Volume 21,Issue 6,2014 Table of Contents
2014, 21(6):1-5.
Abstract:
Differential accumulation mode is one of the classic mode in the petroleum geology which suggests a series of conditions including a single source rock or a sustained hydrocarbon-generation evolution, a continuous hydrocarbon expulsion process, a buoyancy-based secondary migration process, a carrier system mainly based on permeable and connected sand bodies, and a unified fluid dynamic systems; current reservoir-forming theory in the continental rift basin mainly focus on continuous hydrocarbon-generation, evolutionary process, episodic charging process, carrier system time and space finiteness, abnormal fluid compartment and isolated-fluid system. This paper argues that hydrocarbon migration and accumulation suitable for differential accumulation mode can only be a special simple state. Oil and gas filling is likely to occur within a certain range of basin carrier system. The difference exists in the number of fillings. It will be discussed in practice about whether the influence of basin-scale series traps accumulation mode is a complex superimposition of a number of differential accumulation process or a simple superimposition of several periods of differential accumulation,and the influences on reservoir type and space distribution mode of different fluid are also uncertain.
Differential accumulation mode is one of the classic mode in the petroleum geology which suggests a series of conditions including a single source rock or a sustained hydrocarbon-generation evolution, a continuous hydrocarbon expulsion process, a buoyancy-based secondary migration process, a carrier system mainly based on permeable and connected sand bodies, and a unified fluid dynamic systems; current reservoir-forming theory in the continental rift basin mainly focus on continuous hydrocarbon-generation, evolutionary process, episodic charging process, carrier system time and space finiteness, abnormal fluid compartment and isolated-fluid system. This paper argues that hydrocarbon migration and accumulation suitable for differential accumulation mode can only be a special simple state. Oil and gas filling is likely to occur within a certain range of basin carrier system. The difference exists in the number of fillings. It will be discussed in practice about whether the influence of basin-scale series traps accumulation mode is a complex superimposition of a number of differential accumulation process or a simple superimposition of several periods of differential accumulation,and the influences on reservoir type and space distribution mode of different fluid are also uncertain.
2014, 21(6):6-9.
Abstract:
There are advantageous conditions for shale oil and gas accumulation in Jiyang depression, but it should be studied in depth because of its poor exploration effect. On the basis of shale oil classification, differences between shale oils were analyzed. According to shale oil storage space and its hosting rock type, 2 shale oil types were divided: mudstone-shale type, interlayer type. Mudstoneshale type includes matrix type and fractured type. Interlayer type includes sandstone interlayer type and carbonate rock interlayer type. Shale oils are defined as fractured type when fracture development coefficient is more than 0.2. Shale oils are defined as matrix type when fracture development coefficient is less than 0.2. Differences exist in many aspects including shale oil distribution, fluid types, physical properties, storage spaces, occurrence states and deliverability of different type shale oils. Fractured type shale oils and interlayer type shale oils occur in larger storage space with better physical properties and free occurrence state. Therefore, the deliverability of fracture type and interlayer type shale oils are higher than that of the matrix type shale oils. The storage spaces for interlayer type shale oils with high gas-oil ratio are less than those for fractured type shale oils. Therefore, the deliverability of interlayer type shale oils is lower than that of fracture type shale oils.
There are advantageous conditions for shale oil and gas accumulation in Jiyang depression, but it should be studied in depth because of its poor exploration effect. On the basis of shale oil classification, differences between shale oils were analyzed. According to shale oil storage space and its hosting rock type, 2 shale oil types were divided: mudstone-shale type, interlayer type. Mudstoneshale type includes matrix type and fractured type. Interlayer type includes sandstone interlayer type and carbonate rock interlayer type. Shale oils are defined as fractured type when fracture development coefficient is more than 0.2. Shale oils are defined as matrix type when fracture development coefficient is less than 0.2. Differences exist in many aspects including shale oil distribution, fluid types, physical properties, storage spaces, occurrence states and deliverability of different type shale oils. Fractured type shale oils and interlayer type shale oils occur in larger storage space with better physical properties and free occurrence state. Therefore, the deliverability of fracture type and interlayer type shale oils are higher than that of the matrix type shale oils. The storage spaces for interlayer type shale oils with high gas-oil ratio are less than those for fractured type shale oils. Therefore, the deliverability of interlayer type shale oils is lower than that of fracture type shale oils.
2014, 21(6):10-14.
Abstract:
The sequence of non-coastal fluvial facies stratum which developed in continental basin of China is not controlled by the sea level eustacy. Therefore the cosatal fluvial facies sequence stratigraphic model is no longer applicable. This calls for a new fluvial facies sequence model which is not affected by sea level eustacy. This paper, with references to the domestic and foreign research results of fluvial facies sequence stratigraphy, combining with spatial combination styles of fluvial sedimentary system and the controlling factors of river types, following the principles of sequence stratigraphy and sedimentology，summarized the major controlling factors of non-coastal fluvial sequence. Considering the study of the sedimentary patterns of the Neogene in Jiyang depression, the non-coastal fluvial facies sequence stratigraphic model was discussed and established and its potential resources distribution was pointed out. The development of non-coastal fluvial sequence is mainly controlled by tectonic subsidence, sediment supply, topographic slope and climate. Non-coastal fluvial facies sequence may exist initial system tract，growth system tract and decline system tract. When differential uplift of the basin basement occurs，uplifting system tract may also occur.
The sequence of non-coastal fluvial facies stratum which developed in continental basin of China is not controlled by the sea level eustacy. Therefore the cosatal fluvial facies sequence stratigraphic model is no longer applicable. This calls for a new fluvial facies sequence model which is not affected by sea level eustacy. This paper, with references to the domestic and foreign research results of fluvial facies sequence stratigraphy, combining with spatial combination styles of fluvial sedimentary system and the controlling factors of river types, following the principles of sequence stratigraphy and sedimentology，summarized the major controlling factors of non-coastal fluvial sequence. Considering the study of the sedimentary patterns of the Neogene in Jiyang depression, the non-coastal fluvial facies sequence stratigraphic model was discussed and established and its potential resources distribution was pointed out. The development of non-coastal fluvial sequence is mainly controlled by tectonic subsidence, sediment supply, topographic slope and climate. Non-coastal fluvial facies sequence may exist initial system tract，growth system tract and decline system tract. When differential uplift of the basin basement occurs，uplifting system tract may also occur.
2014, 21(6):15-21.
