gas preservation condition was analyzed in the study area. The results show that the preservation condition of Dingshan area has obvious zoning characteristic. The shale stratus close to Qiyueshan buried fault are characterized by poor preservation conditions with shallow depth and small formation pressure coefficient. The shale stratus far to Qiyueshan fault are characterized by good preservation conditions with moderate depth and high stratigraphic pressure. Structure location and fracture development characteristics are the most important factors restricting the shale gas preservation in Dingshan area. Structure location determines the fracture development and formation pressure coefficient. Fault strike and its direction to the maximum horizontal principal stress determine the sealing and hydrogeological conditions of the formation. The shale stratus far away from Qiyueshan buried fault are dominated by thrust faults，and their angle with the maximum horizontal principal stress are mainly more than 45°，which can effectively suppress the vertical escape of shale gas. Faults are extensively developed close to Qiyueshan buried fault and they cut through the upper and bottom strata，which facilitate the vertical dissipation of shale gas，and lead to a poor preservation condition.
Dingshan area is a hot field in the exploration and development of shale gas in Southeastern Sichuan in recent years，preservation conditions are important for the accumulation of shale gas after its generation. Through the analysis of structure factors such as fracture characteristics，structure location and shape，and other non-tectonic factors such as shale gas roof and floor condition，depth and formation pressure coefficient，hydrogeology and gas composition，the shale gas preservation condition was analyzed in the study area. The results show that the preservation condition of Dingshan area has obvious zoning characteristic. The shale stratus close to Qiyueshan buried fault are characterized by poor preservation conditions with shallow depth and small formation pressure coefficient. The shale stratus far to Qiyueshan fault are characterized by good preservation conditions with moderate depth and high stratigraphic pressure. Structure location and fracture development characteristics are the most important factors restricting the shale gas preservation in Dingshan area. Structure location determines the fracture development and formation pressure coefficient. Fault strike and its direction to the maximum horizontal principal stress determine the sealing and hydrogeological conditions of the formation. The shale stratus far away from Qiyueshan buried fault are dominated by thrust faults，and their angle with the maximum horizontal principal stress are mainly more than 45°，which can effectively suppress the vertical escape of shale gas. Faults are extensively developed close to Qiyueshan buried fault and they cut through the upper and bottom strata，which facilitate the vertical dissipation of shale gas，and lead to a poor preservation condition.
2019, 26(2):32-41.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.005
Abstract:
Tight sandstone are formed in various sedimentary environment，the relationship between porosity and permeability of tight sandstone is complex，and the pore throat structure is the key parameter for reservoir characterization and evaluation. Taking Paleogene tight sandstone in Jiyang Depression as an example，the petrologic features and pore throat structures of different sedimentary types were studied and then the classification scheme of tight sandstone based on petrologic features and pore throat structure characteristics was proposed by means of systematic cluster analysis. Results indicate that petrologic features and pore throat structure of turbidity sandstone，beach-bar sandstone and delta-front sandstone are similar. The average pore throat radius of type Ⅰ best reservoir，type Ⅱ good reservoir，type Ⅲ normal reservoir and type Ⅳ worst reservoir are greater than 1.1，0.7-1.1，0.4-0.7，less than 0.4 μm，respectively. The sandstone with pore throat radius less than 0.3 μm cannot be regarded as reservoir. The tight glutenite is obviously different from the former three types of tight sandstone，for tight glutenite，the average pore throat radius of type Ⅰ best reservoir，type Ⅱ good reservoir，type Ⅲ normal reservoir and type Ⅳ worst reservoir satisfies greater than 1.3，0.8-1.3，0.3-0.8，less than 0.3 μm，respectively.
Tight sandstone are formed in various sedimentary environment，the relationship between porosity and permeability of tight sandstone is complex，and the pore throat structure is the key parameter for reservoir characterization and evaluation. Taking Paleogene tight sandstone in Jiyang Depression as an example，the petrologic features and pore throat structures of different sedimentary types were studied and then the classification scheme of tight sandstone based on petrologic features and pore throat structure characteristics was proposed by means of systematic cluster analysis. Results indicate that petrologic features and pore throat structure of turbidity sandstone，beach-bar sandstone and delta-front sandstone are similar. The average pore throat radius of type Ⅰ best reservoir，type Ⅱ good reservoir，type Ⅲ normal reservoir and type Ⅳ worst reservoir are greater than 1.1，0.7-1.1，0.4-0.7，less than 0.4 μm，respectively. The sandstone with pore throat radius less than 0.3 μm cannot be regarded as reservoir. The tight glutenite is obviously different from the former three types of tight sandstone，for tight glutenite，the average pore throat radius of type Ⅰ best reservoir，type Ⅱ good reservoir，type Ⅲ normal reservoir and type Ⅳ worst reservoir satisfies greater than 1.3，0.8-1.3，0.3-0.8，less than 0.3 μm，respectively.
