Volume 21,Issue 5,2014 Table of Contents
2014, 21(5):1-7.
Abstract:
In order to ascertain the secondary-order sequence boundary of Palaeogene in Jiyang depression, geophysical, geochemical and paleontological data were used to study and compare the feature of three boundaries of upper/lower Es4 (the fourth member of Shahejie formation), Es3(the third member of Shahejie formation)/ Es4 and Es4/Ek (Kongdian formation). Tectonic and paleo-environmental changes happened at the three boundaries have been investigated and the results can be concluded as follows: ①unconformity of upper/lower Es4 is more widespread and easier to identify compared with the unconformities of Es3/Es4 and Es4/Ek; ②tectonic stress characteristics indicated by fault activity modes and basin stretch directs were obviously different in the upper and lower Es4 but similar in the lower Es4 and Ek, the upper Es4 and Es3; ③climatic environment change happened at the upper/lower Es4 period was sharper than those happened at the Ek/lower Es4 and the upper Es4/Es3 period. It is ascertained that the order of upper/lower Es4 boundary is a secondary order, which is higher than those of Es4/Ek and Es3/Es4 boundary. Thus, there are three secondary-order sequences in Palaeogene which correspond to lithological stratum of Ek-lower Es4, upper Es4-lower Es2 (the second member of Shahejie formation) and upper Es2-Ed(Dongying formation) respectively. The new classification pattern of secondary-order sequence could not only give rational explanation to the lithological change in Es4 but also provide guidance to oil and gas exploration in Es4.
In order to ascertain the secondary-order sequence boundary of Palaeogene in Jiyang depression, geophysical, geochemical and paleontological data were used to study and compare the feature of three boundaries of upper/lower Es4 (the fourth member of Shahejie formation), Es3(the third member of Shahejie formation)/ Es4 and Es4/Ek (Kongdian formation). Tectonic and paleo-environmental changes happened at the three boundaries have been investigated and the results can be concluded as follows: ①unconformity of upper/lower Es4 is more widespread and easier to identify compared with the unconformities of Es3/Es4 and Es4/Ek; ②tectonic stress characteristics indicated by fault activity modes and basin stretch directs were obviously different in the upper and lower Es4 but similar in the lower Es4 and Ek, the upper Es4 and Es3; ③climatic environment change happened at the upper/lower Es4 period was sharper than those happened at the Ek/lower Es4 and the upper Es4/Es3 period. It is ascertained that the order of upper/lower Es4 boundary is a secondary order, which is higher than those of Es4/Ek and Es3/Es4 boundary. Thus, there are three secondary-order sequences in Palaeogene which correspond to lithological stratum of Ek-lower Es4, upper Es4-lower Es2 (the second member of Shahejie formation) and upper Es2-Ed(Dongying formation) respectively. The new classification pattern of secondary-order sequence could not only give rational explanation to the lithological change in Es4 but also provide guidance to oil and gas exploration in Es4.
2014, 21(5):8-13.
Abstract:
The new edition of The estimated methods of oil recoverable reserves is the national industry standards released by National Energy Administration on 15th December, 2010. It has been acting on for more than 3 years and is important for the assessment of oil recoverable reserves. The calculation method of oil recoverable reserves is the core part of the standard and has effects on the reliability and availability of the results and also the investment risk assessments. Therefore, attentions should be paid to the calculation methods selection. The calculation methods in the new standard include analogy method, empirical formula method, oil displacement efficiency method, production decline method and water drive curve method. In this paper, the uncertainty and the unreliability of these calculation methods were proposed along with the specific recommendations which can be concluded as follows: delete some empirical formula of less credibility, adopt some overseas empirical formula proved by practical application, modify some empirical and production decline formula, use the methods of linear trial and error, curve displacement, and typical curve fitting to determine the decline type and decline parameters, delete some water drive curves derived from A and B water drive characteristic curve, and add the method of prediction model.
The new edition of The estimated methods of oil recoverable reserves is the national industry standards released by National Energy Administration on 15th December, 2010. It has been acting on for more than 3 years and is important for the assessment of oil recoverable reserves. The calculation method of oil recoverable reserves is the core part of the standard and has effects on the reliability and availability of the results and also the investment risk assessments. Therefore, attentions should be paid to the calculation methods selection. The calculation methods in the new standard include analogy method, empirical formula method, oil displacement efficiency method, production decline method and water drive curve method. In this paper, the uncertainty and the unreliability of these calculation methods were proposed along with the specific recommendations which can be concluded as follows: delete some empirical formula of less credibility, adopt some overseas empirical formula proved by practical application, modify some empirical and production decline formula, use the methods of linear trial and error, curve displacement, and typical curve fitting to determine the decline type and decline parameters, delete some water drive curves derived from A and B water drive characteristic curve, and add the method of prediction model.
2014, 21(5):14-17.
Abstract:
Many shallow gas or heavy oil reservoirs have been found over 50 years of exploration and development in Jiyang depression.Research on the distribution pattern and origin of shallow gas and heavy oil is very important to guide future exploration of oil and gas.Two conclusions were drawn by analyzing the spatial distribution and geochemical characteristics: ①The distribution of shallow gas and heavy oil reservoirs are paragenetic. Shallow gas reservoirs often develop above or in the updip direction of heavy oil reservoirs.Meanwhile, heavy oil reservoirs exist under or in the downdip direction of many shallow gas reservoirs；②Shallow gas and heavy oil reservoirs have symbiotic genesis. Shallow gas reservoirs consist mostly of biodegraded and released dissolved-gas which mainly come from underlying or downdip reservoirs. Consequently, oil in these reservoirs becomes heavy oil due to biodegradation and natural gas dispersion. This paper proposes some ways to explore shallow gas and heavy oil reservoirs jointly: search for heavy oil reservoirs according to the distribution of known shallow gas reservoirs and vice versa; or use seismic bright spot to locate gas reservoirs, and discover related heavy oil reservoirs via these gas reservoirs.
Many shallow gas or heavy oil reservoirs have been found over 50 years of exploration and development in Jiyang depression.Research on the distribution pattern and origin of shallow gas and heavy oil is very important to guide future exploration of oil and gas.Two conclusions were drawn by analyzing the spatial distribution and geochemical characteristics: ①The distribution of shallow gas and heavy oil reservoirs are paragenetic. Shallow gas reservoirs often develop above or in the updip direction of heavy oil reservoirs.Meanwhile, heavy oil reservoirs exist under or in the downdip direction of many shallow gas reservoirs；②Shallow gas and heavy oil reservoirs have symbiotic genesis. Shallow gas reservoirs consist mostly of biodegraded and released dissolved-gas which mainly come from underlying or downdip reservoirs. Consequently, oil in these reservoirs becomes heavy oil due to biodegradation and natural gas dispersion. This paper proposes some ways to explore shallow gas and heavy oil reservoirs jointly: search for heavy oil reservoirs according to the distribution of known shallow gas reservoirs and vice versa; or use seismic bright spot to locate gas reservoirs, and discover related heavy oil reservoirs via these gas reservoirs.