Abstract:
Chuxiong basin locates at the southwestern margin of Yangtze Plate and Central Yunnan Secondary Block of the South Sichuan-Yunnan rhombic block. It is bounded by the Red River Fault in the southwest corner and Xiaojiang Fault in the east border. Since Mesozoic, the basin suffered from a pair of extrusion force with northward direction from the Tethys tectonic domain and westward direc? tion from Marginal Pacific tectonic domain. Each force dominated alternately in different tectonic stages and results in left or right-lateral strike-slips of the Red River Fault which controlled the tectonic and depositional evolution of the Basin. The wrench tectonics was identified according to the planar and sectional characteristics with the results of seismic interpretation in Chuxiong basin. On that basis, the dynamic deformation mechanism of the wrench tectonics in each tectonic stage was analyzed combining Paleomagnetic data and stress field of each stage as well as depositional evolution of the basin. It is concluded that:①The Chuxiong basin was not a foreland basin which located on the east side of Jinshajiang collision belt after the conjunction of Indochina block into Yangtze Plate. The Red Riv?er Fault was mainly in strike-slip motion because of the small angle between the strike of the fault and the movement direction of Indochina block, and didn’t give rise to large scale mountain orogenesis. Thereafter, the Chuxiong basin was evolved into a rifted basin in the SN directional extrusion force of the late Indosinian period.②The abrupt change of sedimentary thickness in the region of Chuxiong-Mouding was influenced by the pull-apart effects during the striking-slip movement of Chuxiong-Jianshui Fault and Mouding Fault. ③The distribution of igneous rock in the basin is closely related to the shear movement of the large-scale basement faults in the later stage, which makes it easy to be outlined and to be avoided in the hydrocarbon exploration.
Chuxiong basin locates at the southwestern margin of Yangtze Plate and Central Yunnan Secondary Block of the South Sichuan-Yunnan rhombic block. It is bounded by the Red River Fault in the southwest corner and Xiaojiang Fault in the east border. Since Mesozoic, the basin suffered from a pair of extrusion force with northward direction from the Tethys tectonic domain and westward direc? tion from Marginal Pacific tectonic domain. Each force dominated alternately in different tectonic stages and results in left or right-lateral strike-slips of the Red River Fault which controlled the tectonic and depositional evolution of the Basin. The wrench tectonics was identified according to the planar and sectional characteristics with the results of seismic interpretation in Chuxiong basin. On that basis, the dynamic deformation mechanism of the wrench tectonics in each tectonic stage was analyzed combining Paleomagnetic data and stress field of each stage as well as depositional evolution of the basin. It is concluded that:①The Chuxiong basin was not a foreland basin which located on the east side of Jinshajiang collision belt after the conjunction of Indochina block into Yangtze Plate. The Red Riv?er Fault was mainly in strike-slip motion because of the small angle between the strike of the fault and the movement direction of Indochina block, and didn’t give rise to large scale mountain orogenesis. Thereafter, the Chuxiong basin was evolved into a rifted basin in the SN directional extrusion force of the late Indosinian period.②The abrupt change of sedimentary thickness in the region of Chuxiong-Mouding was influenced by the pull-apart effects during the striking-slip movement of Chuxiong-Jianshui Fault and Mouding Fault. ③The distribution of igneous rock in the basin is closely related to the shear movement of the large-scale basement faults in the later stage, which makes it easy to be outlined and to be avoided in the hydrocarbon exploration.
5 Preservation conditions research on shale gas in the lower Paleozoic of western Hunan and Hubei area
2014, 21(6):22-25.
Abstract:
Organic-rich shale in western Hunan and Hubei area is characterized by wide distribution, great sedimentary thickness,good hydrocarbon source and high thermal evolution, which has the material basis for shale gas formation. However, preservation conditions are the keys to the accumulation of shale gas. Uplift-erosion intensity, combination of fault and fracture, characteristic of caprock development and fluid sealing property of the shales in the lower Combrian and upper Ordovician-lower Silurian of the lower Paleozoic have been analyzed. The results show that the synclinorium area, where is weakly affected by tectonic activity, has deep buried depth for shale, continuous distribution for cover layer, undeveloped fault-fracture and great sealing property; whereas the anticlinorium area is strongly affected by tectonic activity, and the shale is shallow buried or even exposed to the surface having incomplete cover layer or without it, combining with well developed faults and poor sealing property. Preservation conditions of shale gas were preferable in south of Lichuan synclinorium, north-central segment of Huaguoping synclinorium and middle part of Sangzhi-Shimen synclinorium, where could be considered as favorable target areas for further exploration.
Organic-rich shale in western Hunan and Hubei area is characterized by wide distribution, great sedimentary thickness,good hydrocarbon source and high thermal evolution, which has the material basis for shale gas formation. However, preservation conditions are the keys to the accumulation of shale gas. Uplift-erosion intensity, combination of fault and fracture, characteristic of caprock development and fluid sealing property of the shales in the lower Combrian and upper Ordovician-lower Silurian of the lower Paleozoic have been analyzed. The results show that the synclinorium area, where is weakly affected by tectonic activity, has deep buried depth for shale, continuous distribution for cover layer, undeveloped fault-fracture and great sealing property; whereas the anticlinorium area is strongly affected by tectonic activity, and the shale is shallow buried or even exposed to the surface having incomplete cover layer or without it, combining with well developed faults and poor sealing property. Preservation conditions of shale gas were preferable in south of Lichuan synclinorium, north-central segment of Huaguoping synclinorium and middle part of Sangzhi-Shimen synclinorium, where could be considered as favorable target areas for further exploration.
6 Buried strike-slip fault feature and effect on hydrocarbon reservoir forming in Penglai 13-14 area
2014, 21(6):26-29.
Abstract:
Bodong sag and North Miaoxi sag near the Bonan heave develop buried strike-slip structure. Profiles of two sides of the strike-slip fault are characterized by seismic facies changes and tectonic inversion. The planar distribution is characterized by a combination of en-echelon faults,“broom-like structure”and so on. Different from the typical strike-slip fault in heave zone, the main buried strike-slip fault identification needs to integrate a variety of geological evidences. Three main strike-slip faults develop in the region of interest: one is in the south-central area, and the other two is in the west area, forming the east branch of Tan-Lu fault together.The main strike-slip faults develop only in the Pre-Tertiary and the bottom of the Paleocene, formed under the strength of twist and compress. The main strike-slip fault does not develop in the Neocene, and two different mechanical property fault groups develop: one group is synthetic strike-slip faults nearly north-east, with extensional-twisting character; another group is the associated normal fault nearly east-west direction, with the nature of extension and stretch. Tectonic reversion controlled by strike-slip is the decisive factor of the zonal distribution of trap cluster. Extensional normal fault can be divided into two phases having favorable effect on the hydrocarbon migration. Faults which have experienced early activities and extend from the deep to the shallow layers play a decisive role on hydrocarbon migration. Search for relatively active oil and gas migration objective is the key to success in this area.