2019, 26(2):42-50.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.006
Abstract:
Hangjinqi area of Ordos Basin is a key research area for tight gas exploration，and the Lower Shihezi Formation is mainly lithic sandstone which is a typical low-porosity and extra-low-permeability reservoir. According to the analysis results of cast thin section observation，cathodoluminescence，SEM，capillary pressure test，X-diffraction of clay minerals and porosity and permeability，the main types of diagenesis and its characteristics of the tight sandstone reservoir in the Lower Shihezi Formation in Hangjinqi area of Ordos Basin were studied. And the evolution sequence of diagenesis was established and its effects on pore development were analyzed. A quantitative model for porosity evolution was constructed.The results show that the tight sandstone reservoir with secondary pores and microfracture is the main storage space in the Lower Shihezi Formation of the study area. There are various types of diagenesis in the Lower Shihezi Formation，which mainly include compaction，cementation，metasomatic alteration and dissolution. The compaction is the main factor causing great loss of primary pores，and the decrease of porosity is about 20.25%；the cementation destroys the physical properties of the reservoir. The early and the late cementation result in a decrease in porosity of about 5.58% and 6.06%，respectively.The secondary pores formed by dissolution leads to an increase in porosity of about 5.20%.
Hangjinqi area of Ordos Basin is a key research area for tight gas exploration，and the Lower Shihezi Formation is mainly lithic sandstone which is a typical low-porosity and extra-low-permeability reservoir. According to the analysis results of cast thin section observation，cathodoluminescence，SEM，capillary pressure test，X-diffraction of clay minerals and porosity and permeability，the main types of diagenesis and its characteristics of the tight sandstone reservoir in the Lower Shihezi Formation in Hangjinqi area of Ordos Basin were studied. And the evolution sequence of diagenesis was established and its effects on pore development were analyzed. A quantitative model for porosity evolution was constructed.The results show that the tight sandstone reservoir with secondary pores and microfracture is the main storage space in the Lower Shihezi Formation of the study area. There are various types of diagenesis in the Lower Shihezi Formation，which mainly include compaction，cementation，metasomatic alteration and dissolution. The compaction is the main factor causing great loss of primary pores，and the decrease of porosity is about 20.25%；the cementation destroys the physical properties of the reservoir. The early and the late cementation result in a decrease in porosity of about 5.58% and 6.06%，respectively.The secondary pores formed by dissolution leads to an increase in porosity of about 5.20%.
2019, 26(2):51-59.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.007
Abstract:
The mid-high permeability sandstone reservoir has been in the late stage of ultra-high water cut after several decades of water flooding. The high water consumption zone with strong water absorption and low displacement efficiency were inevitably formed in the sandstone reservoirs，moreover formed only at a specific position of single sandbody. It has been difficult for regarding the geological analysis of single sand body as the research unit to meet the needs of residual oil excavation in such reservoirs. Based on the lithofacies analysis of core and outcrop，the development geological research unit was refined into the lithofacies combination grade with lithology as the main controlling factor，and the conventional logging data of the lithofacies combination were interpreted geologically by the grey correlation analysis method. Based on the well data，the lithofacies modes of the composite mouth sand bars and the single sand bodies in No.8 sand group of the second member of Shahejie Formation were summarized in the south of Tuo11 area. Combining with the seepage characteristics of the reservoir，it was concluded from the standpoint of static geological factors that the high water consumption zone would develop in the superposition mode of bar Ⅱ-bar Ⅱ in the composite sand bodies，and in the middle part of the lobe body of the single main bar Ⅱ mode in the single sand body，and the development position of the high water consumption zone corresponds to that of the bar Ⅱ in vertical direction.