4 The strike slip structure and its influences on the formation of petroleum reservoir in Qingdong sag
2014, 21(5):18-21.
Abstract:
Qingdong sag is a Cenozoic faulted basin, whose east boundary is defined by the west branch of Tanlu fault zone. Affected by the strike slip displacement of the boundary fault and the regional tectonic stress field, there are many structures showing obvious strike slip characteristics in Qingdong sag, such as the large strike slip boundary faults, the antiformal negative flower structure and compresso-shear folded structure. After three fault-subsidence periods and two reversion stages, these structures are mostly compound structures. The strike slip structures have great influences on the thermal evolution of hydrocarbon source rock, the formation of structural trap and the migration and accumulation of petroleum in Qingdong sag. Three patterns of petroleum migration and accumulation, which control the abundance and distribution of petroleum reservoirs, are recognized in Qingdong sag.
Qingdong sag is a Cenozoic faulted basin, whose east boundary is defined by the west branch of Tanlu fault zone. Affected by the strike slip displacement of the boundary fault and the regional tectonic stress field, there are many structures showing obvious strike slip characteristics in Qingdong sag, such as the large strike slip boundary faults, the antiformal negative flower structure and compresso-shear folded structure. After three fault-subsidence periods and two reversion stages, these structures are mostly compound structures. The strike slip structures have great influences on the thermal evolution of hydrocarbon source rock, the formation of structural trap and the migration and accumulation of petroleum in Qingdong sag. Three patterns of petroleum migration and accumulation, which control the abundance and distribution of petroleum reservoirs, are recognized in Qingdong sag.
2014, 21(5):22-26.
Abstract:
There are karst fractured/caverned reservoir formed by multi-phase karstification in Tabei uplift and Tazhong lower uplift of Tarim basin, but large scale karst-cave layer have not yet been found in the Bachu uplift. The Yingshan Formation in Xianbazha 3D area of the western Bachu denudation area is directly covered by the Silurian formation. During the middle-Caledonian, the Yingshan Formation exposed to surface for a long time and developed karst cave after atmospheric water eluviation. The branch-like river was mature and had steady valley, which indicates a good lithologic-structural condition and abundant atmospheric fresh water in this area.Therefore, the surface karst is quite developed; drainage for the subterranean rivers, which had a few branches, was mainly controlled by the distribution of the trunk of surface rivers and scattered depressions. It is suggested that the subterranean rivers did not form a system of hydrologic groundwater network, so that underground karst development is confined. Based on analyses of karst characteristics in this area and analog study of karst in Xikeer outcrop, the reasons for the low level of underground karst development were sum? marized as follows:①incomplete karst development; ②cavern filling ; ③layers having developed solution pore and cave .
There are karst fractured/caverned reservoir formed by multi-phase karstification in Tabei uplift and Tazhong lower uplift of Tarim basin, but large scale karst-cave layer have not yet been found in the Bachu uplift. The Yingshan Formation in Xianbazha 3D area of the western Bachu denudation area is directly covered by the Silurian formation. During the middle-Caledonian, the Yingshan Formation exposed to surface for a long time and developed karst cave after atmospheric water eluviation. The branch-like river was mature and had steady valley, which indicates a good lithologic-structural condition and abundant atmospheric fresh water in this area.Therefore, the surface karst is quite developed; drainage for the subterranean rivers, which had a few branches, was mainly controlled by the distribution of the trunk of surface rivers and scattered depressions. It is suggested that the subterranean rivers did not form a system of hydrologic groundwater network, so that underground karst development is confined. Based on analyses of karst characteristics in this area and analog study of karst in Xikeer outcrop, the reasons for the low level of underground karst development were sum? marized as follows:①incomplete karst development; ②cavern filling ; ③layers having developed solution pore and cave .
6 Controlling factors of gypsolith sedimentary and its impact on hydrocarbon reservoirs
in Dongpu sag
2014, 21(5):27-31.
Abstract:
The Dongpu sag locates at the most southern part of the Bohaiwan Basin, there are 4 big sets of the gypsolith rhythmic formations. The reservoir exploration and development practices show that the hydrocarbon accumulation and distribution are closely related to the gypsolith sedimentary in the basin. Based on the principles of sedimentology, structural geology, reservoir geology, geochemistry and previous research and achievements，the controlling factors of the gypsolith distribution was studied using core data, well logging,geophysics and experiment data. It is indicated that synsedimentary faults control the local distribution and sedimentary thickness of the gypsolith. Additionally, the palaeotopography and ancient sources direction control and affect the planar distribution and pattern.The gypsolith sedimentary plays an important role in the formation of abnormal pressure, hydrocarbon lateral block and even hydrocarbon generation, migration and accumulation. Thus, the research achievements provide guidance for the further subtle reservoir exploration, progressive exploration and development, and also exploration in the similar gypsolith-bearing basin.
The Dongpu sag locates at the most southern part of the Bohaiwan Basin, there are 4 big sets of the gypsolith rhythmic formations. The reservoir exploration and development practices show that the hydrocarbon accumulation and distribution are closely related to the gypsolith sedimentary in the basin. Based on the principles of sedimentology, structural geology, reservoir geology, geochemistry and previous research and achievements，the controlling factors of the gypsolith distribution was studied using core data, well logging,geophysics and experiment data. It is indicated that synsedimentary faults control the local distribution and sedimentary thickness of the gypsolith. Additionally, the palaeotopography and ancient sources direction control and affect the planar distribution and pattern.The gypsolith sedimentary plays an important role in the formation of abnormal pressure, hydrocarbon lateral block and even hydrocarbon generation, migration and accumulation. Thus, the research achievements provide guidance for the further subtle reservoir exploration, progressive exploration and development, and also exploration in the similar gypsolith-bearing basin.
2014, 21(5):32-35.