Bodong sag and North Miaoxi sag near the Bonan heave develop buried strike-slip structure. Profiles of two sides of the strike-slip fault are characterized by seismic facies changes and tectonic inversion. The planar distribution is characterized by a combination of en-echelon faults,“broom-like structure”and so on. Different from the typical strike-slip fault in heave zone, the main buried strike-slip fault identification needs to integrate a variety of geological evidences. Three main strike-slip faults develop in the region of interest: one is in the south-central area, and the other two is in the west area, forming the east branch of Tan-Lu fault together.The main strike-slip faults develop only in the Pre-Tertiary and the bottom of the Paleocene, formed under the strength of twist and compress. The main strike-slip fault does not develop in the Neocene, and two different mechanical property fault groups develop: one group is synthetic strike-slip faults nearly north-east, with extensional-twisting character; another group is the associated normal fault nearly east-west direction, with the nature of extension and stretch. Tectonic reversion controlled by strike-slip is the decisive factor of the zonal distribution of trap cluster. Extensional normal fault can be divided into two phases having favorable effect on the hydrocarbon migration. Faults which have experienced early activities and extend from the deep to the shallow layers play a decisive role on hydrocarbon migration. Search for relatively active oil and gas migration objective is the key to success in this area.
2014, 21(6):30-32.
Abstract:
The fractured vuggy unit of S80 is an important fractured zone in the Tahe oilfield, which stretch across the sixth and the seventh area. Methods based on petroleum geology, sedimentology and structural geology were used to study the S80 fractured structure model in detail. Sinkholes, river cave, tributaries cave and peripheral hole were found out. The sinkholes, river Cave, cave branch flow and peripheral holes mainly develop in the epikarst zone. And the sinkholes distribute along the structural low and the slope presenting a string of beads. A few peripheral holes were found out in seepage karst cave zones. River cave is the main part of runoff karst belt which grows parallel or nearly parallel to the direction of formation and superposed in the longitudinal direction. The deep seam and vuggy zone is characteristic of slit strip liking underground rivers, having close relationship with fault. High angle fractures, joints and pressure solution seam mesh were found in S80 unit which are controlled by the tectonization and influence the cracks and caves development in the epikarst. Therefore, limestone caves mainly grow in the surface layer of the karst belt with horizontal distribution. The deep seam cave zone has close relationship with the deeper fracture and exhibits underground river characteristics. In the Akekule and its adjacent areas, there are four important tectonic deformations which lead to the formation fracture development in S80 unit. During middle Caledonian, early and late Hercynian, the folding and faulting controls the crack growth and its direction in this area. Accordingly, the fractured-vuggy model of S80 wells in the fractured karst area was summed up into four stages: sedimentary and diagenesis, tectonic compression, uplift and dissolution, erosion expansion and back filling period, and the controlling factor of different periods on cave formation were proposed.
The fractured vuggy unit of S80 is an important fractured zone in the Tahe oilfield, which stretch across the sixth and the seventh area. Methods based on petroleum geology, sedimentology and structural geology were used to study the S80 fractured structure model in detail. Sinkholes, river cave, tributaries cave and peripheral hole were found out. The sinkholes, river Cave, cave branch flow and peripheral holes mainly develop in the epikarst zone. And the sinkholes distribute along the structural low and the slope presenting a string of beads. A few peripheral holes were found out in seepage karst cave zones. River cave is the main part of runoff karst belt which grows parallel or nearly parallel to the direction of formation and superposed in the longitudinal direction. The deep seam and vuggy zone is characteristic of slit strip liking underground rivers, having close relationship with fault. High angle fractures, joints and pressure solution seam mesh were found in S80 unit which are controlled by the tectonization and influence the cracks and caves development in the epikarst. Therefore, limestone caves mainly grow in the surface layer of the karst belt with horizontal distribution. The deep seam cave zone has close relationship with the deeper fracture and exhibits underground river characteristics. In the Akekule and its adjacent areas, there are four important tectonic deformations which lead to the formation fracture development in S80 unit. During middle Caledonian, early and late Hercynian, the folding and faulting controls the crack growth and its direction in this area. Accordingly, the fractured-vuggy model of S80 wells in the fractured karst area was summed up into four stages: sedimentary and diagenesis, tectonic compression, uplift and dissolution, erosion expansion and back filling period, and the controlling factor of different periods on cave formation were proposed.
2014, 21(6):33-36.
Abstract:
In order to analyze the characteristic of current in-situ stress field of the Fengshan formation, using the strike of drilling inducing fracture and direction of hole-wall collapsing, the direction of current in-situ stress of the Fengshan formation was judged, and the value of current stress is calculated by logging data and empirical formula. Based on above, taking ground stress results of key wells as constraint condition, horizontal distribution of current in-situ stress field was analyzed by numerical simulation with confirming rock mechanical parameters and building finite element model. Meanwhile, the impact on fracture efficacy of current in-situ stress field was analyzed. The result demonstrates that, the maximal horizontal principal stress is 90.6-181 MPa, and the direction is close to NEESWW;the minimal horizontal principal stress is 61.9-110 MPa, and the direction is close to NNW-SSE. Low value of current stress appears in faults. The value of current stress in arch core distributes stably. There are two stress gradient zones in anticlinal flanks. High value of current stress appears in the low-lying areas near the east and west sides. According to the simulation results, the impact of stress on the fracture efficacy was analyzed. Effective fracture strike of the Fengshan formation is close to NEE-SWW. The arch core is the best area for effective fracture development, followed by the anticlinal flanks and the low-lying areas.