The mid-high permeability sandstone reservoir has been in the late stage of ultra-high water cut after several decades of water flooding. The high water consumption zone with strong water absorption and low displacement efficiency were inevitably formed in the sandstone reservoirs，moreover formed only at a specific position of single sandbody. It has been difficult for regarding the geological analysis of single sand body as the research unit to meet the needs of residual oil excavation in such reservoirs. Based on the lithofacies analysis of core and outcrop，the development geological research unit was refined into the lithofacies combination grade with lithology as the main controlling factor，and the conventional logging data of the lithofacies combination were interpreted geologically by the grey correlation analysis method. Based on the well data，the lithofacies modes of the composite mouth sand bars and the single sand bodies in No.8 sand group of the second member of Shahejie Formation were summarized in the south of Tuo11 area. Combining with the seepage characteristics of the reservoir，it was concluded from the standpoint of static geological factors that the high water consumption zone would develop in the superposition mode of bar Ⅱ-bar Ⅱ in the composite sand bodies，and in the middle part of the lobe body of the single main bar Ⅱ mode in the single sand body，and the development position of the high water consumption zone corresponds to that of the bar Ⅱ in vertical direction.
2019, 26(2):60-67.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.008
Abstract:
In order to clarify the influence of original sedimentary components and water environment on diagenetic evolution of clastic reservoirs，the 3rd member of Shahejie Formation of Paleogene in Bonan Sag，Jiyang Depression was analyzed with drilling，logging and a large number of testing data in detail. The results show that the lowstand systems tract of the 3rd member of Shahejie Formation in Bonan Sag is in a near-subaqueous and brackish water sedimentary environment. The clastic reservoir is rich in carbonate rock debris and has low resistance to compaction. In addition，the brackish water environment makes it undergo strong compaction and cementation diagenesis in the early diagenetic stage. The primary porosity of reservoir decreases rapidly and there is not enough space to accommodate organic acids in the middle diagenetic stage.The acid dissolution is weak and the reservoir physical properties are poor at present. The highstand systems tract of the 3rd member of Shahejie Formation in Bonan Sag is a long-distance and freshwater sedimentary environment. Clastic reservoir is dominated by quartz particles and has high resistance to compaction. In addition，the freshwater environment makes it undergo weak compaction and cementation diagenesis in the early diagenetic stage. So the primary porosity of reservoir declines slowly. The reservoir experiences strong acid corrosion in the middle stage of diagenesis and the reservoir physical properties are good at present. The original sedimentary components and water environment are the essential factors leading to the differences in diagenetic evolution of the clastic reservoirs.
In order to clarify the influence of original sedimentary components and water environment on diagenetic evolution of clastic reservoirs，the 3rd member of Shahejie Formation of Paleogene in Bonan Sag，Jiyang Depression was analyzed with drilling，logging and a large number of testing data in detail. The results show that the lowstand systems tract of the 3rd member of Shahejie Formation in Bonan Sag is in a near-subaqueous and brackish water sedimentary environment. The clastic reservoir is rich in carbonate rock debris and has low resistance to compaction. In addition，the brackish water environment makes it undergo strong compaction and cementation diagenesis in the early diagenetic stage. The primary porosity of reservoir decreases rapidly and there is not enough space to accommodate organic acids in the middle diagenetic stage.The acid dissolution is weak and the reservoir physical properties are poor at present. The highstand systems tract of the 3rd member of Shahejie Formation in Bonan Sag is a long-distance and freshwater sedimentary environment. Clastic reservoir is dominated by quartz particles and has high resistance to compaction. In addition，the freshwater environment makes it undergo weak compaction and cementation diagenesis in the early diagenetic stage. So the primary porosity of reservoir declines slowly. The reservoir experiences strong acid corrosion in the middle stage of diagenesis and the reservoir physical properties are good at present. The original sedimentary components and water environment are the essential factors leading to the differences in diagenetic evolution of the clastic reservoirs.