Abstract:
The shallow reservoirs of Youquanzi oil field in the northwest Qaidam basin are characteristic of abnormal low pressure.Based on the study of low pressure distribution, the main controlling factors of low-pressure reservoirs formation in the Youquanzi were analyzed including fluid features, seal mechanism, structural evolution and sedimentary characteristics. The seal conditions, formation mechanism and the relationship between pressure evolution and hydrocarbon accumulation in the shallow reservoirs were discussed.The study results show that: the formation water type is CaCl2 with high salinity and low ratio of Na+ and Cl- , which reflects a good sealing capability; additionally, the light density and low viscosity of crude oil also reflect good sealing conditions of the shallow reservoirs. The plastic gypsum mudstone deposited in saline lacustrine, the bitumen plug, the thrust fault plane and the reservoir heterogeneity provide both vertical and lateral sealing conditions. Methods of EASY%Ro and stratigraphic correlation were used to estimate the late Neogene denudation thickness of Youquanzi with a result of 2 700 m. Influenced by the intense tectonic uplift, the pore rebounded and the temperature decreased, which lead to a pressure drop of 14.1 MPa and 7.4 MPa respectively. The abnormal low pressure of the shallow reservoirs in Youquanzi oilfield is controlled by multi effects of sedimentary assemblage, tectonic evolution and hydrocarbon accumulation.
The shallow reservoirs of Youquanzi oil field in the northwest Qaidam basin are characteristic of abnormal low pressure.Based on the study of low pressure distribution, the main controlling factors of low-pressure reservoirs formation in the Youquanzi were analyzed including fluid features, seal mechanism, structural evolution and sedimentary characteristics. The seal conditions, formation mechanism and the relationship between pressure evolution and hydrocarbon accumulation in the shallow reservoirs were discussed.The study results show that: the formation water type is CaCl2 with high salinity and low ratio of Na+ and Cl- , which reflects a good sealing capability; additionally, the light density and low viscosity of crude oil also reflect good sealing conditions of the shallow reservoirs. The plastic gypsum mudstone deposited in saline lacustrine, the bitumen plug, the thrust fault plane and the reservoir heterogeneity provide both vertical and lateral sealing conditions. Methods of EASY%Ro and stratigraphic correlation were used to estimate the late Neogene denudation thickness of Youquanzi with a result of 2 700 m. Influenced by the intense tectonic uplift, the pore rebounded and the temperature decreased, which lead to a pressure drop of 14.1 MPa and 7.4 MPa respectively. The abnormal low pressure of the shallow reservoirs in Youquanzi oilfield is controlled by multi effects of sedimentary assemblage, tectonic evolution and hydrocarbon accumulation.
2014, 21(5):36-39.
Abstract:
The layer series of development in NP1-5 area of Nanpu sag is braided delta front deposits. It consists of a large number of layers with complex contact relationship. Based on the principle of reservoir hierarchical structure, the reservoir formation in the study area has been divided into 9 hierarchies. The 5th to 7th hierarchies are the focus of this study, which are single delta-front sand body,single genesis sand body, single channel sand body. According to the characteristic of the interbed, the deposition time unit (single sand bed) was subdivided based on analyses of layers; according to the characteristic of microfacies, single genesis sand body was identified; according to the characteristic of well log, altitude and thickness, the single channel sand body in the main single genesis sand (underwater distributary channel) was identified. Findings show the single-channel sand bodies in the study area are always lay banded with a thickness of 3-5 m and a maximum width of 400 m. The single-channel sands cut into each other and build up the wide range of underwater distributary channel; by reworking from wave action and later erosion of underwater distributary channel, the channel border sand presents a sheet-like distribution; the mouth bar sand is rare and remainremains only in the interchannel.
The layer series of development in NP1-5 area of Nanpu sag is braided delta front deposits. It consists of a large number of layers with complex contact relationship. Based on the principle of reservoir hierarchical structure, the reservoir formation in the study area has been divided into 9 hierarchies. The 5th to 7th hierarchies are the focus of this study, which are single delta-front sand body,single genesis sand body, single channel sand body. According to the characteristic of the interbed, the deposition time unit (single sand bed) was subdivided based on analyses of layers; according to the characteristic of microfacies, single genesis sand body was identified; according to the characteristic of well log, altitude and thickness, the single channel sand body in the main single genesis sand (underwater distributary channel) was identified. Findings show the single-channel sand bodies in the study area are always lay banded with a thickness of 3-5 m and a maximum width of 400 m. The single-channel sands cut into each other and build up the wide range of underwater distributary channel; by reworking from wave action and later erosion of underwater distributary channel, the channel border sand presents a sheet-like distribution; the mouth bar sand is rare and remainremains only in the interchannel.
2014, 21(5):40-44.
Abstract:
Yuanba gas field lies in the weak deformation area with super-deep negative structure. The major carrier system is a 3D network complex that consists of porous-type dolomite reservoirs in Changxing formation and fractures (interbedded fracture, joint fissures and so on) , which is different from that in Puguang gas field. The multidirectional migration and near-source hydrocarbon accumulation are the favorable conditons of the carrier system. It can help the gas generated from the underlying Wujiaping Formation and lateral Dalong Formation to realize vertical and lateral hydrocarbon migration. The oil and gas accumulation zones are mainly controlled by the height and density of fractures and the distribution ranges and scales of high quality dolomite reservoirs that are characteristic of reef and shoal facies in the Changxing Formation.
Yuanba gas field lies in the weak deformation area with super-deep negative structure. The major carrier system is a 3D network complex that consists of porous-type dolomite reservoirs in Changxing formation and fractures (interbedded fracture, joint fissures and so on) , which is different from that in Puguang gas field. The multidirectional migration and near-source hydrocarbon accumulation are the favorable conditons of the carrier system. It can help the gas generated from the underlying Wujiaping Formation and lateral Dalong Formation to realize vertical and lateral hydrocarbon migration. The oil and gas accumulation zones are mainly controlled by the height and density of fractures and the distribution ranges and scales of high quality dolomite reservoirs that are characteristic of reef and shoal facies in the Changxing Formation.
2014, 21(5):45-48.
Abstract:
The Pengyang oilfield, next to the Xiyuan Thrust-belt of Ordos basin, is located in the southwest part of Tianhuan depression with a key target of the seventh, eighth and ninth member of Jurassic Yan’an Formation. Structure of the Yan’an Formation shows a complex NE-SW striking syncline with a saddle in the middle. The Yan’an Formation, unconformbly overlying the Triassic Yanchang Formation toward southwest, was deposited as sandy braided-river sediment under humid conditions with sandbodies having good lateral continuity, porosity and permeability. The Yan’an Formation reservoirs mainly sourced from carbonaceous mudstones and oil shales of the sixth and seventh member of Yanchang Formation. The source rock became mature since the late Jurassic and approached a climax of hydrocarbon generation during the late Cretaceous. It provided petroleum to the reservoirs by faults, fractures and the unconformity on top of the Yanchang Formation. Structure is the most important control on hydrocarbon accumulation of the Yan’an Formation sandstone reservoirs, followed by sandbody distribution and hydrocarbon preservation conditions. These three controls resulted in structural, structural-lithologic and stratigraphic overlap reservoirs. The northern and the eastern part of the studied area have better hydrocarbon preservation conditions than the other parts, in which low-amplitude anticline and nose are the most favorable areas for hydrocarbon accumulation in the Yan’an Formation.
