Volume 23,Issue 6,2016 Table of Contents
2016, 23(6):1-7.
Abstract:
Quantitative identification of effective fractures is very important for tight clastic rock reservoir capacity and seepage ability evaluation and sweet point prediction. Tight clastic rock reservoir，belonging to marine-continent transitional facies，developed in the Upper Palaeozoic of southern Qinshui basin，which was very tight because the reservoir rock had experienced complicated tectonic evolution and sedimentation. Based on the core observation statistics and log analysis，effective fractures of tight clastic rock reservoir were identified quantitatively using principal component analysis method. Results show that the fractures of the clastic rock strata of Shanxi Formation in the Upper Palaeozoic of southern Qinshui basin are effective，the formation of which is closely related to the strong uplift and denudation of strata during Himalayan period，and they are mainly late period fractures. The opening of full filling fractures is largger，and they are mainly early period fractures. Principal components of six kinds of logging parameters which are sensitive to effective fractures were analyzed. It is found that the cumulative variance contribution ratio of the principal components of Y1 and Y2 is 88.55%. Therefore，Y1 and Y2 principal component can be used to identify the effective fractures，with good recognition effect. As a result，it can reduce the dimension and the effective information of the fracture can be extracted.
Quantitative identification of effective fractures is very important for tight clastic rock reservoir capacity and seepage ability evaluation and sweet point prediction. Tight clastic rock reservoir，belonging to marine-continent transitional facies，developed in the Upper Palaeozoic of southern Qinshui basin，which was very tight because the reservoir rock had experienced complicated tectonic evolution and sedimentation. Based on the core observation statistics and log analysis，effective fractures of tight clastic rock reservoir were identified quantitatively using principal component analysis method. Results show that the fractures of the clastic rock strata of Shanxi Formation in the Upper Palaeozoic of southern Qinshui basin are effective，the formation of which is closely related to the strong uplift and denudation of strata during Himalayan period，and they are mainly late period fractures. The opening of full filling fractures is largger，and they are mainly early period fractures. Principal components of six kinds of logging parameters which are sensitive to effective fractures were analyzed. It is found that the cumulative variance contribution ratio of the principal components of Y1 and Y2 is 88.55%. Therefore，Y1 and Y2 principal component can be used to identify the effective fractures，with good recognition effect. As a result，it can reduce the dimension and the effective information of the fracture can be extracted.
2016, 23(6):8-15.
Abstract:
The Mishrif Formation（Upper Cretaceous age）is an important carbonate reservoir in the Persian Gulf Basin. Taking Y oilfield in southeast Iraq as an example，a comprehensive study on carbonate reservoir and its logging response was carried out with core description，thin section observation，petrophysical analysis，mercury injection and well logging data.The results are as follows：there are bioclastic grainstone，reef limestone，packstone，wackstone，dolomitic limestone and mudstone developed in the Mishrif Formation；the types of storage space in the carbonate rocks include intergranular pores，moldic pores，intragranular pores，intercrystal pores and intergranular micropores，and dissolved fractures and pressure-solution fractures also developed in partial sections；the main range of reservoir porosity derived from core analysis varies from 8 percent to 28 percent，and permeability ranges from 1 millidarcy to 100 millidarcy. The pore system of Mishrif carbonate rocks is constructed by four combinations of pore types：intergranular-moldic pores，intergranular-intragranular-intercrystal pores，intergranular-intercrystal pores，and micropores-moldic-intercrystal pores. The highquality reservoirs are characterized by low gamma ray value，high acoustic value，high neutron porosity，low density and high resistivity. The highquality reservoirs in Mishrif carbonate in the study area are closely related to regressive cycles and are controlled by original depositional environment. Syngenetic selective dissolution，exposed dissolution and cementation in burial period are important controlling factors of reservoir qualities.
The Mishrif Formation（Upper Cretaceous age）is an important carbonate reservoir in the Persian Gulf Basin. Taking Y oilfield in southeast Iraq as an example，a comprehensive study on carbonate reservoir and its logging response was carried out with core description，thin section observation，petrophysical analysis，mercury injection and well logging data.The results are as follows：there are bioclastic grainstone，reef limestone，packstone，wackstone，dolomitic limestone and mudstone developed in the Mishrif Formation；the types of storage space in the carbonate rocks include intergranular pores，moldic pores，intragranular pores，intercrystal pores and intergranular micropores，and dissolved fractures and pressure-solution fractures also developed in partial sections；the main range of reservoir porosity derived from core analysis varies from 8 percent to 28 percent，and permeability ranges from 1 millidarcy to 100 millidarcy. The pore system of Mishrif carbonate rocks is constructed by four combinations of pore types：intergranular-moldic pores，intergranular-intragranular-intercrystal pores，intergranular-intercrystal pores，and micropores-moldic-intercrystal pores. The highquality reservoirs are characterized by low gamma ray value，high acoustic value，high neutron porosity，low density and high resistivity. The highquality reservoirs in Mishrif carbonate in the study area are closely related to regressive cycles and are controlled by original depositional environment. Syngenetic selective dissolution，exposed dissolution and cementation in burial period are important controlling factors of reservoir qualities.
2016, 23(6):16-21.
Abstract:
Shale rock is mainly composed of carbonate rock，clay and organic matter，and its rock physical and elastic parameters are mainly controlled by the influence of the three kinds of material. There is no mature rock physics models describing the relationship between lithology and velocity because of the complexity of the rock characteristics of the shale.Basic rock physics experiment of shale is an effective method to study the relationship of the shale lithology，oiliness and velocity，and such research in Jiyang depression is still in its infancy. Shale relevant physical parameters（density，porosity，etc.），the elastic parameters（P-wave velocity and S-wave wave velocity and Poisson’s ratio，etc.），organic geochemical parameters（organic carbon content）and rock fabric parameters were obtained through the laboratory tests on shale samples from Well Luo69. It is found that the elastic parameters（P，S，C type parameters）can be used for identification of shale lithology by analysis of the intersection of these parameters while the organic carbon content and carbonate mineral content are important factors influencing shale density and its P-wave and S-wave velocities. The variations of P-wave velocity and S-wave velocity of shale samples obtained under different conditions of temperature and pressure show that P-wave velocity is more sensitive to the change of pressure，and S-wave velocity is more sensitive to the change of temperature. The research results obtained can lay a foundation for the evaluation of the shale geophysical characteristics.