2019, 26(2):68-75.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.009
Abstract:
The small layers 54-68 in the upper section of Guantao Formation in No.6 Block of Gudong Oilfield are braided river deposits that have complex architecture. At present，this oilfield has faced several problems including extra-high water cut，high distribution of remaining oil，difficulties in stable production. Therefore，the key to solving those problems is to carry out fine anatomy of the reservoir architecture. The fine architecture characterization of the inner part of the sandy braid bar is taken as the entry point. The internal architecture of the sandy braid bar in the upper section of Guantao Formation in No.6 Block of Gudong Oilfield was analyzed. Combined with the characteristics of sedimentary microfacies of the sandy braided river of Gudong Oilfield，the different hierarchical levels of architecture interfaces in the sandy braided-river reservoirs were identified. Based on the well correction in dense pattern，the quantitative characterization of the scale of the reproduction body in the braid bar of the braided-river reservoir was realized. The range of parameters for four-grade architecture was determined. Among them，width is 100-350 m，length is 400-500 m，thickness is 4-12 m of the braid bar.The length of the braid bar has positive correlation with the width of the braid bar，and the width of the braid has almost positive correlation with the thickness of the braid bar. The range of parameters for three-grade architecture of the off-silt and accretion body was determined. The average dip of the off-silt at the head of bar is 0.93° and that at the end is 0.53° and that at two wings is 1.47°，and the length of single accretion body in the braid bar at direction of long axis is from 280 to 800 meters，and its width is from 165 to 400 meters. The width of the the off-silt may be from 250 to 700 meters and its length may be from 150 to 350 meters.
The small layers 54-68 in the upper section of Guantao Formation in No.6 Block of Gudong Oilfield are braided river deposits that have complex architecture. At present，this oilfield has faced several problems including extra-high water cut，high distribution of remaining oil，difficulties in stable production. Therefore，the key to solving those problems is to carry out fine anatomy of the reservoir architecture. The fine architecture characterization of the inner part of the sandy braid bar is taken as the entry point. The internal architecture of the sandy braid bar in the upper section of Guantao Formation in No.6 Block of Gudong Oilfield was analyzed. Combined with the characteristics of sedimentary microfacies of the sandy braided river of Gudong Oilfield，the different hierarchical levels of architecture interfaces in the sandy braided-river reservoirs were identified. Based on the well correction in dense pattern，the quantitative characterization of the scale of the reproduction body in the braid bar of the braided-river reservoir was realized. The range of parameters for four-grade architecture was determined. Among them，width is 100-350 m，length is 400-500 m，thickness is 4-12 m of the braid bar.The length of the braid bar has positive correlation with the width of the braid bar，and the width of the braid has almost positive correlation with the thickness of the braid bar. The range of parameters for three-grade architecture of the off-silt and accretion body was determined. The average dip of the off-silt at the head of bar is 0.93° and that at the end is 0.53° and that at two wings is 1.47°，and the length of single accretion body in the braid bar at direction of long axis is from 280 to 800 meters，and its width is from 165 to 400 meters. The width of the the off-silt may be from 250 to 700 meters and its length may be from 150 to 350 meters.
2019, 26(2):76-80.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.010
Abstract:
When the adsorption experiment is carried out by using weighing method，the total mass mt at a test pressure point is composed by four parts，which are the mass of the test barrel mb，the mass of the core sample mc，the adsorbed methane gas mag and the free methane gas mfg in the void volume of the test barrel. And the mass of the injected methane gas mi only includes two parts，mag and mfg. Since the mass of the sample barrel and the mass of the sample loaded into the sample barrel are constant，this provides convenience for establishing a method for calculating the isothermal adsorption capacity by the weighing adsorption apparatus. Based on the principle of mass balance and Avogadro’s law，the method of calculating isothermal adsorption capacity using the data tested by the weighing adsorption apparatus was theoretically derived.Meanwhile，a criteria for judging adsorption degree，determining the saturated adsorption pressure and the saturated cumulative adsorption capacity was proposed. The application of shale gas and coalbed methane adsorption showed that the said method was correct and effective.
When the adsorption experiment is carried out by using weighing method，the total mass mt at a test pressure point is composed by four parts，which are the mass of the test barrel mb，the mass of the core sample mc，the adsorbed methane gas mag and the free methane gas mfg in the void volume of the test barrel. And the mass of the injected methane gas mi only includes two parts，mag and mfg. Since the mass of the sample barrel and the mass of the sample loaded into the sample barrel are constant，this provides convenience for establishing a method for calculating the isothermal adsorption capacity by the weighing adsorption apparatus. Based on the principle of mass balance and Avogadro’s law，the method of calculating isothermal adsorption capacity using the data tested by the weighing adsorption apparatus was theoretically derived.Meanwhile，a criteria for judging adsorption degree，determining the saturated adsorption pressure and the saturated cumulative adsorption capacity was proposed. The application of shale gas and coalbed methane adsorption showed that the said method was correct and effective.