In order to analyze the characteristic of current in-situ stress field of the Fengshan formation, using the strike of drilling inducing fracture and direction of hole-wall collapsing, the direction of current in-situ stress of the Fengshan formation was judged, and the value of current stress is calculated by logging data and empirical formula. Based on above, taking ground stress results of key wells as constraint condition, horizontal distribution of current in-situ stress field was analyzed by numerical simulation with confirming rock mechanical parameters and building finite element model. Meanwhile, the impact on fracture efficacy of current in-situ stress field was analyzed. The result demonstrates that, the maximal horizontal principal stress is 90.6-181 MPa, and the direction is close to NEESWW;the minimal horizontal principal stress is 61.9-110 MPa, and the direction is close to NNW-SSE. Low value of current stress appears in faults. The value of current stress in arch core distributes stably. There are two stress gradient zones in anticlinal flanks. High value of current stress appears in the low-lying areas near the east and west sides. According to the simulation results, the impact of stress on the fracture efficacy was analyzed. Effective fracture strike of the Fengshan formation is close to NEE-SWW. The arch core is the best area for effective fracture development, followed by the anticlinal flanks and the low-lying areas.
2014, 21(6):37-40.
Abstract:
Multiphase unconformities were found in the Bamianhe area of Dongying sag. The unconformity in the bottom of the Kongdian formation is very important for petroleum accumulation in this area. Seismic section was comprehensively interpreted to discover three unconformity types including truncation-overlap unconformity, parallel-overlap unconformity and truncation-parallel unconformity. According to the log data analysis, the unconformities were divided into three parts vertically: rocks deposited above the unconformity interfaces, weathered clay layer and semi-weathered rocks below the unconformity interfaces. Under the weathering and leaching action，the permeability of semi-weathered rocks is improved. Based on the combination of different unconformity types and lithologic configurations, 12 lithological combination types were proposed, which play different roles in the oil and gas migration and accumulation. The exploration has proved that numerous oil and gas shows and petroleum accumulations exist within 40 m range both above and below the unconformity interfaces. The stratigraphic overlap reservoirs can form above the unconformity interfaces in the area where the truncation-overlap and the parallel-overlap unconformities develop combined with sand-mud lithologic configuration; the buried hill reservoirs can form below the unconformity interfaces in the area where the truncation-overlap and the truncation-parallel unconformities develop with mud-sand lithologic configuration.
Multiphase unconformities were found in the Bamianhe area of Dongying sag. The unconformity in the bottom of the Kongdian formation is very important for petroleum accumulation in this area. Seismic section was comprehensively interpreted to discover three unconformity types including truncation-overlap unconformity, parallel-overlap unconformity and truncation-parallel unconformity. According to the log data analysis, the unconformities were divided into three parts vertically: rocks deposited above the unconformity interfaces, weathered clay layer and semi-weathered rocks below the unconformity interfaces. Under the weathering and leaching action，the permeability of semi-weathered rocks is improved. Based on the combination of different unconformity types and lithologic configurations, 12 lithological combination types were proposed, which play different roles in the oil and gas migration and accumulation. The exploration has proved that numerous oil and gas shows and petroleum accumulations exist within 40 m range both above and below the unconformity interfaces. The stratigraphic overlap reservoirs can form above the unconformity interfaces in the area where the truncation-overlap and the parallel-overlap unconformities develop combined with sand-mud lithologic configuration; the buried hill reservoirs can form below the unconformity interfaces in the area where the truncation-overlap and the truncation-parallel unconformities develop with mud-sand lithologic configuration.
2014, 21(6):41-44.
Abstract:
Huzhuangji area in the west slope of Dongpu depression is complex in structure with frequent alternation of sandstone and mudstone. Sandstones and faults are configured to form a complex oil and gas carrier system, which has great influence on oil and gas migration and accumulation in this area. This paper focuses on the relationship between the carrier systems and the hydrocarbon distribution in Hu5 block area of Huzhuangji oilfield. The analysis results show that: oil and gas generated from the source rock in the east sag of Huzhuangji oilfield migrated nearly east-west to the slope and accumulated; the thickness of sand body and the fault distance control the lithology contraposition of the two sides of the fault, thereby affecting lateral fault sealing. Two types of carrier system that consist of different sand body and fault combinations were analyzed and their control on the hydrocarbon migration and accumulation in this area. For faults parallel to the strike of the main fault, they are favorable for oil and gas migration if their fault distance is small combining with thick sandstones; and they are favorable for oil and gas accumulation if their fault distance is large enough to disconnect the thick sand bodies; and for faults oblique crossing the main fault, it is favorable for oil and gas migration where the fault distance is small and sand body is thick; and tis favorable for hydrocarbon accumulation where the fault distance is large and sand body is thin.
Huzhuangji area in the west slope of Dongpu depression is complex in structure with frequent alternation of sandstone and mudstone. Sandstones and faults are configured to form a complex oil and gas carrier system, which has great influence on oil and gas migration and accumulation in this area. This paper focuses on the relationship between the carrier systems and the hydrocarbon distribution in Hu5 block area of Huzhuangji oilfield. The analysis results show that: oil and gas generated from the source rock in the east sag of Huzhuangji oilfield migrated nearly east-west to the slope and accumulated; the thickness of sand body and the fault distance control the lithology contraposition of the two sides of the fault, thereby affecting lateral fault sealing. Two types of carrier system that consist of different sand body and fault combinations were analyzed and their control on the hydrocarbon migration and accumulation in this area. For faults parallel to the strike of the main fault, they are favorable for oil and gas migration if their fault distance is small combining with thick sandstones; and they are favorable for oil and gas accumulation if their fault distance is large enough to disconnect the thick sand bodies; and for faults oblique crossing the main fault, it is favorable for oil and gas migration where the fault distance is small and sand body is thick; and tis favorable for hydrocarbon accumulation where the fault distance is large and sand body is thin.
2014, 21(6):45-48.
Abstract:
Aiming to solve problems about complex faulted structure and rule of oil-gas migration and accumulation, we have studied the fault connecting properties in Qingcheng arch and the Mesozoic key faults’ability to plug or transport hydrocarbon. Based on the study, the numerical simulation has been carried out on oil migration and accumulation, finding that Mesozoic dominant migrating pathways are westward and west-southward along the Gaoqing fault. The direction of oil-gas migration is mainly controlled by structure modality and reservoir sandstones. Oil and gas migrate to the back of structure nose along the fault and sandstones and the migration distance is controlled by the structure nose with a northeast strike. However, it is difficult for oil and gas to keep on migrating to the west because the western side of strata is inclining to the west. So, oil and gas can migrate easily on the west of the nose structure along the Gao15 well-Gao52 well-Gao46 well in Mesozoic, which means this area is an effective petroliferous area. Thus we can know the direction of oil and gas migration and the development area of trap as well as the characteristics of Mesozoic reservoirs.