Shale rock is mainly composed of carbonate rock，clay and organic matter，and its rock physical and elastic parameters are mainly controlled by the influence of the three kinds of material. There is no mature rock physics models describing the relationship between lithology and velocity because of the complexity of the rock characteristics of the shale.Basic rock physics experiment of shale is an effective method to study the relationship of the shale lithology，oiliness and velocity，and such research in Jiyang depression is still in its infancy. Shale relevant physical parameters（density，porosity，etc.），the elastic parameters（P-wave velocity and S-wave wave velocity and Poisson’s ratio，etc.），organic geochemical parameters（organic carbon content）and rock fabric parameters were obtained through the laboratory tests on shale samples from Well Luo69. It is found that the elastic parameters（P，S，C type parameters）can be used for identification of shale lithology by analysis of the intersection of these parameters while the organic carbon content and carbonate mineral content are important factors influencing shale density and its P-wave and S-wave velocities. The variations of P-wave velocity and S-wave velocity of shale samples obtained under different conditions of temperature and pressure show that P-wave velocity is more sensitive to the change of pressure，and S-wave velocity is more sensitive to the change of temperature. The research results obtained can lay a foundation for the evaluation of the shale geophysical characteristics.
2016, 23(6):22-27.
Abstract:
The supergene karst reservoir，regarded as the research target by drilling，develops 100 m thick below the top of the carbonate buried hill in Nanpu sag. The residual karst index is firstly introduced as a quantitative parameters for evaluating the effectiveness of supergene karst reservoir space in the study area，taking advantage of seismic data，core，thin sections，electron microscope（SEM），well logging，mud logging and oil test data and combining with diagenesis types and degree，classification of reservoir space，physical characteristics and pore structure types. As a result，the supergene karst reservoirs of carbonate buried hill in Nanpu sag are divided into 3 types of I，II and III and evaluated comprehensively. Average amplitude，average instantaneous frequency and amplitude distorted degree，which are better correlated to residual karst index and independent to each other，are selected to be clustered and then mapped. At last，the supergene karst index contour map is drawn and then is verified with the actual drilling data. It is found that the accuracy rate is more than 70%.Finally，the favorable zone prediction of the carbonate supergene karst reservoir in Nanpu buried hill is realized，which indicates the direction for the next exploration and deployment.
The supergene karst reservoir，regarded as the research target by drilling，develops 100 m thick below the top of the carbonate buried hill in Nanpu sag. The residual karst index is firstly introduced as a quantitative parameters for evaluating the effectiveness of supergene karst reservoir space in the study area，taking advantage of seismic data，core，thin sections，electron microscope（SEM），well logging，mud logging and oil test data and combining with diagenesis types and degree，classification of reservoir space，physical characteristics and pore structure types. As a result，the supergene karst reservoirs of carbonate buried hill in Nanpu sag are divided into 3 types of I，II and III and evaluated comprehensively. Average amplitude，average instantaneous frequency and amplitude distorted degree，which are better correlated to residual karst index and independent to each other，are selected to be clustered and then mapped. At last，the supergene karst index contour map is drawn and then is verified with the actual drilling data. It is found that the accuracy rate is more than 70%.Finally，the favorable zone prediction of the carbonate supergene karst reservoir in Nanpu buried hill is realized，which indicates the direction for the next exploration and deployment.
2016, 23(6):28-33.
Abstract:
By seismic reflection interpretation，stratigraphic correlation and study on parasequence sets and relative lakelevel changes，the differences in sandbody distribution patterns were proposed for the1st member of lower Cretaceous Duhongmu Formation in Baiyinchagan sag. The results show that during the sedimentary period of the 1st member of Duhongmu Formation，the relative lakelevel changes are different in different areas of the basin，different types of parasequencesets in one systems tract are resulted in. The seismic reflection features is different obviously in different part of the 1st member of Duhongmu Formation. The seismic reflection frequency is medium high and the amplitude is moderate and continuous in Xilinhaolai area of southwester gentle slope belt of Baiyinchagan sag，and the formations prograde towards the north layer by layer. But the frequency is low，and amplitude is weak with poor continuity，and the formations retrograde layer by layer in Daerqi area of north eastern gentle slope. When the 1st member of Duhongmu Formation deposited，the provenance was sufficient in the Xilinhaolai area，and thus the fan scale was relatively large and its granularity was coarser with coarsing upwards. Progressive delta sand body developed in the whole area and the progressive parasequence sets were formed in Xilinhaolai area. But in northern steep slope zone of Daerqi area，the provenance supply was poor and the relative lake level ascended，and thus the regressive delta sand body developed and parasequence sets were formed under the progressive lake background. There is a trade-off relationship in the development of sandbodies between westsouth Xilinhaolai area and northeast Daerqi area.
By seismic reflection interpretation，stratigraphic correlation and study on parasequence sets and relative lakelevel changes，the differences in sandbody distribution patterns were proposed for the1st member of lower Cretaceous Duhongmu Formation in Baiyinchagan sag. The results show that during the sedimentary period of the 1st member of Duhongmu Formation，the relative lakelevel changes are different in different areas of the basin，different types of parasequencesets in one systems tract are resulted in. The seismic reflection features is different obviously in different part of the 1st member of Duhongmu Formation. The seismic reflection frequency is medium high and the amplitude is moderate and continuous in Xilinhaolai area of southwester gentle slope belt of Baiyinchagan sag，and the formations prograde towards the north layer by layer. But the frequency is low，and amplitude is weak with poor continuity，and the formations retrograde layer by layer in Daerqi area of north eastern gentle slope. When the 1st member of Duhongmu Formation deposited，the provenance was sufficient in the Xilinhaolai area，and thus the fan scale was relatively large and its granularity was coarser with coarsing upwards. Progressive delta sand body developed in the whole area and the progressive parasequence sets were formed in Xilinhaolai area. But in northern steep slope zone of Daerqi area，the provenance supply was poor and the relative lake level ascended，and thus the regressive delta sand body developed and parasequence sets were formed under the progressive lake background. There is a trade-off relationship in the development of sandbodies between westsouth Xilinhaolai area and northeast Daerqi area.