2019, 26(2):81-86.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.011
Abstract:
The automatic gas content apparatus was independently developed with no-pressure resistance and micro-pressure loss. It can not only continuously measure the content of shale gas，but also have the function of detecting methane concentration. Shale gas content at the well site was measured by this device in Southeast Chongqing.Continuous detection of desorbed gas composition was conducted for the first time，and it was found that the desorption of shale gas had unique characteristics. A“three-stage”variation type of gas desorption was obtained after core being sealed. In the early period（the first 3 hours），the methane concentration increased rapidly；and it became stable in the mid period（the next three to ten hours）；in the late period（from the tenth hour to the end），it decreased sharply with fluctuations. The shale gas desorption is a progressive process from the external to the internal，from fractures and large pores to microfractures，micropores and matrix of the shale. The released shale gas in the early stage was mostly from fractures or well-connected macropores，and the free gas was the main part. In the mid stage，the shale gas adsorbed in microfractures or macropores and that in mesopores with semi-connectivity and some micropores began to release，and the free gas and adsorption gas were the main part. In the late stage，the adsorbed and bounded gas desorbed from pores with poor connectivity and micropores，and the adsorption gas occupied the major part of the shale gas.
The automatic gas content apparatus was independently developed with no-pressure resistance and micro-pressure loss. It can not only continuously measure the content of shale gas，but also have the function of detecting methane concentration. Shale gas content at the well site was measured by this device in Southeast Chongqing.Continuous detection of desorbed gas composition was conducted for the first time，and it was found that the desorption of shale gas had unique characteristics. A“three-stage”variation type of gas desorption was obtained after core being sealed. In the early period（the first 3 hours），the methane concentration increased rapidly；and it became stable in the mid period（the next three to ten hours）；in the late period（from the tenth hour to the end），it decreased sharply with fluctuations. The shale gas desorption is a progressive process from the external to the internal，from fractures and large pores to microfractures，micropores and matrix of the shale. The released shale gas in the early stage was mostly from fractures or well-connected macropores，and the free gas was the main part. In the mid stage，the shale gas adsorbed in microfractures or macropores and that in mesopores with semi-connectivity and some micropores began to release，and the free gas and adsorption gas were the main part. In the late stage，the adsorbed and bounded gas desorbed from pores with poor connectivity and micropores，and the adsorption gas occupied the major part of the shale gas.
2019, 26(2):87-93.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.012
Abstract:
Volumetric method and gravimetric method are two important methods for shale gas adsorption experiment. Compared with the gravimetric method based on magnetic suspension balance（MSB），the instrument of volumetric method has simple structure and principle，and low cost. The volumetric method is the main means to evaluate the shale gas adsorption experiments in China. However，the biggest problem of the volumetric method is that the calculation of the gas compressibility factor is inaccurate，especially when this method is used to calculate the adsorption amount at high pressure. In order to solve this problem，the compressibility factors of seven complex gas state equations were calculated through programming，and the calculated results were compared with those calculated in the Chemistry part of NIST database in USA. The results show that the gas compressibility factor calculated by the Setzmann equation is accurate at both high and low pressures， which solves the shortage of the volumetric method at high pressure. The actual shale gas isotherm data was interpreted by the volumetric method and the improved volumetric method respectively. The result shows that when the equilibrium pressure exceeds 5 MPa，the adsorption amount difference increases with the increase of equilibrium pressure，the maximum adsorption amount difference is 0.426 5 mL/g at equilibrium pressure of about 30 MPa，which indicates the importance of accurate calculating the gas compressibility factor. The adsorption isotherm of the shale gas was fitted by the adsorption theory model. The results show that Toth adsorption model has the highest accuracy.