The Pengyang oilfield, next to the Xiyuan Thrust-belt of Ordos basin, is located in the southwest part of Tianhuan depression with a key target of the seventh, eighth and ninth member of Jurassic Yan’an Formation. Structure of the Yan’an Formation shows a complex NE-SW striking syncline with a saddle in the middle. The Yan’an Formation, unconformbly overlying the Triassic Yanchang Formation toward southwest, was deposited as sandy braided-river sediment under humid conditions with sandbodies having good lateral continuity, porosity and permeability. The Yan’an Formation reservoirs mainly sourced from carbonaceous mudstones and oil shales of the sixth and seventh member of Yanchang Formation. The source rock became mature since the late Jurassic and approached a climax of hydrocarbon generation during the late Cretaceous. It provided petroleum to the reservoirs by faults, fractures and the unconformity on top of the Yanchang Formation. Structure is the most important control on hydrocarbon accumulation of the Yan’an Formation sandstone reservoirs, followed by sandbody distribution and hydrocarbon preservation conditions. These three controls resulted in structural, structural-lithologic and stratigraphic overlap reservoirs. The northern and the eastern part of the studied area have better hydrocarbon preservation conditions than the other parts, in which low-amplitude anticline and nose are the most favorable areas for hydrocarbon accumulation in the Yan’an Formation.
2014, 21(5):49-52.
Abstract:
There has been a great controversy over primary oil and gas reservoirs in the Meso-Neo Proterozoic. Meso-Neo Proterozoic primary reservoirs have not been found in China yet. Such findings will make a breakthrough in petroleum exploration of Meso-Neo Proterozoic. Abundant oil reserves have been found in the Meso-Neo Proterozoic of Damintun sag, which were considered as a type of young bed for source and old bed for storage. But in this study, the crude oil in the Meso-Neo Proterozoic reservoirs is different from that in the 3rd member of Shahejie Formation which indicates that other oil sources may exist. The Meso-Neo Proterozoic source rocks in the Damintun sag were studied and the result shows that they have high abundance and good type of organic matter, as well as a moderate degree of thermal maturation and a great potential of hydrocarbon generation. These all indicate that it may be an important oil source for the oil reservoirs in the Meso-Neo Proterozoic. The thermal simulation results of carbonate source rock samples show that the Meso-Neo Proterozoic source rocks have a good capacity of hydrocarbon generation.
There has been a great controversy over primary oil and gas reservoirs in the Meso-Neo Proterozoic. Meso-Neo Proterozoic primary reservoirs have not been found in China yet. Such findings will make a breakthrough in petroleum exploration of Meso-Neo Proterozoic. Abundant oil reserves have been found in the Meso-Neo Proterozoic of Damintun sag, which were considered as a type of young bed for source and old bed for storage. But in this study, the crude oil in the Meso-Neo Proterozoic reservoirs is different from that in the 3rd member of Shahejie Formation which indicates that other oil sources may exist. The Meso-Neo Proterozoic source rocks in the Damintun sag were studied and the result shows that they have high abundance and good type of organic matter, as well as a moderate degree of thermal maturation and a great potential of hydrocarbon generation. These all indicate that it may be an important oil source for the oil reservoirs in the Meso-Neo Proterozoic. The thermal simulation results of carbonate source rock samples show that the Meso-Neo Proterozoic source rocks have a good capacity of hydrocarbon generation.
12 Practical technology of inter- salt mudstone fracture prediction in the north of Dongpu depression
2014, 21(5):53-56.
Abstract:
There are no suitable technologies for the prediction of intra-salt mudstone fracture in the northern Dongpu depression.Based on the analysis of geology and geophysical characteristics of fractured mudstone reservoirs in the sag, it is concluded that the mudstone formations are easy to form tectonic fractures under tectonic deformation and with high content of brittle minerals. The geophysical characteristics of the fractured reservoirs are low-speed, low-impedance, low Poisson′s ratio and high resistivity etc. Accordingly, we proposed 2 fracture prediction technologies which are suitable for mudstone fractures of inter-salinastone overpressure and tectonic origin. The core technologies are based on residual structure analysis and generalized multi-attribute cluster analysis. The residual structural analysis technique considers conventional geological structure as three parts, namely, structure background, local tectonic deformation and random factor, and it highlights the changes of micro-curvature caused by local tectonic deformation which can be used in mudstone fracture prediction; the generalized multi-attribute clustering analysis technique combines seismic inversion meth?od and seismic attribute to achieve attributes optimization, and it uses neural network clustering analysis to predict the fracture zone in mudstone qualitatively. According to the practical application results, this 2 method had a good agreement. Based on the fracture prediction results, Pu-Shen 18-1 well in the Zhongyuan oilfield was drilled and has obtained a good oil and gas show in 10 sand group of Es3 at a depth of 3 258 m, and the daily oil production can reach 215-420 m3.
There are no suitable technologies for the prediction of intra-salt mudstone fracture in the northern Dongpu depression.Based on the analysis of geology and geophysical characteristics of fractured mudstone reservoirs in the sag, it is concluded that the mudstone formations are easy to form tectonic fractures under tectonic deformation and with high content of brittle minerals. The geophysical characteristics of the fractured reservoirs are low-speed, low-impedance, low Poisson′s ratio and high resistivity etc. Accordingly, we proposed 2 fracture prediction technologies which are suitable for mudstone fractures of inter-salinastone overpressure and tectonic origin. The core technologies are based on residual structure analysis and generalized multi-attribute cluster analysis. The residual structural analysis technique considers conventional geological structure as three parts, namely, structure background, local tectonic deformation and random factor, and it highlights the changes of micro-curvature caused by local tectonic deformation which can be used in mudstone fracture prediction; the generalized multi-attribute clustering analysis technique combines seismic inversion meth?od and seismic attribute to achieve attributes optimization, and it uses neural network clustering analysis to predict the fracture zone in mudstone qualitatively. According to the practical application results, this 2 method had a good agreement. Based on the fracture prediction results, Pu-Shen 18-1 well in the Zhongyuan oilfield was drilled and has obtained a good oil and gas show in 10 sand group of Es3 at a depth of 3 258 m, and the daily oil production can reach 215-420 m3.