2016, 23(6):34-40.
Abstract:
The petroleum exploration of deep-buried reservoir in lower Es3 in the north zone of Chezhen sag faces the problem that the distribution of favorable reservoirs is not clear. For further exploration，through core，casting thin sections，scanning electron microscope and other chemical examination data，the formation mechanism and distribution laws of favorable reservoir in lower Es3 in the north zone of Chezhen sag was studied. Results show that there are much differences in rock composition and gravels components in Dawangbei-Guojuzi area and Chexi area in the eastern and western of the study area respectively. Sand-conglomerate reservoirs in the Dawangbei-Guojuzi area are mainly controlled by Archeozoic granite gneiss parent rock in the area of eastern Chenzikou uplift，which are characterized by relatively high composition maturity and gravel components of granite gneiss. While sand-conglomerate reservoirs in Chexi area are mainly controlled by lower Palaeozoic carbonate parent rock in the area of western Chenzikou uplift，which are characterized by relatively low composition maturity and gravel components of carbonate rocks. The differences of parent rock property cause the differences of compressive strength of sand-conglomerate bodies，thus they have impacts on the preservation of primary pores and the development of secondary porosity. It’s the key to the formation of deep-buried favorable reservoir in the study area. Taking into account of sedimentary types，parent rock property and abnormal high pressure，it is believed that the favorable reservoir is mainly distributed in Dawangbei-Guojuzi area which has high formation pressure coefficient and is affected by granite gneiss parent rock.
The petroleum exploration of deep-buried reservoir in lower Es3 in the north zone of Chezhen sag faces the problem that the distribution of favorable reservoirs is not clear. For further exploration，through core，casting thin sections，scanning electron microscope and other chemical examination data，the formation mechanism and distribution laws of favorable reservoir in lower Es3 in the north zone of Chezhen sag was studied. Results show that there are much differences in rock composition and gravels components in Dawangbei-Guojuzi area and Chexi area in the eastern and western of the study area respectively. Sand-conglomerate reservoirs in the Dawangbei-Guojuzi area are mainly controlled by Archeozoic granite gneiss parent rock in the area of eastern Chenzikou uplift，which are characterized by relatively high composition maturity and gravel components of granite gneiss. While sand-conglomerate reservoirs in Chexi area are mainly controlled by lower Palaeozoic carbonate parent rock in the area of western Chenzikou uplift，which are characterized by relatively low composition maturity and gravel components of carbonate rocks. The differences of parent rock property cause the differences of compressive strength of sand-conglomerate bodies，thus they have impacts on the preservation of primary pores and the development of secondary porosity. It’s the key to the formation of deep-buried favorable reservoir in the study area. Taking into account of sedimentary types，parent rock property and abnormal high pressure，it is believed that the favorable reservoir is mainly distributed in Dawangbei-Guojuzi area which has high formation pressure coefficient and is affected by granite gneiss parent rock.
2016, 23(6):41-46.
Abstract:
Wendong sag，one of the small Mesozoic-to-Cenozoic lacustrine rift basins locating in the Luxi uplift，deposits thick Paleocene mudrocks with shallow burial depth and high exploration value. Vertically，development features and enrichment factors of shale oil of the Dawenkou Formation within the sag was analyzed on the basis of data of Well Wenye No.1 drilled by China Geological Survey. The drilling results of Well Wenye No.1 show that about 500 m thick of source rock develops at the middle-to-upper member of the Dawenkou Formation near the subsidence center of Wendong sag. Hydrocarbons accumulate in the ways of shale oil with oil content generally greater than 1.5%. Two shale oil-rich intervals having high hydrocarbon generation potential are found at 440-560 m and 700-820 m underground. The level of vertical enrichment for shale oil in this region depends on depositional setting，TOC abundance and development level of fractures（beddings）. Evidence shows semi-deep to deep lacustrine setting is favorable for organic matter preservation which provides fundamental material for hydrocarbon generation；the abundance of organic matter has a positive relationship with oil content，which determines the hydrocarbon generation potential；fractures（beddings）provide better porosity and permeability and make the accumulation of oil possible.
Wendong sag，one of the small Mesozoic-to-Cenozoic lacustrine rift basins locating in the Luxi uplift，deposits thick Paleocene mudrocks with shallow burial depth and high exploration value. Vertically，development features and enrichment factors of shale oil of the Dawenkou Formation within the sag was analyzed on the basis of data of Well Wenye No.1 drilled by China Geological Survey. The drilling results of Well Wenye No.1 show that about 500 m thick of source rock develops at the middle-to-upper member of the Dawenkou Formation near the subsidence center of Wendong sag. Hydrocarbons accumulate in the ways of shale oil with oil content generally greater than 1.5%. Two shale oil-rich intervals having high hydrocarbon generation potential are found at 440-560 m and 700-820 m underground. The level of vertical enrichment for shale oil in this region depends on depositional setting，TOC abundance and development level of fractures（beddings）. Evidence shows semi-deep to deep lacustrine setting is favorable for organic matter preservation which provides fundamental material for hydrocarbon generation；the abundance of organic matter has a positive relationship with oil content，which determines the hydrocarbon generation potential；fractures（beddings）provide better porosity and permeability and make the accumulation of oil possible.
2016, 23(6):47-51.