Aiming to solve problems about complex faulted structure and rule of oil-gas migration and accumulation, we have studied the fault connecting properties in Qingcheng arch and the Mesozoic key faults’ability to plug or transport hydrocarbon. Based on the study, the numerical simulation has been carried out on oil migration and accumulation, finding that Mesozoic dominant migrating pathways are westward and west-southward along the Gaoqing fault. The direction of oil-gas migration is mainly controlled by structure modality and reservoir sandstones. Oil and gas migrate to the back of structure nose along the fault and sandstones and the migration distance is controlled by the structure nose with a northeast strike. However, it is difficult for oil and gas to keep on migrating to the west because the western side of strata is inclining to the west. So, oil and gas can migrate easily on the west of the nose structure along the Gao15 well-Gao52 well-Gao46 well in Mesozoic, which means this area is an effective petroliferous area. Thus we can know the direction of oil and gas migration and the development area of trap as well as the characteristics of Mesozoic reservoirs.
2014, 21(6):49-52.
Abstract:
Tazhong is an important carbonate exploration area with abundant hydrocarbon in the Ordovician, but the oil/gas/water distribution is complex and heterogeneous. By statistics and analysis on massive well drilling data and performance curve of producing test water ratio, the idea is revealed that watering style in Yazhong can be classified into four categories as follows: drilling watering, producing test rapid watering, producing test steps watering and producing test intermission watering, and drilling watering>producing test rapid watering>producing test steps watering>producing test intermission watering in watering intensity. Combining the terrain, reservoir and faults, and analyzing the relationship between them and the water distribution, the main factors controlling watering styles were revealed. The water distribution is controlled by the terrain generally; watering style is obviously controlled by reservoir space styles;faults usually act as channels for the water underneath to higher level, and can also reform the reservoir space styles. Different watering styles have one or more ruling factors, based on which, geological models were established for different watering styles.
Tazhong is an important carbonate exploration area with abundant hydrocarbon in the Ordovician, but the oil/gas/water distribution is complex and heterogeneous. By statistics and analysis on massive well drilling data and performance curve of producing test water ratio, the idea is revealed that watering style in Yazhong can be classified into four categories as follows: drilling watering, producing test rapid watering, producing test steps watering and producing test intermission watering, and drilling watering>producing test rapid watering>producing test steps watering>producing test intermission watering in watering intensity. Combining the terrain, reservoir and faults, and analyzing the relationship between them and the water distribution, the main factors controlling watering styles were revealed. The water distribution is controlled by the terrain generally; watering style is obviously controlled by reservoir space styles;faults usually act as channels for the water underneath to higher level, and can also reform the reservoir space styles. Different watering styles have one or more ruling factors, based on which, geological models were established for different watering styles.
2014, 21(6):53-56.
Abstract:
Yingmai32 well area in the western part of North Tarim uplift has experienced tectonic movements for many times, which led to serious formation denudation and faults development. Directed by“Three Classifications, Three Subjects”, the article deeply analyzed the tectonic evolution and styles of Cambrian-Ordovician faults combining with the main tectonic movements of Tarim basin and North Tarim uplift and the actual geologic conditions. We have found that there are three periods of the Cambrian-Ordovician fault: the late Caledonian fault, the Early Hercynian faults and late Hercynian faults. Meanwhile, the two periods of Hercynian faults kept active until Cretaceous. Cambrianrdovician faults in the work area are mainly strike-slip faults and thrust faults, which promoted the interphase development of swell and concave within the buried hill and form many fault styles including flower-like fault, back thrust fault,imbricate thrust fault and so on. By summarizing the features of the faults and the distribution of oil and gas, we concluded that the high positions of positive flower-like faults are the best places for oil accumulation.
Yingmai32 well area in the western part of North Tarim uplift has experienced tectonic movements for many times, which led to serious formation denudation and faults development. Directed by“Three Classifications, Three Subjects”, the article deeply analyzed the tectonic evolution and styles of Cambrian-Ordovician faults combining with the main tectonic movements of Tarim basin and North Tarim uplift and the actual geologic conditions. We have found that there are three periods of the Cambrian-Ordovician fault: the late Caledonian fault, the Early Hercynian faults and late Hercynian faults. Meanwhile, the two periods of Hercynian faults kept active until Cretaceous. Cambrianrdovician faults in the work area are mainly strike-slip faults and thrust faults, which promoted the interphase development of swell and concave within the buried hill and form many fault styles including flower-like fault, back thrust fault,imbricate thrust fault and so on. By summarizing the features of the faults and the distribution of oil and gas, we concluded that the high positions of positive flower-like faults are the best places for oil accumulation.
2014, 21(6):57-60.
Abstract:
Based on observation of core and analyses of logging data, fracture occurrence, height, position are analyzed in Chang8 section, Heshui area. The fracture planar distribution was summarized. According to the fracture linear density, Heshui area is divided into strong fractured zone, fracture developed zone, weak fractured zone and non-fractured zone. Fracture in Chang8 section is mainly distributed in the siltstone, followed by fine sandstone and mudstone. The better the porosity and permeability of reservoir are, the less the fracture develops. For layers of the same lithology, the greater the thickness of layer is, the less the fracture develops. In the strong fractured zone and the fracture developed zone, the porosity and permeability are poor and the layer thickness is small. So oil production is not high in the two zones, and high yield wells are always in the weak fractured zone. This shows that it is difficult to obtain industrial oil flow even if the reservoir is fractured when its porosity and permeability and oil bearing are poor. Fracture existed in the formation nearby reservoir has little effect on fracturing and the yield of oil-bearing reservoir. Controlling factors of oil production are lithology,thickness, physical properties, oil bearing of reservoir.
Based on observation of core and analyses of logging data, fracture occurrence, height, position are analyzed in Chang8 section, Heshui area. The fracture planar distribution was summarized. According to the fracture linear density, Heshui area is divided into strong fractured zone, fracture developed zone, weak fractured zone and non-fractured zone. Fracture in Chang8 section is mainly distributed in the siltstone, followed by fine sandstone and mudstone. The better the porosity and permeability of reservoir are, the less the fracture develops. For layers of the same lithology, the greater the thickness of layer is, the less the fracture develops. In the strong fractured zone and the fracture developed zone, the porosity and permeability are poor and the layer thickness is small. So oil production is not high in the two zones, and high yield wells are always in the weak fractured zone. This shows that it is difficult to obtain industrial oil flow even if the reservoir is fractured when its porosity and permeability and oil bearing are poor. Fracture existed in the formation nearby reservoir has little effect on fracturing and the yield of oil-bearing reservoir. Controlling factors of oil production are lithology,thickness, physical properties, oil bearing of reservoir.