Volumetric method and gravimetric method are two important methods for shale gas adsorption experiment. Compared with the gravimetric method based on magnetic suspension balance（MSB），the instrument of volumetric method has simple structure and principle，and low cost. The volumetric method is the main means to evaluate the shale gas adsorption experiments in China. However，the biggest problem of the volumetric method is that the calculation of the gas compressibility factor is inaccurate，especially when this method is used to calculate the adsorption amount at high pressure. In order to solve this problem，the compressibility factors of seven complex gas state equations were calculated through programming，and the calculated results were compared with those calculated in the Chemistry part of NIST database in USA. The results show that the gas compressibility factor calculated by the Setzmann equation is accurate at both high and low pressures， which solves the shortage of the volumetric method at high pressure. The actual shale gas isotherm data was interpreted by the volumetric method and the improved volumetric method respectively. The result shows that when the equilibrium pressure exceeds 5 MPa，the adsorption amount difference increases with the increase of equilibrium pressure，the maximum adsorption amount difference is 0.426 5 mL/g at equilibrium pressure of about 30 MPa，which indicates the importance of accurate calculating the gas compressibility factor. The adsorption isotherm of the shale gas was fitted by the adsorption theory model. The results show that Toth adsorption model has the highest accuracy.
2019, 26(2):94-100.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.013
Abstract:
The nitrogen foam profile control and displacement technique is widely used in oil recovery，water control，and other enhanced oil recovery measures because of its characteristics of adjusting the fluid production profile and reducing the water cut. In order to furtherly clarify the applicable limit of nitrogen foam profile control and flooding system in medium porosity and medium permeability reservoir and to determine the best flooding time，the effect of the enhanced nitrogen foam on cores with various permeability ratios was evaluated，and the influence of heterogeneity and flooding time on profile control and displacement of the nitrogen foam system was analyzed by laboratory experiments. The experimental results show that for the medium porosity and medium permeability reservoir，the system has a better effect on water control and stable oil production，and the recovery efficiency by nitrogen foam flooding can be increased by more than 18%compared with that by water flooding when the permeability ratio is in the range of 2-6；among them，the recovery efficiency is the highest（20.0%）when the permeability ratio is 6. The production profile will be improved when the permeability ratio is about 3，and the diversion rate can be effectively controlled at 0.25 PV. When the water cut of the produced fluid is 80%，it is the best time for nitrogen foam flooding. The experimental results of enhanced nitrogen foam flooding for the reservoir adaptability can provide guidance for the optimization of water control and oil production increase measures and the design of foam flooding scheme in oilfield.
The nitrogen foam profile control and displacement technique is widely used in oil recovery，water control，and other enhanced oil recovery measures because of its characteristics of adjusting the fluid production profile and reducing the water cut. In order to furtherly clarify the applicable limit of nitrogen foam profile control and flooding system in medium porosity and medium permeability reservoir and to determine the best flooding time，the effect of the enhanced nitrogen foam on cores with various permeability ratios was evaluated，and the influence of heterogeneity and flooding time on profile control and displacement of the nitrogen foam system was analyzed by laboratory experiments. The experimental results show that for the medium porosity and medium permeability reservoir，the system has a better effect on water control and stable oil production，and the recovery efficiency by nitrogen foam flooding can be increased by more than 18%compared with that by water flooding when the permeability ratio is in the range of 2-6；among them，the recovery efficiency is the highest（20.0%）when the permeability ratio is 6. The production profile will be improved when the permeability ratio is about 3，and the diversion rate can be effectively controlled at 0.25 PV. When the water cut of the produced fluid is 80%，it is the best time for nitrogen foam flooding. The experimental results of enhanced nitrogen foam flooding for the reservoir adaptability can provide guidance for the optimization of water control and oil production increase measures and the design of foam flooding scheme in oilfield.
2019, 26(2):101-105.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.014
Abstract:
Paralleled cores flooding experiments were carried out to evaluate effect of foam flooding after polymer flooding under different water cut. The experimental results showed that polymer flooding followed by 0.3 PV foam slug could improve additiona l9.9% oil recovery. The larger size of foam slug was，the more enhanced oil recovery could reach. The oil recovery in the polymer flooding followed by more 0.5 PV foam slug increased by 6.9% than that in the polymer flooding followed by 0.3 PV foam slug，or 16.3% more than that in the polymer flooding only. When the foam was injected at different high water cut stage after early polymer flooding，the higher the water cut was，the greater the oil recovery increased. Followed by same foam slug injection size（0.3 PV），when 85% and 98% water cut was reached respectively，it was found that oil recovery in the polymer flooding could increase by 9.9% more. The results showed that the water cut stage had an important influence on the stability of the foam. The later foam was injected，the weaker crude oil defoaming effect was in the high permeability layers，the foam would be more stable and stronger，effective time of resistance retaining would be longer，the low permeability layers would be better exploited.