Abstract:
Based on the data of drilling，logging and seismic and the basin modeling technique，the effects of salt on thermal evolution of source rock and the reservoir temperature were studied taking Block X in Gabon coastal basin as an instance. The results indicate that the distribution of salt is in ribbon pattern or in dot scope in the study area，and the thickness of salt is between 0 and 3 723 m with an average of 808.5 m. The thermal conductivity of salt is typically two or three times larger than that of other sedimentary rock. Therefore，under constraint of the high thermal conductivity of salt，the source rock maturity of the Madielais Formation is risen，and the source rock maturity of the Melania Formation is reduced，and the reservoir temperature of the Dentale Formation is reduced. The thicker the layer of salt is，and the nearer the layer of salt is to the formations，the larger the effect of salt on vitrinite reflectance is. To the isobathic layer under the salt，the difference between Ro with effect of salt and without effect of salt is 0.6% when the Ezanga stratum thickness is 2.0 km，and the difference between Ro with effect of salt and without effect of salt is only 0.1% when the Ezanga stratum thickness is 0.2 km. Ro difference of the Vembo Formation nearer salt may be more than 1.2%，and that of the Melania Formation which is farther away from the salt may be less than 1.2%. The thicker the salt is，the greater the influence of salt on reservoir top and bottom temperature is. Temperature difference between reservoir top and bottom are 30.66 and 29.22 ℃ respectively when the Ezanga Formation thickness is 2.0 km，and those values drop to 5.06 and 3.14 ℃ respectively when the Ezanga Formation thickness is 0.2 km. Therefore，hydrocarbon source rock thermal evolution and reservoir temperature are affect?ed by the thickness of the salt body，shape change，etc.，Ro revealed by drilling data cannot be used simply to predict Ro of the source rock around and its thermal evolution in salt zone.
Based on the data of drilling，logging and seismic and the basin modeling technique，the effects of salt on thermal evolution of source rock and the reservoir temperature were studied taking Block X in Gabon coastal basin as an instance. The results indicate that the distribution of salt is in ribbon pattern or in dot scope in the study area，and the thickness of salt is between 0 and 3 723 m with an average of 808.5 m. The thermal conductivity of salt is typically two or three times larger than that of other sedimentary rock. Therefore，under constraint of the high thermal conductivity of salt，the source rock maturity of the Madielais Formation is risen，and the source rock maturity of the Melania Formation is reduced，and the reservoir temperature of the Dentale Formation is reduced. The thicker the layer of salt is，and the nearer the layer of salt is to the formations，the larger the effect of salt on vitrinite reflectance is. To the isobathic layer under the salt，the difference between Ro with effect of salt and without effect of salt is 0.6% when the Ezanga stratum thickness is 2.0 km，and the difference between Ro with effect of salt and without effect of salt is only 0.1% when the Ezanga stratum thickness is 0.2 km. Ro difference of the Vembo Formation nearer salt may be more than 1.2%，and that of the Melania Formation which is farther away from the salt may be less than 1.2%. The thicker the salt is，the greater the influence of salt on reservoir top and bottom temperature is. Temperature difference between reservoir top and bottom are 30.66 and 29.22 ℃ respectively when the Ezanga Formation thickness is 2.0 km，and those values drop to 5.06 and 3.14 ℃ respectively when the Ezanga Formation thickness is 0.2 km. Therefore，hydrocarbon source rock thermal evolution and reservoir temperature are affect?ed by the thickness of the salt body，shape change，etc.，Ro revealed by drilling data cannot be used simply to predict Ro of the source rock around and its thermal evolution in salt zone.
2016, 23(6):52-56.
Abstract:
Based on the feature that the development methods of the fault-block reservoir vary in different parts，a partitioned control technique of well pattern was put forward. Considering the structural and flowing characteristics of the fault block reservoirs，the first level of reservoir partitioning technique was established，and the reservoir can be divided into 8 parts generally which can be summarize into 3 patterns：angle controlled region，fault controlled region and well controlled region. According to the distribution of remaining oil，the second level of reservoir partitioning was divided into enriched area of remaining oil，weak enriched area of remaining oil，water-flooded area and strong water-flooded area. Then the well pattern partitioned control method for different regions was determined based on analyzing remaining oil characteristics and control factors. Different kinds of fault block reservoir can be seen as a combination of different types of regions，and the combined development method can be further determined：the production well should be deployed in structure high site near the fault and close to the vertex of the angle between two faults，and the injection well ought to inject outside the edge using staggered line-drive pattern. This technique was applied to Xin10 fault block with good results，and the 10-year cumulative increased oil will be 2.53×104 t and EOR will be 4.6% after it was predicted by numerical simulation.
Based on the feature that the development methods of the fault-block reservoir vary in different parts，a partitioned control technique of well pattern was put forward. Considering the structural and flowing characteristics of the fault block reservoirs，the first level of reservoir partitioning technique was established，and the reservoir can be divided into 8 parts generally which can be summarize into 3 patterns：angle controlled region，fault controlled region and well controlled region. According to the distribution of remaining oil，the second level of reservoir partitioning was divided into enriched area of remaining oil，weak enriched area of remaining oil，water-flooded area and strong water-flooded area. Then the well pattern partitioned control method for different regions was determined based on analyzing remaining oil characteristics and control factors. Different kinds of fault block reservoir can be seen as a combination of different types of regions，and the combined development method can be further determined：the production well should be deployed in structure high site near the fault and close to the vertex of the angle between two faults，and the injection well ought to inject outside the edge using staggered line-drive pattern. This technique was applied to Xin10 fault block with good results，and the 10-year cumulative increased oil will be 2.53×104 t and EOR will be 4.6% after it was predicted by numerical simulation.
2016, 23(6):57-63.