2014, 21(6):61-64.
Abstract:
Through mathematical operation, elastic parameters such as velocity, density and Poisson ratio can be acquired from prestack seismic inversion. Based on the elastic parameters, medium characteristics that are concerned in the process of oil and gas exploration and development such as lithology, physical property and fluid can be identified, thus reservoir description accuracy can be greatly improved and ambiguity can be reduced. However, pre-stack seismic inversion technology has certain application conditions,and it has the adaptability to geology, seismic and logging data, and the application effect of the inversion results is affected by many factors. Therefore, based on the analysis of the advantages of pre-stack seismic inversion technology, application conditions of the technology were determined and the problems existing in the application were analyzed through synthetic data and practical seismic and logging data. Results show that pre-stack seismic inversion technology has the advantages of data diversity and the intrinsic advantages of the technology itself, and rich inversion result data can be obtained, but the application of this technology needs high quality seismic data, analysis of rock physical feasibility and reasonable pre-stack seismic inversion process control and achievements application. Currently, the difficult issues in the pre-stack seismic inversion technology are the ambiguity in the inversion results, the matching among a variety of data, the consistency between longitudinal and lateral resolution and the requirements of exploration and development, etc.
Through mathematical operation, elastic parameters such as velocity, density and Poisson ratio can be acquired from prestack seismic inversion. Based on the elastic parameters, medium characteristics that are concerned in the process of oil and gas exploration and development such as lithology, physical property and fluid can be identified, thus reservoir description accuracy can be greatly improved and ambiguity can be reduced. However, pre-stack seismic inversion technology has certain application conditions,and it has the adaptability to geology, seismic and logging data, and the application effect of the inversion results is affected by many factors. Therefore, based on the analysis of the advantages of pre-stack seismic inversion technology, application conditions of the technology were determined and the problems existing in the application were analyzed through synthetic data and practical seismic and logging data. Results show that pre-stack seismic inversion technology has the advantages of data diversity and the intrinsic advantages of the technology itself, and rich inversion result data can be obtained, but the application of this technology needs high quality seismic data, analysis of rock physical feasibility and reasonable pre-stack seismic inversion process control and achievements application. Currently, the difficult issues in the pre-stack seismic inversion technology are the ambiguity in the inversion results, the matching among a variety of data, the consistency between longitudinal and lateral resolution and the requirements of exploration and development, etc.
2014, 21(6):65-67.
Abstract:
Due to the strong heterogeneity of Tahe oilfield fracture-vug carbonate reservoir, there exists some factors greatly influencing the effect of the unit waterflooding development, such as the fuzzy understanding of fracture-cave body distribution between wells and large scale fracture channel connectivity in injection layers. Through a comparative analysis of the characteristics of seismic curva? ture, using the seismic reflection angle, discontinuity and maximum curvature attributes, the seismic facies, images’micro fracture -fracture system were analyzed. The fissure-cave connected spatial form was depicted. The extending direction of the large scale fracture was tracked. When waterflood is performed in the fracture-vug reservoir, the depicted fracture-cave connectivity distribution can guide the deployment of the injection and production wells and optimize their relationship; based on tracking the trend of large-scale crack, the main direction of waterflooding can be predicted. Through the application in the field, the geological basis for fracture-vug reservoir in injection and production wells can be provided and their deployment can be optimized. The establishment of the network of injection and production wells and prediction of effective direction of water injection can be realized.
Due to the strong heterogeneity of Tahe oilfield fracture-vug carbonate reservoir, there exists some factors greatly influencing the effect of the unit waterflooding development, such as the fuzzy understanding of fracture-cave body distribution between wells and large scale fracture channel connectivity in injection layers. Through a comparative analysis of the characteristics of seismic curva? ture, using the seismic reflection angle, discontinuity and maximum curvature attributes, the seismic facies, images’micro fracture -fracture system were analyzed. The fissure-cave connected spatial form was depicted. The extending direction of the large scale fracture was tracked. When waterflood is performed in the fracture-vug reservoir, the depicted fracture-cave connectivity distribution can guide the deployment of the injection and production wells and optimize their relationship; based on tracking the trend of large-scale crack, the main direction of waterflooding can be predicted. Through the application in the field, the geological basis for fracture-vug reservoir in injection and production wells can be provided and their deployment can be optimized. The establishment of the network of injection and production wells and prediction of effective direction of water injection can be realized.
2014, 21(6):68-71.
Abstract:
Fractured reservoir exploration has great potential, and its development is affected by many factors, so it is necessary to describe it by combining geology, well logging, geophysical data and other information. Through meticulous analysis on the geological data of the lower Shasan member reservoir in Bonan sag and multi-scale fracture prediction, we selected two kinds of technologies: one is using tomographic image enhancement technology to predict fracture zone and another is using multi-attribute trend fitting technique to predict the planar distribution of the first class reservoir. However, there is a big uncertainty of the prediction result whenusing only a single technology, so it is necessary to combine these two kinds of prediction techniques and use overlay display technology to predict the advantaged fracture reservoir zone in the study area, which can improve the prediction accuracy of fractured reservoirs. We combined the structural dip attribute of the lower Shasan member reservoir with the predicted thickness of the first class reservoir. The results show that the fault zone Yi182 and the southern Luo42 well around are favorable target zones, where the field drilling high-producing wells such as Yi182, Yi186 and Yi187 well etc. show good indication of oil and gas. Well Boye-Ping1 is located near the favorable fractured reservoir zones which are predicted by combining display technologies, and it shows that the application of combining display technologies can improve reservoir prediction accuracy, which is an effective method of comprehensive evaluation of fractured reservoirs.