2014, 21(5):57-60.
Abstract:
It is not easy to distinguish the effective and the invalid reservoir for tight sandstone reservoirs with low porosity and permeability. To develop tight sandstone reservoir economically and effectively, the effective thickness should be reconsidered. To study the characteristics of tight reservoirs with poor physical properties, we took reservoirs in the Funing Formation and Daiyi Member in Subei basin as an example. The relationship of four properties including lithology, physical property, oil-bearing property and electrical property was analyzed based on core analysis, formation testing, mercury injection, logs, etc. The lower limits of physical properties and electrical properties were studied using 5 methods, such as nuclear magnetic resonance, empirical statistics, minimum flow pore throat radius, etc. The results from different method agree with each other. Using the established lower limit standard, the effective thickness of five wells in the study area has been analyzed. The absolute error of logging interpreted effective thickness is -0.15 m by comparing with that defined by oil core. The accuracy of layer division is 100%. The proposed standard is in good agreement with the actual data and the operation is simple.
It is not easy to distinguish the effective and the invalid reservoir for tight sandstone reservoirs with low porosity and permeability. To develop tight sandstone reservoir economically and effectively, the effective thickness should be reconsidered. To study the characteristics of tight reservoirs with poor physical properties, we took reservoirs in the Funing Formation and Daiyi Member in Subei basin as an example. The relationship of four properties including lithology, physical property, oil-bearing property and electrical property was analyzed based on core analysis, formation testing, mercury injection, logs, etc. The lower limits of physical properties and electrical properties were studied using 5 methods, such as nuclear magnetic resonance, empirical statistics, minimum flow pore throat radius, etc. The results from different method agree with each other. Using the established lower limit standard, the effective thickness of five wells in the study area has been analyzed. The absolute error of logging interpreted effective thickness is -0.15 m by comparing with that defined by oil core. The accuracy of layer division is 100%. The proposed standard is in good agreement with the actual data and the operation is simple.
2014, 21(5):61-64.
Abstract:
Highly unbalanced displacement problems arise in low permeability reservoirs during high water cut period caused by interlayer heterogeneity of petrophysical properties. Radial drilling is one of the important technologies to solve this problem. Branch number and branch length are the mainly variables affecting the performance of radial drilling. To achieve equilibrium displacement, an optimization model of the radial drilling branch length and number was established for two-layer comingled production reservoir by considering the inter-layer heterogeneities and displacement, and the corresponding calculation program were developed. Using reservoir numerical simulation technology, the prediction results show that radial drilling can solve the unbalanced displacement problems effectively and also prove the accuracy and applicability of this model.
Highly unbalanced displacement problems arise in low permeability reservoirs during high water cut period caused by interlayer heterogeneity of petrophysical properties. Radial drilling is one of the important technologies to solve this problem. Branch number and branch length are the mainly variables affecting the performance of radial drilling. To achieve equilibrium displacement, an optimization model of the radial drilling branch length and number was established for two-layer comingled production reservoir by considering the inter-layer heterogeneities and displacement, and the corresponding calculation program were developed. Using reservoir numerical simulation technology, the prediction results show that radial drilling can solve the unbalanced displacement problems effectively and also prove the accuracy and applicability of this model.
2014, 21(5):65-68.
Abstract:
This study has discussed factors that influence the precision of conventional reservoir numerical simulation, including the accuracy of reservoir description, relative permeability curve selection, dynamic data entry, and grid precision. To improve the precision,many methods were used including staged numerical simulation, relative permeability curve in stages assignment, endpoint value calibration, grid scale processing in high water cut period, subdivided layers water injection. Compared with the traditional numerical simulation technology, the staged numerical simulation technology is more reliable, especially when the oilfield enters the extra high water cut development period with highly scattered remaining oil distribution. By using staged numerical simulation, the distribution of remaining oil saturation field is more accurate which can facilitate the late development of oilfield.
This study has discussed factors that influence the precision of conventional reservoir numerical simulation, including the accuracy of reservoir description, relative permeability curve selection, dynamic data entry, and grid precision. To improve the precision,many methods were used including staged numerical simulation, relative permeability curve in stages assignment, endpoint value calibration, grid scale processing in high water cut period, subdivided layers water injection. Compared with the traditional numerical simulation technology, the staged numerical simulation technology is more reliable, especially when the oilfield enters the extra high water cut development period with highly scattered remaining oil distribution. By using staged numerical simulation, the distribution of remaining oil saturation field is more accurate which can facilitate the late development of oilfield.
2014, 21(5):69-72.
Abstract:
The existence of dominant flowing channels after polymer flooding leads to low sweep efficiency and then further results of low recovery factor. So it is urgent to solve the problem of how to describe the distribution and seepage characteristics of dominant flowing channels effectively in the process of Daqing oilfield development after polymer flooding. According to the data of pressure cored wells and logging, the definition and distribution features of dominant flowing channels are determined after polymer flooding, then their seepage characteristics is studied by physical modeling and numerical modeling, etc. The thickness percentage of dominant flowing channels is increased by 9.3% than that before polymer flooding. They are mainly concentrated in the thick oil layers vertically and distribute in a wide range horizontally. The thickness percentage of dominant flowing channels is about 20%, but the flux ratio of them can reach up to more than 50% leading to serious invalid circulation. The study of dominant flowing channels distribution and seepage characteristics after polymer flooding provides a foundation for following plugging scenario design, which can further enhance oil recovery after polymer flooding.
The existence of dominant flowing channels after polymer flooding leads to low sweep efficiency and then further results of low recovery factor. So it is urgent to solve the problem of how to describe the distribution and seepage characteristics of dominant flowing channels effectively in the process of Daqing oilfield development after polymer flooding. According to the data of pressure cored wells and logging, the definition and distribution features of dominant flowing channels are determined after polymer flooding, then their seepage characteristics is studied by physical modeling and numerical modeling, etc. The thickness percentage of dominant flowing channels is increased by 9.3% than that before polymer flooding. They are mainly concentrated in the thick oil layers vertically and distribute in a wide range horizontally. The thickness percentage of dominant flowing channels is about 20%, but the flux ratio of them can reach up to more than 50% leading to serious invalid circulation. The study of dominant flowing channels distribution and seepage characteristics after polymer flooding provides a foundation for following plugging scenario design, which can further enhance oil recovery after polymer flooding.
2014, 21(5):73-76.