Abstract:
In order to study the variation of the rock physical property parameter and fluid flow parameter during the development of low-permeability reservoir，a new stress sensitivity predictive model for permeability and threshold pressure gradient in the low-permeability reservoir has been derived theoretically combined with the non-linear seepage feature based on the fractal theory of core accumulation model and mechanics of materials. The variation of permeability and threshold pressure gradient versus the effective stress with different mechanical parameters was quantitatively analyzed. Validity of the stress sensitivity model was verified through comparison between theoretical model result and those of available experimental data. The research results show that：the permeability decreases and the threshold pressure gradient increases as the effective stress increases，and the normalized permeability and threshold pressure gradient has a better power function relationship under the effective stress. Stress sensitivity of permeability and threshold pressure gradient is closely relative to the mechanical parameters of rock，higher Young’s modulus presents a relative weaker stress sensitivity of permeability and threshold pressure gradient，and lower Poisson’s ratio exhibits a more stress sensitive threshold pressure gradient and permeability under the same Young’s modulus. The model could accurately predict the stress sensitivity of permeability and threshold pressure gradient，thereby offer a theoretical base and guide for flow rule research and design for production performance in the low-permeability reservoir．
In order to study the variation of the rock physical property parameter and fluid flow parameter during the development of low-permeability reservoir，a new stress sensitivity predictive model for permeability and threshold pressure gradient in the low-permeability reservoir has been derived theoretically combined with the non-linear seepage feature based on the fractal theory of core accumulation model and mechanics of materials. The variation of permeability and threshold pressure gradient versus the effective stress with different mechanical parameters was quantitatively analyzed. Validity of the stress sensitivity model was verified through comparison between theoretical model result and those of available experimental data. The research results show that：the permeability decreases and the threshold pressure gradient increases as the effective stress increases，and the normalized permeability and threshold pressure gradient has a better power function relationship under the effective stress. Stress sensitivity of permeability and threshold pressure gradient is closely relative to the mechanical parameters of rock，higher Young’s modulus presents a relative weaker stress sensitivity of permeability and threshold pressure gradient，and lower Poisson’s ratio exhibits a more stress sensitive threshold pressure gradient and permeability under the same Young’s modulus. The model could accurately predict the stress sensitivity of permeability and threshold pressure gradient，thereby offer a theoretical base and guide for flow rule research and design for production performance in the low-permeability reservoir．
2016, 23(6):64-69.
Abstract:
The carbonate reservoir has characteristics of strong heterogeneity and developed natural fractures，and it is always treated by acidizing to remove pollution near the wellbore area. The existence of natural fractures makes heterogeneity of carbonate reservoir stronger，which would affect the wormhole development significantly in acidizing process. Only few research on wormhole developed in carbonate rocks fracture with natural has been reported，while current studies mainly focus on the rule of wormhole growing in carbonate rock matrix. The effect of natural fracture length，natural fracture density and direction on wormhole pattern and acid injection volume for breakthrough were analyzed by a radial dual-scale continuum model based on equivalent theory. The results show that the developed wormholes in injection side without fractures are restrained and the acid volume for breakthrough decreases with an increasing length of fractures parallel to acid injection direction. The rise of natural fracture number leads to fewer developed wormhole and lower injection pressure in other directions of inlet，while the acid injection volume for breakthrough are dependent on physical property of oil reservoirs before natural fractures. The natural fractures perpendicular to acid injection direction can only change the wormhole pattern nearby，and it needs more acid to inject to achieve breakthrough of wormhole.
The carbonate reservoir has characteristics of strong heterogeneity and developed natural fractures，and it is always treated by acidizing to remove pollution near the wellbore area. The existence of natural fractures makes heterogeneity of carbonate reservoir stronger，which would affect the wormhole development significantly in acidizing process. Only few research on wormhole developed in carbonate rocks fracture with natural has been reported，while current studies mainly focus on the rule of wormhole growing in carbonate rock matrix. The effect of natural fracture length，natural fracture density and direction on wormhole pattern and acid injection volume for breakthrough were analyzed by a radial dual-scale continuum model based on equivalent theory. The results show that the developed wormholes in injection side without fractures are restrained and the acid volume for breakthrough decreases with an increasing length of fractures parallel to acid injection direction. The rise of natural fracture number leads to fewer developed wormhole and lower injection pressure in other directions of inlet，while the acid injection volume for breakthrough are dependent on physical property of oil reservoirs before natural fractures. The natural fractures perpendicular to acid injection direction can only change the wormhole pattern nearby，and it needs more acid to inject to achieve breakthrough of wormhole.
2016, 23(6):70-75.
Abstract:
Steam distillation could improve the oil recovery effectively during thermal recovery process of heavy oil. However，steam distillation mechanism and its effect on oil properties was still not clear. Aiming at these problems，three groups of steam distillation experiments in different conditions were conducted with a 3- D physical model，including saturated steam，superheated 10 ℃ steam and superheated 40 ℃ steam. The results show that steam distillation ratio of crude oil is greatly affected by degree of superheat of injected steam. The higher the degree of superheat is，the higher the steam distillation ratio of crude oil is. Steam distillation ratio of crude oil in different conditions is 11.158%，10.903% and 10.423%，respectively. With the increasing injected volume，the distillation ratio increases. When the injected volume reaches a certain value，the distillation ratio will no longer increase. The experiment results of the density，viscosity，composition，carbon number distribution of crude oil and distillation fraction were compared to those before the experiment. The results show that light components of smaller carbon number were distilled off firstly by steam distillation，followed by heavier components. During steam distillation，the density and viscosity of residual oil increase，and the contents of saturated hydrocarbons and gum decrease，and the distribution region of carbon number shifts toward high carbon. The composition of the crude oil is changed.
Steam distillation could improve the oil recovery effectively during thermal recovery process of heavy oil. However，steam distillation mechanism and its effect on oil properties was still not clear. Aiming at these problems，three groups of steam distillation experiments in different conditions were conducted with a 3- D physical model，including saturated steam，superheated 10 ℃ steam and superheated 40 ℃ steam. The results show that steam distillation ratio of crude oil is greatly affected by degree of superheat of injected steam. The higher the degree of superheat is，the higher the steam distillation ratio of crude oil is. Steam distillation ratio of crude oil in different conditions is 11.158%，10.903% and 10.423%，respectively. With the increasing injected volume，the distillation ratio increases. When the injected volume reaches a certain value，the distillation ratio will no longer increase. The experiment results of the density，viscosity，composition，carbon number distribution of crude oil and distillation fraction were compared to those before the experiment. The results show that light components of smaller carbon number were distilled off firstly by steam distillation，followed by heavier components. During steam distillation，the density and viscosity of residual oil increase，and the contents of saturated hydrocarbons and gum decrease，and the distribution region of carbon number shifts toward high carbon. The composition of the crude oil is changed.