Fractured reservoir exploration has great potential, and its development is affected by many factors, so it is necessary to describe it by combining geology, well logging, geophysical data and other information. Through meticulous analysis on the geological data of the lower Shasan member reservoir in Bonan sag and multi-scale fracture prediction, we selected two kinds of technologies: one is using tomographic image enhancement technology to predict fracture zone and another is using multi-attribute trend fitting technique to predict the planar distribution of the first class reservoir. However, there is a big uncertainty of the prediction result whenusing only a single technology, so it is necessary to combine these two kinds of prediction techniques and use overlay display technology to predict the advantaged fracture reservoir zone in the study area, which can improve the prediction accuracy of fractured reservoirs. We combined the structural dip attribute of the lower Shasan member reservoir with the predicted thickness of the first class reservoir. The results show that the fault zone Yi182 and the southern Luo42 well around are favorable target zones, where the field drilling high-producing wells such as Yi182, Yi186 and Yi187 well etc. show good indication of oil and gas. Well Boye-Ping1 is located near the favorable fractured reservoir zones which are predicted by combining display technologies, and it shows that the application of combining display technologies can improve reservoir prediction accuracy, which is an effective method of comprehensive evaluation of fractured reservoirs.
2014, 21(6):72-75.
Abstract:
Using ultra-low permeability cores, the influences of surfactants with different interfacial tension on single phase and two phase starting pressure gradient of oil/water as well as relative permeability curves were studied. The effects of the surfactants on reducing injection pressure and enhancing oil recovery were also studied. The basic mechanisms of surfactant flooding to enhance oil recovery of low permeability reservoirs were obtained. The results show that the single phase starting pressure gradient of oil or water significantly decreases while the interfacial tension of the surfactant solution used as a displacing fluid. At the same ratio of displacing velocity, starting pressure gradient of oil and water two-phase gradually decreased, and water saturation gradually increased, as the interfacial tension decreased. The relative permeability curves of core had following characteristics: while oil/water interfacial tension decreased, the two-phase region became wider and the residual oil saturation decreased, and water relative permeability at residual oil saturation increased, and ultimate oil recovery increased. The results of the core displacement experiments show that injecting surfactant slug after the first water flooding can decrease the injection pressure significantly and enhance oil recovery to some extent. And,the lower the oil-water interfacial tension, the better the effect of enhancing oil recovery. And, the lower the oil-water interfacial tension, the better the effect of reducing injection pressure.
Using ultra-low permeability cores, the influences of surfactants with different interfacial tension on single phase and two phase starting pressure gradient of oil/water as well as relative permeability curves were studied. The effects of the surfactants on reducing injection pressure and enhancing oil recovery were also studied. The basic mechanisms of surfactant flooding to enhance oil recovery of low permeability reservoirs were obtained. The results show that the single phase starting pressure gradient of oil or water significantly decreases while the interfacial tension of the surfactant solution used as a displacing fluid. At the same ratio of displacing velocity, starting pressure gradient of oil and water two-phase gradually decreased, and water saturation gradually increased, as the interfacial tension decreased. The relative permeability curves of core had following characteristics: while oil/water interfacial tension decreased, the two-phase region became wider and the residual oil saturation decreased, and water relative permeability at residual oil saturation increased, and ultimate oil recovery increased. The results of the core displacement experiments show that injecting surfactant slug after the first water flooding can decrease the injection pressure significantly and enhance oil recovery to some extent. And,the lower the oil-water interfacial tension, the better the effect of enhancing oil recovery. And, the lower the oil-water interfacial tension, the better the effect of reducing injection pressure.
2014, 21(6):76-78.
Abstract:
The pay thickness is small and the production effect of steam stimulation is poor for Chen373 block in Shengli oilfield. Effect of CO2 and chemical agent on crude oil is analyzed by experimentation. At the same time, the production of compound stimulation of CO2-Chemical after steam stimulation was studied by reservoir simulation soft CMG. The result indicated that CO2 and chemical had good effect on the heavy oil. The viscosity reduction rate is 98.97% by CO2 and chemical synergy under the reservoir condition. The viscosity is 18.4% of that in the role of chemical agent. Compound stimulation of CO2-Chemical can complement formation energy and increase scope of crude oil viscosity reduction and production effect. CO2-chemical compound stimulation after six cycles steam stimulation contributes more production. Average cycle oil production of CO2-chemical compound stimulation is 480.5 t, which is 252.4 t more than steam stimulation. The return on invested is 1.64. The research provides evidence for producing transformation after steam stimulation for Chen373.
The pay thickness is small and the production effect of steam stimulation is poor for Chen373 block in Shengli oilfield. Effect of CO2 and chemical agent on crude oil is analyzed by experimentation. At the same time, the production of compound stimulation of CO2-Chemical after steam stimulation was studied by reservoir simulation soft CMG. The result indicated that CO2 and chemical had good effect on the heavy oil. The viscosity reduction rate is 98.97% by CO2 and chemical synergy under the reservoir condition. The viscosity is 18.4% of that in the role of chemical agent. Compound stimulation of CO2-Chemical can complement formation energy and increase scope of crude oil viscosity reduction and production effect. CO2-chemical compound stimulation after six cycles steam stimulation contributes more production. Average cycle oil production of CO2-chemical compound stimulation is 480.5 t, which is 252.4 t more than steam stimulation. The return on invested is 1.64. The research provides evidence for producing transformation after steam stimulation for Chen373.
2014, 21(6):79-83.
Abstract:
In order to further improve the utilization of the core experimental parameters, to enrich oil recovery prediction methods and to further improve the prediction precision, a one-dimensional mathematical model of water flooding was established by utilizing the advantage of various types of core experimental methods, numerical simulation and reservoir engineering approach. The model is based on the one-dimensional reservoir physics experiment parameters, considering effect of the threshold pressure during water flooding.Moreover, using liquid production rate as weight coefficient, the one-dimensional mathematical model is transformed into a two-dimensional cross-sectional model; on this basis, using water flooding sweep coefficient under different well patterns, the two-dimensional cross-sectional model can be transformed into a three-dimensional model to predict oil recovery. The results in Mo005 well block showed that: the predicted recovery using this method is 25.6%, consistent with 25% of the actual standardized recovery. The method can fully use various types of core results, consider interlayer heterogeneity and well pattern, avoiding the singularity and uncertainties by using simple experimental methods or reservoir engineering methods to predict oil recovery. The method can further enrich oil recovery prediction methods and improve prediction precision, at the same time, it provides a new direction and idea for other researchers.