Paralleled cores flooding experiments were carried out to evaluate effect of foam flooding after polymer flooding under different water cut. The experimental results showed that polymer flooding followed by 0.3 PV foam slug could improve additiona l9.9% oil recovery. The larger size of foam slug was，the more enhanced oil recovery could reach. The oil recovery in the polymer flooding followed by more 0.5 PV foam slug increased by 6.9% than that in the polymer flooding followed by 0.3 PV foam slug，or 16.3% more than that in the polymer flooding only. When the foam was injected at different high water cut stage after early polymer flooding，the higher the water cut was，the greater the oil recovery increased. Followed by same foam slug injection size（0.3 PV），when 85% and 98% water cut was reached respectively，it was found that oil recovery in the polymer flooding could increase by 9.9% more. The results showed that the water cut stage had an important influence on the stability of the foam. The later foam was injected，the weaker crude oil defoaming effect was in the high permeability layers，the foam would be more stable and stronger，effective time of resistance retaining would be longer，the low permeability layers would be better exploited.
2019, 26(2):106-112.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.015
Abstract:
Aiming at the practical problems of high reservoir temperature，high salinity of formation water，high concentration of divalent cations of calcium and magnesium and high viscosity of formation crude oil in Shengli Oilfield，a novel polymer flooding system with strong tolerance to temperature，salinity，calcium and magnesium was designed to meet the needs of mobility control in polymer flooding in Class III of high-temperature and high-salinity heavy oil reservoirs. Based on the property evaluation of conventional polymers，a new property evaluation for the novel temperature-resistant and salt-tolerant polymer flooding system was improved，and the seepage law of the novel polymer in the core was summarized. Besides，the mobility control simulation of the novel polymer flooding was carried out by reservoir numerical simulation. Physical simulation experiment results show that the ability of resistance of the novel polymer to Ca2+and Mg2+was above 800 mg/L and the enhanced oil recovery by the physical simulation was more than 15.0%. Under the guidance of the reasonable mobility ratio limits，the enhanced oil recovery by the numerical simulation was 7.0%. A pilot test of polymer flooding was carried out in No.4 unit of Dong3 member in No.2 area of Shengtuo Oilfield. The composite water cut was decreased from 96.5% to 88.4% and the daily oil production was increased from 86 t/d to 273 t/d，which shows significant water cut decrease and oil production increase.
Aiming at the practical problems of high reservoir temperature，high salinity of formation water，high concentration of divalent cations of calcium and magnesium and high viscosity of formation crude oil in Shengli Oilfield，a novel polymer flooding system with strong tolerance to temperature，salinity，calcium and magnesium was designed to meet the needs of mobility control in polymer flooding in Class III of high-temperature and high-salinity heavy oil reservoirs. Based on the property evaluation of conventional polymers，a new property evaluation for the novel temperature-resistant and salt-tolerant polymer flooding system was improved，and the seepage law of the novel polymer in the core was summarized. Besides，the mobility control simulation of the novel polymer flooding was carried out by reservoir numerical simulation. Physical simulation experiment results show that the ability of resistance of the novel polymer to Ca2+and Mg2+was above 800 mg/L and the enhanced oil recovery by the physical simulation was more than 15.0%. Under the guidance of the reasonable mobility ratio limits，the enhanced oil recovery by the numerical simulation was 7.0%. A pilot test of polymer flooding was carried out in No.4 unit of Dong3 member in No.2 area of Shengtuo Oilfield. The composite water cut was decreased from 96.5% to 88.4% and the daily oil production was increased from 86 t/d to 273 t/d，which shows significant water cut decrease and oil production increase.