Abstract:
Water cut rises quickly in the middle and later periods of ASP flooding in Daqing oilfield, which leads to considerable discrepancies in development situations of reservoirs with different permeability and invalid injected liquid cycle. Aiming at these problems, the preparation of resisted alkali profile control agent in ASP flooding was carried out. Through choosing crosslinking agent and crosslinking agent concentration, polymer concentration and molecular weight and polymer maturing time, along with orthogonal experiment, the resisted alkali profile control agent formula fitting for ASP flooding was prepared. The formula was made up of polymer, ion crosslinking agent, organic crosslinking agent, stabilizer and deoxidant (polymer: molecular weight was 2 500×104 and its concentration was 2 000 mg/L; metallic crosslinking agent: YH-1 and its concentration was 0.15%; organic chromium: THM-1, THM-2 and their concentrations were 0.1%, 0.08% respectively; stabilizing agent: concentration was 0.2%; deoxidant: concentration was 0.1%). The gelation time was 102 hours and is adjustable. The viscosity after gelatinizing was 3 510 mPa?s. The stability time of gel was greater than 60 days. It had good salt resistance and small impact on interfacial tension of ASP system. When the profile control agent was applied to the process of ASP flooding, it can enable more injection liquid to displace low and medium permeable layer, and it can enhance oil recovery by 4% compared with that of ASP flooding without profile control agent. The numerical simulation results showed that the profile agent could keep better gelation performance by adding a small amount of pre-polymer slug before injecting profile control agent to achieve a better development effect.
Water cut rises quickly in the middle and later periods of ASP flooding in Daqing oilfield, which leads to considerable discrepancies in development situations of reservoirs with different permeability and invalid injected liquid cycle. Aiming at these problems, the preparation of resisted alkali profile control agent in ASP flooding was carried out. Through choosing crosslinking agent and crosslinking agent concentration, polymer concentration and molecular weight and polymer maturing time, along with orthogonal experiment, the resisted alkali profile control agent formula fitting for ASP flooding was prepared. The formula was made up of polymer, ion crosslinking agent, organic crosslinking agent, stabilizer and deoxidant (polymer: molecular weight was 2 500×104 and its concentration was 2 000 mg/L; metallic crosslinking agent: YH-1 and its concentration was 0.15%; organic chromium: THM-1, THM-2 and their concentrations were 0.1%, 0.08% respectively; stabilizing agent: concentration was 0.2%; deoxidant: concentration was 0.1%). The gelation time was 102 hours and is adjustable. The viscosity after gelatinizing was 3 510 mPa?s. The stability time of gel was greater than 60 days. It had good salt resistance and small impact on interfacial tension of ASP system. When the profile control agent was applied to the process of ASP flooding, it can enable more injection liquid to displace low and medium permeable layer, and it can enhance oil recovery by 4% compared with that of ASP flooding without profile control agent. The numerical simulation results showed that the profile agent could keep better gelation performance by adding a small amount of pre-polymer slug before injecting profile control agent to achieve a better development effect.
2014, 21(5):77-80.
Abstract:
Dynamic relationship among factors have not been taken into consideration in the application of oilfield output prediction method. Time series transfer function method is firstly applied to build a multiple factor oilfield output prediction model considering dynamic relationship. Taking new wells output of one oilfield in Shengli Region for example, data preparation, model recognition, parameter estimation, diagnosis and checking and prediction process of transfer function model are illustrated according to its modeling work flow. The study result shows that this prediction model can remove irrelevant elements from multifarious factors and identify the main controlling factors on oilfield output prediction, and it can also observe the dynamic relationship of factors with non-synchronization and hysteresis. The precision is high and up to 98.4%.
Dynamic relationship among factors have not been taken into consideration in the application of oilfield output prediction method. Time series transfer function method is firstly applied to build a multiple factor oilfield output prediction model considering dynamic relationship. Taking new wells output of one oilfield in Shengli Region for example, data preparation, model recognition, parameter estimation, diagnosis and checking and prediction process of transfer function model are illustrated according to its modeling work flow. The study result shows that this prediction model can remove irrelevant elements from multifarious factors and identify the main controlling factors on oilfield output prediction, and it can also observe the dynamic relationship of factors with non-synchronization and hysteresis. The precision is high and up to 98.4%.
2014, 21(5):81-83.
Abstract:
During the development process of heavy oil reservoir with active edge water, edge water invasion will cause the water cut of production well to rise rapidly and the consequent low oil recovery efficiency. In order to better understandings of edge water drive law of offshore heavy oil reservoir and its effects on remaining oil distribution, 2D visible physical models with different well-type have been built, which are based on geological characteristics and development features of offshore heavy oil reservoir. The experimental results are shown as follows. First, edge water primarily encroaches through the areas of maximum pressure gradient in homogeneous reservoir. However, for heterogeneous reservoir, edge water mainly encroaches through high permeability part and the areas with maximum pressure gradient. Meanwhile, in comparison with heterogeneous reservoir, a more distinct water/oil front and higher reserve recovery degree will be obtained in homogeneous reservoir under the same conditions. Second, there is a higher reserve recovery degree obtained by double vertical wells compared with single vertical well. Thus, increasing the number of production well is beneficial to the improvement of reserve recovery degree. Third, horizontal well has a better effect on reservoir development than vertical well.
During the development process of heavy oil reservoir with active edge water, edge water invasion will cause the water cut of production well to rise rapidly and the consequent low oil recovery efficiency. In order to better understandings of edge water drive law of offshore heavy oil reservoir and its effects on remaining oil distribution, 2D visible physical models with different well-type have been built, which are based on geological characteristics and development features of offshore heavy oil reservoir. The experimental results are shown as follows. First, edge water primarily encroaches through the areas of maximum pressure gradient in homogeneous reservoir. However, for heterogeneous reservoir, edge water mainly encroaches through high permeability part and the areas with maximum pressure gradient. Meanwhile, in comparison with heterogeneous reservoir, a more distinct water/oil front and higher reserve recovery degree will be obtained in homogeneous reservoir under the same conditions. Second, there is a higher reserve recovery degree obtained by double vertical wells compared with single vertical well. Thus, increasing the number of production well is beneficial to the improvement of reserve recovery degree. Third, horizontal well has a better effect on reservoir development than vertical well.
2014, 21(5):84-86.
Abstract:
The purpose of this study is to predict water influx and economic recoverable reserves accurately and simply in water-drive oil field. The calculation of water influx and economic recoverable reserves were based on the present production performance and Zhang’s water drive curve, and we have studied the characteristics of oil-water flow by using Welge equation. Then, according to water influx material balance principle, a new calculation model for water influx was established. This paper also proposed a method for determination of economic limit water-cut to predict economic recoverable reserves of oil fields. The economic recoverable reserves can be calculated on the basis of the economic limit water-cut. The case study shows that calculation process of the new method is simple and the results are accurate and practical.