2016, 23(6):76-81.
Abstract:
Polymer flooding is an important chemical EOR technology for many Chinese reservoirs. Polymer thermal degradation is an important factor affecting the polymer flooding. It is necessary to consider the polymer thermal degradation when polymer flooding project is designed using reservoir numerical simulation. Currently，numerical simulation of polymer flooding considering polymer thermal degradation is not yet perfect. Based on viscosity attenuation model that can accurately reflect the polymer thermal degradation，method of streamlines updating at each step and mapping between grid and streamline was applied to solve the degradation time，and the numerical simulation of polymer flooding considering polymer thermal degradation can be realized. The method has clear physical meaning，strong applicability and accurate calculation results，reflecting the thermal degradation process of flowing polymer underground accurately. Three models were studied using the new method. The results show that the time of polymer degradation is less than that of propagation in the stratum during polymer flooding process，and equal when the process is stable. Thermal degradation has no effect on polymer concentration，but decreases the viscosity significantly. As a result，the effective time of polymer flooding is prolonged，water cut drop funnel is minified and the effect becomes poor. It is necessary to consider the polymer thermal degradation when designing polymer flooding project.
Polymer flooding is an important chemical EOR technology for many Chinese reservoirs. Polymer thermal degradation is an important factor affecting the polymer flooding. It is necessary to consider the polymer thermal degradation when polymer flooding project is designed using reservoir numerical simulation. Currently，numerical simulation of polymer flooding considering polymer thermal degradation is not yet perfect. Based on viscosity attenuation model that can accurately reflect the polymer thermal degradation，method of streamlines updating at each step and mapping between grid and streamline was applied to solve the degradation time，and the numerical simulation of polymer flooding considering polymer thermal degradation can be realized. The method has clear physical meaning，strong applicability and accurate calculation results，reflecting the thermal degradation process of flowing polymer underground accurately. Three models were studied using the new method. The results show that the time of polymer degradation is less than that of propagation in the stratum during polymer flooding process，and equal when the process is stable. Thermal degradation has no effect on polymer concentration，but decreases the viscosity significantly. As a result，the effective time of polymer flooding is prolonged，water cut drop funnel is minified and the effect becomes poor. It is necessary to consider the polymer thermal degradation when designing polymer flooding project.
2016, 23(6):82-86.
Abstract:
Bottom water coning is one of the important problems in the development process of horizontal wells in bottom water reservoir. To accurately predict the time of bottom water coning is vital for reasonable development of the bottom water reservoir. For the horizontal wells in bottom water reservoir with barrier，physical model was establish based on oil-water two phase flow theory and the law of fluid flow in porous media，and potential distribution of horizontal wells in bottom water reservoir was obtained through the mirror image and potential superposition principle. The formula for water breakthrough time of horizontal wells in bottom water reservoir with barrier was deduced. Case calculation shows that the relative error between the formula calculation results and the actual water breakthrough time is 5.39%. The existence of the barrier greatly delays the bottom water coning time，and the water breakthrough time increases with the increase of the barrier radius and water avoidance height. With decrease of horizontal section length and increases of daily oil production，the water breakthrough time of horizontal well decreases. The research has certain guiding significance for the design of the horizontal well length and water avoidance height and development of the bottom water reservoir with barrier reservoir.
Bottom water coning is one of the important problems in the development process of horizontal wells in bottom water reservoir. To accurately predict the time of bottom water coning is vital for reasonable development of the bottom water reservoir. For the horizontal wells in bottom water reservoir with barrier，physical model was establish based on oil-water two phase flow theory and the law of fluid flow in porous media，and potential distribution of horizontal wells in bottom water reservoir was obtained through the mirror image and potential superposition principle. The formula for water breakthrough time of horizontal wells in bottom water reservoir with barrier was deduced. Case calculation shows that the relative error between the formula calculation results and the actual water breakthrough time is 5.39%. The existence of the barrier greatly delays the bottom water coning time，and the water breakthrough time increases with the increase of the barrier radius and water avoidance height. With decrease of horizontal section length and increases of daily oil production，the water breakthrough time of horizontal well decreases. The research has certain guiding significance for the design of the horizontal well length and water avoidance height and development of the bottom water reservoir with barrier reservoir.
2016, 23(6):87-93.
Abstract:
Fractured horizontal wells are increasingly widely used in tight oil reservoirs with low permeability. However，most studies on drainage radius are primarily associated with vertical wells while few studies on horizontal wells. With the case of Changqing oilfield，the fractures in the horizontal wells generated by stimulated reservoir volume fracturing were simulated by band source. Pressure distribution equations of stimulated reservoir volume fracturing for horizontal wells are derived considering threshold pressure gradient，and drainage radius of fractured horizontal wells in tight oil reservoir can be studied. The results show that drainage radius first increases and then decreases with development time increasing，and drainage radius increases slightly as length of horizontal well increases. The hydraulic fracture half-length exerts different influence on drainage radius in the horizontal and vertical direction respectively，which shows that the horizontal drainage radius increases and the drainage radius of matrix and vertical drainage radius decrease as the increase of hydraulic fracture half-length. Increase of network width helps expand the drainage radius in the both directions，but its effect on drainage radius gradually becomes weaker.