2019, 26(2):113-119.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.016
Abstract:
The three-dimensional anisotropy of actual reservoirs and the typical linear flow characteristics in horizontal well seepage are not considered in commonly used horizontal well productivity prediction formula，and thus the productivity prediction results tend to be optimistic. Aiming at solving this problem，the three-dimensional anisotropic reservoir is converted into an equivalent isotropic reservoir through coordinate transformation. Then the flow region in the reservoir can be divided into external region with plane radial flow，middle region with plane linear flow and internal region with vertical radial flow based on typical seepage characteristics of the horizontal wells. A new comprehensive formula for calculating the productivity of horizontal wells in a three-dimensional anisotropic reservoir was derived by using the hydropower similarity principle and the equivalent flow resistance method. Comparison with the conventional horizontal well productivity formula shows that the flow resistance of the plane linear flow and its influence on the productivity gradually increase with the increase of the length of the horizontal well；the plane anisotropy has significant influence on the productivity of the horizontal well，and its changing law is controlled by the angle between horizontal well and the main permeability direction of the reservoir；the productivity of the horizontal well increases with the increase of the vertical and horizontal permeability ratio，and increases with the increase of the angle between the horizontal well and the main permeability direction of the reservoir.The application shows that the new formula has higher prediction accuracy with an average deviation less than 3%，and it can be used to guide horizontal well productivity prediction and optimization of horizontal section length and azimuth.
The three-dimensional anisotropy of actual reservoirs and the typical linear flow characteristics in horizontal well seepage are not considered in commonly used horizontal well productivity prediction formula，and thus the productivity prediction results tend to be optimistic. Aiming at solving this problem，the three-dimensional anisotropic reservoir is converted into an equivalent isotropic reservoir through coordinate transformation. Then the flow region in the reservoir can be divided into external region with plane radial flow，middle region with plane linear flow and internal region with vertical radial flow based on typical seepage characteristics of the horizontal wells. A new comprehensive formula for calculating the productivity of horizontal wells in a three-dimensional anisotropic reservoir was derived by using the hydropower similarity principle and the equivalent flow resistance method. Comparison with the conventional horizontal well productivity formula shows that the flow resistance of the plane linear flow and its influence on the productivity gradually increase with the increase of the length of the horizontal well；the plane anisotropy has significant influence on the productivity of the horizontal well，and its changing law is controlled by the angle between horizontal well and the main permeability direction of the reservoir；the productivity of the horizontal well increases with the increase of the vertical and horizontal permeability ratio，and increases with the increase of the angle between the horizontal well and the main permeability direction of the reservoir.The application shows that the new formula has higher prediction accuracy with an average deviation less than 3%，and it can be used to guide horizontal well productivity prediction and optimization of horizontal section length and azimuth.
2019, 26(2):120-126.
DOI: 10.13673/j.cnki.cn37-1359/te.2019.02.017
Abstract:
Hangjinqi block in Ordos Basin is a tight sandstone gas reservoir with low porosity and permeability. To develop this type of reservoir with multi-stage fractured horizontal well is the most effective way. The fracture distribution of multicluster staged fracturing for the horizontal well has a significant influence on gas production. In order to get the highest gas productivity，an unsteady productivity prediction model was proposed in the consideration of fracture interference，threshold pressure gradient，and the coupling of flow in both fractures and matrix based on the potential theory and potential superposition principle. The gas productivity of both straight fractures and curved fractures can be estimated with the model.In this study，He3 Formation of Jin58 well area in Hangjinqi block was studied. Influence of fracture parameters on the gas productivity in each stage was discussed with orthoganality design method in conditions of different clusters. The results show that the influence of the fracture parameters on the gas productivity for either three or four cluster fractures in each stage from strong to weak are as follows：the half length of total fracture，length ratio，fracture conductivity，and the space ratio. The“U”pattern and nonuniform fracture pattern are recommended for this block.
Hangjinqi block in Ordos Basin is a tight sandstone gas reservoir with low porosity and permeability. To develop this type of reservoir with multi-stage fractured horizontal well is the most effective way. The fracture distribution of multicluster staged fracturing for the horizontal well has a significant influence on gas production. In order to get the highest gas productivity，an unsteady productivity prediction model was proposed in the consideration of fracture interference，threshold pressure gradient，and the coupling of flow in both fractures and matrix based on the potential theory and potential superposition principle. The gas productivity of both straight fractures and curved fractures can be estimated with the model.In this study，He3 Formation of Jin58 well area in Hangjinqi block was studied. Influence of fracture parameters on the gas productivity in each stage was discussed with orthoganality design method in conditions of different clusters. The results show that the influence of the fracture parameters on the gas productivity for either three or four cluster fractures in each stage from strong to weak are as follows：the half length of total fracture，length ratio，fracture conductivity，and the space ratio. The“U”pattern and nonuniform fracture pattern are recommended for this block.
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