The purpose of this study is to predict water influx and economic recoverable reserves accurately and simply in water-drive oil field. The calculation of water influx and economic recoverable reserves were based on the present production performance and Zhang’s water drive curve, and we have studied the characteristics of oil-water flow by using Welge equation. Then, according to water influx material balance principle, a new calculation model for water influx was established. This paper also proposed a method for determination of economic limit water-cut to predict economic recoverable reserves of oil fields. The economic recoverable reserves can be calculated on the basis of the economic limit water-cut. The case study shows that calculation process of the new method is simple and the results are accurate and practical.
21 Cyclic steam injection volume optimization of steam huff and puff in offshore heavy oil reservoirs
2014, 21(5):87-89.
Abstract:
Due to the big discrepancy between onshore and offshore oilfields, the development of cyclic steam stimulation in offshore oilfields appears to be more complicated. And a reasonable choice of steam injection volume has attracted increasingly wide attention.Based on the heavy oil reservoir in Bohai oilfield, a numerical simulation model of cyclic steam stimulation was built based on the characteristics of offshore oilfields. The numerical simulation was used to optimize the cyclic steam injection volume. First, seven kinds of programs were designed on steam injection slug size for qualitative research. For the best result, twelve kinds of programs were designed for quantitative research. The results show cycle steam injection volume should be increased with increasing number of cycles,and the increasing rate of each cycle steam injection is 20% with best results. The results can provide theoretical guidance for cyclic steam injection volume optimization of steam huff and puff in offshore oilfields.
Due to the big discrepancy between onshore and offshore oilfields, the development of cyclic steam stimulation in offshore oilfields appears to be more complicated. And a reasonable choice of steam injection volume has attracted increasingly wide attention.Based on the heavy oil reservoir in Bohai oilfield, a numerical simulation model of cyclic steam stimulation was built based on the characteristics of offshore oilfields. The numerical simulation was used to optimize the cyclic steam injection volume. First, seven kinds of programs were designed on steam injection slug size for qualitative research. For the best result, twelve kinds of programs were designed for quantitative research. The results show cycle steam injection volume should be increased with increasing number of cycles,and the increasing rate of each cycle steam injection is 20% with best results. The results can provide theoretical guidance for cyclic steam injection volume optimization of steam huff and puff in offshore oilfields.
2014, 21(5):90-93.
Abstract:
The majority of remaining non-producing reserves in Daniudi gas field are Ⅱ-Ⅲ low-grade reserves, and horizontal well development will be the primary way for gas field productivity construction. Therefore, the optimization study on the multi-stage fracturing development technology policy of horizontal well is extremely significant. Based on numerical simulation model of multi-stage fractured horizontal wells, the paper investigated single well design, pressure cracks, well pattern and well spacing. The study eventually demonstrates that the extending direction of single well horizontal section should be perpendicular to the maximum principal stress direction. Horizontal section is better to be located in the middle of gas reservoir. Crushed fractures crossing gas-bearing sand body with a crenellated distribution are optimal. When average half- length of the fracture is 158 meters and average fracture spacing is 112 meters, row-interleaving well patter is optimum. Combined with numerical simulation method, dynamic analysis method and economic evaluation method, it is suggested that the reasonable well spacing in Da98 well area ranges from 1 000 meters to 1 200 meters, and well array spacing is 700 meters.
The majority of remaining non-producing reserves in Daniudi gas field are Ⅱ-Ⅲ low-grade reserves, and horizontal well development will be the primary way for gas field productivity construction. Therefore, the optimization study on the multi-stage fracturing development technology policy of horizontal well is extremely significant. Based on numerical simulation model of multi-stage fractured horizontal wells, the paper investigated single well design, pressure cracks, well pattern and well spacing. The study eventually demonstrates that the extending direction of single well horizontal section should be perpendicular to the maximum principal stress direction. Horizontal section is better to be located in the middle of gas reservoir. Crushed fractures crossing gas-bearing sand body with a crenellated distribution are optimal. When average half- length of the fracture is 158 meters and average fracture spacing is 112 meters, row-interleaving well patter is optimum. Combined with numerical simulation method, dynamic analysis method and economic evaluation method, it is suggested that the reasonable well spacing in Da98 well area ranges from 1 000 meters to 1 200 meters, and well array spacing is 700 meters.
2014, 21(5):94-97.
Abstract:
Based on non-Darcy gas seepage characteristics in porous media, a new productivity equation was presented for tight reservoirs in pseudo-steady state considering the effect of power function stress sensitivity. And the open flow capacity calculation formula of gas wells was derived. The computation result of an example showed that: the stress sensitivity phenomenon reduced the productivity and open flow capacity of gas wells in pseudo-steady flow period. The productivity curve of producer bended towards the pressure axis and the productivity was lower than that calculated from the equation without stress sensitive coefficient under the same producing pressure drop. The larger the power function stress sensitive coefficient was, the earlier and severer the productivity curve bended, and the lower the productivity was and the larger the yield reduction rate was. With the decline of reservoir pressure, the effect of stress sensitivity would be reduced for producing well. It would be appropriate to enlarge producing pressure drop when the average formation pressure was lower.
Based on non-Darcy gas seepage characteristics in porous media, a new productivity equation was presented for tight reservoirs in pseudo-steady state considering the effect of power function stress sensitivity. And the open flow capacity calculation formula of gas wells was derived. The computation result of an example showed that: the stress sensitivity phenomenon reduced the productivity and open flow capacity of gas wells in pseudo-steady flow period. The productivity curve of producer bended towards the pressure axis and the productivity was lower than that calculated from the equation without stress sensitive coefficient under the same producing pressure drop. The larger the power function stress sensitive coefficient was, the earlier and severer the productivity curve bended, and the lower the productivity was and the larger the yield reduction rate was. With the decline of reservoir pressure, the effect of stress sensitivity would be reduced for producing well. It would be appropriate to enlarge producing pressure drop when the average formation pressure was lower.
2014, 21(5):98-100.
Abstract:
High degree of reserve recovery disparities between layers is one of the main issues in multi-layer commingled reservoir at high water-cut stage. A correct understanding of inter-layer recovery degree has important guiding significance in making development decisions. Water injection profile data are important information that reflecting water injective behavior in different layers. Differences of water absorption capacity between different layers are mainly affected by reservoir petrophysical properties and remaining oil saturation. Based on hydropower similarity principle and non-piston type water displacing theory, a calculation method of inter-layer average remaining oil saturation in multi-layer commingled reservoir was established using water injection profile data. According to the results of numerical simulation, the relative error of the calculated results based on this method is less than 5%.