Fractured horizontal wells are increasingly widely used in tight oil reservoirs with low permeability. However，most studies on drainage radius are primarily associated with vertical wells while few studies on horizontal wells. With the case of Changqing oilfield，the fractures in the horizontal wells generated by stimulated reservoir volume fracturing were simulated by band source. Pressure distribution equations of stimulated reservoir volume fracturing for horizontal wells are derived considering threshold pressure gradient，and drainage radius of fractured horizontal wells in tight oil reservoir can be studied. The results show that drainage radius first increases and then decreases with development time increasing，and drainage radius increases slightly as length of horizontal well increases. The hydraulic fracture half-length exerts different influence on drainage radius in the horizontal and vertical direction respectively，which shows that the horizontal drainage radius increases and the drainage radius of matrix and vertical drainage radius decrease as the increase of hydraulic fracture half-length. Increase of network width helps expand the drainage radius in the both directions，but its effect on drainage radius gradually becomes weaker.
2016, 23(6):94-98.
Abstract:
Canada is the country with world largest oil sands resource，where 80% of the resources need to be produced by thermal recovery methods. The methods used widely include steam assisted gravity drainage（SAGD）and cyclic steam stimulation（CSS）. The mismatch between reservoir simulation results and history production is one of the main challenges.Studies suggest that the large-scale lateral gradient change in the western Canadian sedimentary basin and small-scale vertical gradient change within the oil reservoir are very common for the composition and physical properties of crude oil and that the composition and properties of crude oil on bottom and top of oil reservoir are completely different. Reservoir simulation study was conducted on effects of the variation of viscosity gradient of crude oil on the thermal production. The results show that the viscosity gradient change is the main reason for mismatch between reservoir simulation results and production history. However，variable viscosity model can be used to predict cumulative oil production more accurately. And the prediction result of fixed viscosity model is too optimistic. Case studies on production well position optimization with variable viscosity model have shown the best produced degree and economic benefits should be 8 m above oil-water interface for ASGD. Heterogeneity of reservoir fluids，especially viscosity heterogeneity，and heterogeneity of reservoir rocks was combined and was applid to reservoir description and numerical simulation，which can predict accurately production dynamics and development effect of oil sand thermal recovery，optimize production management and ensure the best recovery efficiency and economic benefits.
Canada is the country with world largest oil sands resource，where 80% of the resources need to be produced by thermal recovery methods. The methods used widely include steam assisted gravity drainage（SAGD）and cyclic steam stimulation（CSS）. The mismatch between reservoir simulation results and history production is one of the main challenges.Studies suggest that the large-scale lateral gradient change in the western Canadian sedimentary basin and small-scale vertical gradient change within the oil reservoir are very common for the composition and physical properties of crude oil and that the composition and properties of crude oil on bottom and top of oil reservoir are completely different. Reservoir simulation study was conducted on effects of the variation of viscosity gradient of crude oil on the thermal production. The results show that the viscosity gradient change is the main reason for mismatch between reservoir simulation results and production history. However，variable viscosity model can be used to predict cumulative oil production more accurately. And the prediction result of fixed viscosity model is too optimistic. Case studies on production well position optimization with variable viscosity model have shown the best produced degree and economic benefits should be 8 m above oil-water interface for ASGD. Heterogeneity of reservoir fluids，especially viscosity heterogeneity，and heterogeneity of reservoir rocks was combined and was applid to reservoir description and numerical simulation，which can predict accurately production dynamics and development effect of oil sand thermal recovery，optimize production management and ensure the best recovery efficiency and economic benefits.
2016, 23(6):99-104.
Abstract:
The current calculation methods of recovery of CBM（coalbed methane）are simple，which ignores the influence factors of recovery systematically. Therefore，a new analysis method of the recovery of CBM was put forward and verified，which can reflect major influence factors during each production period. The recovery of CBM is mainly controlled by sweep efficiency of reservoir pressure drop and desorption efficiency. The sweep efficiency of pressure drop depends on well pattern，well types，fracturing and other engineering factors. Desorption efficiency is determined by gas sorption parameters and abandoned pressure. Reduction of 0.1 MPa of abandoned pressure can lead to enhancement of recovery by 4.43%. During the early period of CBM production，the sweep efficiency of pressure drop mainly contributes to the CBM recovery degree and its increasing will result in a faster production speed of coalbed methane. During the later production period，the recovery degree is controlled by desorption efficiency. The efficient way to improve the sweep efficiency of pressure drop is to adopt the optimized well pattern which can match the coalbed geological parameters. And then the well pattern can control the coalbed effectively and volumetric desorption may be formed. Negative pressure production method can reduce the abandoned pressure of coalbed reservoir to improve the desorption efficiency of the coalbed methane.
The current calculation methods of recovery of CBM（coalbed methane）are simple，which ignores the influence factors of recovery systematically. Therefore，a new analysis method of the recovery of CBM was put forward and verified，which can reflect major influence factors during each production period. The recovery of CBM is mainly controlled by sweep efficiency of reservoir pressure drop and desorption efficiency. The sweep efficiency of pressure drop depends on well pattern，well types，fracturing and other engineering factors. Desorption efficiency is determined by gas sorption parameters and abandoned pressure. Reduction of 0.1 MPa of abandoned pressure can lead to enhancement of recovery by 4.43%. During the early period of CBM production，the sweep efficiency of pressure drop mainly contributes to the CBM recovery degree and its increasing will result in a faster production speed of coalbed methane. During the later production period，the recovery degree is controlled by desorption efficiency. The efficient way to improve the sweep efficiency of pressure drop is to adopt the optimized well pattern which can match the coalbed geological parameters. And then the well pattern can control the coalbed effectively and volumetric desorption may be formed. Negative pressure production method can reduce the abandoned pressure of coalbed reservoir to improve the desorption efficiency of the coalbed methane.
2016, 23(6):105-111.
Abstract:
Shale gas reservoir has drastically low permeability and production capacity，and thus it can only be exploited after simulated reservoir volume fracturing in order to form fracture network. Traditionally，dual porosity model is the most common method for numerical simulation，however，it becomes inefficient when facing the natural fractures far away from well which open and connect with each other after volume fracturing. In order to describe the actual flow situation and the adsorption mechanism of gas of fractured shale gas reservoir，a triple porosity-dual permeability model was built. The new model considers the adsorption mechanism of shale gas and takes the matrix as gas source，and the first-degree and second-degree secondary fractures were regarded as two equivalent porous continuums while the main fractures were described explicitly as discrete fractures. A comparison between results of the new triple porous model and the traditional dual medium model was conducted. The gas production rate and cumulative production rate of the new triple porous model are both higher than those of the traditional dual medium model. Considering the rule that observed gas production rate is always higher than that of traditional dual medium model，the simulation result of the new triple porous model is more accurate. The analysis result shows that the permeability of second-degree secondary fractures has great influence on cumulative production rate and should be improved by measures in the production，while the influence of initial adsorbed gas content is not obvious.
Shale gas reservoir has drastically low permeability and production capacity，and thus it can only be exploited after simulated reservoir volume fracturing in order to form fracture network. Traditionally，dual porosity model is the most common method for numerical simulation，however，it becomes inefficient when facing the natural fractures far away from well which open and connect with each other after volume fracturing. In order to describe the actual flow situation and the adsorption mechanism of gas of fractured shale gas reservoir，a triple porosity-dual permeability model was built. The new model considers the adsorption mechanism of shale gas and takes the matrix as gas source，and the first-degree and second-degree secondary fractures were regarded as two equivalent porous continuums while the main fractures were described explicitly as discrete fractures. A comparison between results of the new triple porous model and the traditional dual medium model was conducted. The gas production rate and cumulative production rate of the new triple porous model are both higher than those of the traditional dual medium model. Considering the rule that observed gas production rate is always higher than that of traditional dual medium model，the simulation result of the new triple porous model is more accurate. The analysis result shows that the permeability of second-degree secondary fractures has great influence on cumulative production rate and should be improved by measures in the production，while the influence of initial adsorbed gas content is not obvious.
2016, 23(6):112-119.
Abstract:
Complex fracture network formed by fracturing is the key of unconventional reservoir stimulation，and the fracture initiation and expansion are mainly controlled by the ground stress field distribution. So the fracture local stress disturbance law of the horizontal well fracturing is necessary to be studied. A calculation model of the near wellbore fracture local stress composed of the horizontal wellbore stress concentration and fracture-induced stress was established. Finite element numerical simulation software Comsol Multiphysic was used to simulate and to analyze the stress distribution situation，and the influence law of the disturbance factors including the fracture net pressure，fracture length，fracture number and spacing on the local stress field was revealed. The result shows that the disturbance degree of the near wellbore fracture to the minimum horizontal principal stress is more significant. Among the factors，the fracture net pressure and number have a positive impact on the disturbance amplitude of the local stress field. The increase of the fracture length is mainly reflected in the increase of stress disturbance range. And the increase of the fracture spacing makes the decrease of the stress interference degree among fractures.
Complex fracture network formed by fracturing is the key of unconventional reservoir stimulation，and the fracture initiation and expansion are mainly controlled by the ground stress field distribution. So the fracture local stress disturbance law of the horizontal well fracturing is necessary to be studied. A calculation model of the near wellbore fracture local stress composed of the horizontal wellbore stress concentration and fracture-induced stress was established. Finite element numerical simulation software Comsol Multiphysic was used to simulate and to analyze the stress distribution situation，and the influence law of the disturbance factors including the fracture net pressure，fracture length，fracture number and spacing on the local stress field was revealed. The result shows that the disturbance degree of the near wellbore fracture to the minimum horizontal principal stress is more significant. Among the factors，the fracture net pressure and number have a positive impact on the disturbance amplitude of the local stress field. The increase of the fracture length is mainly reflected in the increase of stress disturbance range. And the increase of the fracture spacing makes the decrease of the stress interference degree among fractures.
2016, 23(6):120-126.
Abstract:
Ordos basin is rich in tight oil resources and single well production in such reservoirs has been substantially increased by the progress of volume fracturing in recent years. However，early developed by conventional fracturing，the single well production and economic benefit was inferior in An83 block of Changqing oilfield. In order to solve this problem，the reservoir characteristics and development dynamic of An83 block was analyzed，and the idea of volume fracturing was put forward. The net pressure of meeting the demands of complex fracture network system was studied by making use of test data of rock mechanics，in-situ stress and natural fracture. And a chart of dynamic fracture width varying with time and rate was established. The temporary plugging timing，injection rate and temporary blocking agent optimization were also researched. Fracturing technology involves fracture tip temporary plugging，multistage temporary plugging in created fractures，high pump rate，low proppant concentration and large amount of slick water and low viscosity liquid system. The new technologies increases the net fracture pressure and creates a complex network system in the side of the fractures. It also leads to an increase of contact area between fracture networks and matrix and thus enhance the lateral remaining oil producing. The technique has been applied to 100 wells in C7 tight oil reservoir of An83 block，and the average well production was increased by 4-5 times than that before fracturing. Besides，it will effectively improve the block development efficiency.
Ordos basin is rich in tight oil resources and single well production in such reservoirs has been substantially increased by the progress of volume fracturing in recent years. However，early developed by conventional fracturing，the single well production and economic benefit was inferior in An83 block of Changqing oilfield. In order to solve this problem，the reservoir characteristics and development dynamic of An83 block was analyzed，and the idea of volume fracturing was put forward. The net pressure of meeting the demands of complex fracture network system was studied by making use of test data of rock mechanics，in-situ stress and natural fracture. And a chart of dynamic fracture width varying with time and rate was established. The temporary plugging timing，injection rate and temporary blocking agent optimization were also researched. Fracturing technology involves fracture tip temporary plugging，multistage temporary plugging in created fractures，high pump rate，low proppant concentration and large amount of slick water and low viscosity liquid system. The new technologies increases the net fracture pressure and creates a complex network system in the side of the fractures. It also leads to an increase of contact area between fracture networks and matrix and thus enhance the lateral remaining oil producing. The technique has been applied to 100 wells in C7 tight oil reservoir of An83 block，and the average well production was increased by 4-5 times than that before fracturing. Besides，it will effectively improve the block development efficiency.
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