High degree of reserve recovery disparities between layers is one of the main issues in multi-layer commingled reservoir at high water-cut stage. A correct understanding of inter-layer recovery degree has important guiding significance in making development decisions. Water injection profile data are important information that reflecting water injective behavior in different layers. Differences of water absorption capacity between different layers are mainly affected by reservoir petrophysical properties and remaining oil saturation. Based on hydropower similarity principle and non-piston type water displacing theory, a calculation method of inter-layer average remaining oil saturation in multi-layer commingled reservoir was established using water injection profile data. According to the results of numerical simulation, the relative error of the calculated results based on this method is less than 5%.
2014, 21(5):101-103.
Abstract:
In order to expound the influence of interactions between organic alkali ethanolamine and crude oil fractions in Shengtuo 28 block crude oil on the interfacial tension, the crude oil fractions (saturates, aromatics, resins and asphaltenes) were obtained by classic SARA method. The acidic components were extracted from Tuo 28 block crude oil by using NaOH/EtOH mixed solution. The dynamic interfacial tensions between all crude oil fractions and ethanolamine were investigated by means of Spinning Drop method. The experimental results show that the key factors of reducing interfacial tension between organic alkali and model oils are the content and structure of petroleum acids. The minimum value of dynamic interfacial tension can reach 10-2 mN/m order of magnitude. The higher the content of petroleum acid is, the longer the low transient value of interfacial tension keeps. The order for the ability of Tuo 28 crude oil fractions to react with ethanolamine is: acidic components are the strongest; resins are next; asphaltenes, aromatics, and saturates are the weakest.
In order to expound the influence of interactions between organic alkali ethanolamine and crude oil fractions in Shengtuo 28 block crude oil on the interfacial tension, the crude oil fractions (saturates, aromatics, resins and asphaltenes) were obtained by classic SARA method. The acidic components were extracted from Tuo 28 block crude oil by using NaOH/EtOH mixed solution. The dynamic interfacial tensions between all crude oil fractions and ethanolamine were investigated by means of Spinning Drop method. The experimental results show that the key factors of reducing interfacial tension between organic alkali and model oils are the content and structure of petroleum acids. The minimum value of dynamic interfacial tension can reach 10-2 mN/m order of magnitude. The higher the content of petroleum acid is, the longer the low transient value of interfacial tension keeps. The order for the ability of Tuo 28 crude oil fractions to react with ethanolamine is: acidic components are the strongest; resins are next; asphaltenes, aromatics, and saturates are the weakest.
2014, 21(5):104-106.
Abstract:
In order to further enhance oil recovery in Zhenjing low permeability reservoirs, the air foam flooding EOR technology was researched through core displacement experiments. The experimental results suggested that air foam flooding after water flooding could improve oil displacement efficiency in low permeability reservoirs. Meanwhile, the development effect of following water flooding could be enhanced. The displacement efficiency for initial water flooding was 29.06%, and the following air foam flooding improved it for more than 10 percentage points. After water flooding again, the oil displacement efficiency could reach 45.42% for the average. The results also indicated that increasing injection rate or injection volume of air foam could improve the ultimate oil displacement efficiency with a shortened time of gas breakthrough, and gas channeling had little effect on oil recovery. Air foam flooding EOR technology using alternative injection of foaming agent solution and air was technically feasible for low permeability reservoirs based on water flooding.
In order to further enhance oil recovery in Zhenjing low permeability reservoirs, the air foam flooding EOR technology was researched through core displacement experiments. The experimental results suggested that air foam flooding after water flooding could improve oil displacement efficiency in low permeability reservoirs. Meanwhile, the development effect of following water flooding could be enhanced. The displacement efficiency for initial water flooding was 29.06%, and the following air foam flooding improved it for more than 10 percentage points. After water flooding again, the oil displacement efficiency could reach 45.42% for the average. The results also indicated that increasing injection rate or injection volume of air foam could improve the ultimate oil displacement efficiency with a shortened time of gas breakthrough, and gas channeling had little effect on oil recovery. Air foam flooding EOR technology using alternative injection of foaming agent solution and air was technically feasible for low permeability reservoirs based on water flooding.
27 Water sensitivity and its controlling factors on high-rank coal reservoirs in southern Qinshui basin
2014, 21(5):107-110.
Abstract:
During the coalbed methane (CBM) development process, the incompatilbility between working fluid and coal reservoir will result in water sensitivity, leading to a reduction in coal reservoir permeability and serious effects on the production of CBM wells.Therefore, water sensitivity evaluation of coal reservoirs and disscution on its controlling factors have a significant importance in improving the development efficiency of CBM. High-rank coal reservoirs in the southern Qinshui basin are characterized by low porosity and low permeability, and the conventional water-sensitive experimental method is no longer applicable in this area. This research proposed a new method for the evaluation of coal reservoir water sensitivity by using gas permeability instead of the traditional water permeability. Typical coal samples in the southern Qinshui basin were tested based on this method. Results show that: the water sensitivity in the study area is weak to moderate and is dominated by low water sensitivity; the controlling factors of water sensitivity in the southern Qinshui basin are permeability, clay mineral content and the occurrence type of clay minerals. The lower the coal reservoir permeability, the higher the clay mineral content and the higher the water sensitivity. The clay minerals in coal reservoirs have two types of occurrence: fracture filling and cavity filling of plant cells in the coal matrix, and the water sensitivity caused by fracture filling is higher than that caused by cavity filling.
During the coalbed methane (CBM) development process, the incompatilbility between working fluid and coal reservoir will result in water sensitivity, leading to a reduction in coal reservoir permeability and serious effects on the production of CBM wells.Therefore, water sensitivity evaluation of coal reservoirs and disscution on its controlling factors have a significant importance in improving the development efficiency of CBM. High-rank coal reservoirs in the southern Qinshui basin are characterized by low porosity and low permeability, and the conventional water-sensitive experimental method is no longer applicable in this area. This research proposed a new method for the evaluation of coal reservoir water sensitivity by using gas permeability instead of the traditional water permeability. Typical coal samples in the southern Qinshui basin were tested based on this method. Results show that: the water sensitivity in the study area is weak to moderate and is dominated by low water sensitivity; the controlling factors of water sensitivity in the southern Qinshui basin are permeability, clay mineral content and the occurrence type of clay minerals. The lower the coal reservoir permeability, the higher the clay mineral content and the higher the water sensitivity. The clay minerals in coal reservoirs have two types of occurrence: fracture filling and cavity filling of plant cells in the coal matrix, and the water sensitivity caused by fracture filling is higher than that caused by cavity filling.
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