In order to further improve the utilization of the core experimental parameters, to enrich oil recovery prediction methods and to further improve the prediction precision, a one-dimensional mathematical model of water flooding was established by utilizing the advantage of various types of core experimental methods, numerical simulation and reservoir engineering approach. The model is based on the one-dimensional reservoir physics experiment parameters, considering effect of the threshold pressure during water flooding.Moreover, using liquid production rate as weight coefficient, the one-dimensional mathematical model is transformed into a two-dimensional cross-sectional model; on this basis, using water flooding sweep coefficient under different well patterns, the two-dimensional cross-sectional model can be transformed into a three-dimensional model to predict oil recovery. The results in Mo005 well block showed that: the predicted recovery using this method is 25.6%, consistent with 25% of the actual standardized recovery. The method can fully use various types of core results, consider interlayer heterogeneity and well pattern, avoiding the singularity and uncertainties by using simple experimental methods or reservoir engineering methods to predict oil recovery. The method can further enrich oil recovery prediction methods and improve prediction precision, at the same time, it provides a new direction and idea for other researchers.
2014, 21(6):84-86.
Abstract:
This paper does research on the natural capacity of the synthetic rubber-gel system through indoor experiment in contrast to the gel system. It is proved that at the same temperature, mineralize, pH, the natural capacity of the rubber-gel system is better than that of the gel system. In the following plugging experiment, the plugging rate of the rubber-gel system is above 97% which is similar to that of the gel system; however its breakthrough pressure is 4.97 MPa/m which is much higher than that of the gel system, 3.08 MPa/m,and its washing resistance is also better than that of the gel system. When the water flooding is above 7 PV, its pressure maintains stable at 2.35 MPa, However, the pressure of the gel system reduces gradually after the 4 PV water flooding, and the stable pressure is only 1.12 MPa, which is much lower than that of the rubber-gel system; the plugging experiment of the different permeability states that the rubber-gel system has greater performance in high permeability layer.
This paper does research on the natural capacity of the synthetic rubber-gel system through indoor experiment in contrast to the gel system. It is proved that at the same temperature, mineralize, pH, the natural capacity of the rubber-gel system is better than that of the gel system. In the following plugging experiment, the plugging rate of the rubber-gel system is above 97% which is similar to that of the gel system; however its breakthrough pressure is 4.97 MPa/m which is much higher than that of the gel system, 3.08 MPa/m,and its washing resistance is also better than that of the gel system. When the water flooding is above 7 PV, its pressure maintains stable at 2.35 MPa, However, the pressure of the gel system reduces gradually after the 4 PV water flooding, and the stable pressure is only 1.12 MPa, which is much lower than that of the rubber-gel system; the plugging experiment of the different permeability states that the rubber-gel system has greater performance in high permeability layer.
2014, 21(6):87-91.
Abstract:
Although multi-stage fracturing of horizontal wells has been used as the main method to develop shale gas, a long time for fluid recovery and the small amount of fluid recovered with only 10% to 50% of total pumped have led to concerns that phase trapping of fracture fluids may do serious damage to gas reservoir. The experiments of fracturing fluid leakoff and spontaneous imbibitions have been investigated with Longmaxi shale in the eastern Sichuan Basin, and the process of water flowback was surveyed, and then evaluated the impact of rising water saturation on gas-transport and propagation ability of pressure. Experiments results reveal that water saturation in shale is more than 40% after fracturing, but water amount and rising rate are much higher in fractured shale. Much of the load water that is not recovered from pores is effectively blocking gas flow path, and decreased permeability, diffusivity and propagation speed of pressure, and then form water phase trapping. It is concluded that water phase trapping damage is mainly caused by nanopores, abundant hydrophilic clay, and ultra-low water saturation. Furthermore, the load water has led to more gas-transport resistance,and decreased the supply capacity of gas flowing from matrix to fractures. Therefore, it is a promising and significant work to investigate the fluid flow-back mechanism, optimization of surfactant, and the application of non-aqueous fracturing technologies and heat treatment for alleviating or eliminating water phase trapping damage in shale gas reservoirs.
Although multi-stage fracturing of horizontal wells has been used as the main method to develop shale gas, a long time for fluid recovery and the small amount of fluid recovered with only 10% to 50% of total pumped have led to concerns that phase trapping of fracture fluids may do serious damage to gas reservoir. The experiments of fracturing fluid leakoff and spontaneous imbibitions have been investigated with Longmaxi shale in the eastern Sichuan Basin, and the process of water flowback was surveyed, and then evaluated the impact of rising water saturation on gas-transport and propagation ability of pressure. Experiments results reveal that water saturation in shale is more than 40% after fracturing, but water amount and rising rate are much higher in fractured shale. Much of the load water that is not recovered from pores is effectively blocking gas flow path, and decreased permeability, diffusivity and propagation speed of pressure, and then form water phase trapping. It is concluded that water phase trapping damage is mainly caused by nanopores, abundant hydrophilic clay, and ultra-low water saturation. Furthermore, the load water has led to more gas-transport resistance,and decreased the supply capacity of gas flowing from matrix to fractures. Therefore, it is a promising and significant work to investigate the fluid flow-back mechanism, optimization of surfactant, and the application of non-aqueous fracturing technologies and heat treatment for alleviating or eliminating water phase trapping damage in shale gas reservoirs.
2014, 21(6):92-94.
Abstract:
Impurities contained in the injected CO2 will exert influence on minimum miscibility pressure (MMP) as well as the crude oil property. It is meaningful to study the influence of impurities on CO2 flooding. Based on PVT data regression, the impact of CH4 and N2 on MMP was analyzed with numerical simulation method. Besides, the impact of impurities on crude oil properties was also studied. It shows that the presence of N2 and CH4 tends to increase MMP, and the influence of N2 is more notable. When the mole fraction of injected pure CO2 reaches 60%, the oil viscosity reduces by 71.9% and the coefficient of cubic expansion reaches 1.42. But when 30% mole fraction of CH4 is contained in the injected CO2, the oil viscosity reduces by 69.72% and the coefficient of cubic expansion reaches 1.41. However, when 30% mole fraction of N2 is contained in the injected gas, the oil viscosity only reduces by 65.92% and the coefficient of cubic expansion is 1.36. For the target block, the critical molar content of CH4 in the injected CO2 is 5.6%, while the critical molar content of N2 is 2%.
Impurities contained in the injected CO2 will exert influence on minimum miscibility pressure (MMP) as well as the crude oil property. It is meaningful to study the influence of impurities on CO2 flooding. Based on PVT data regression, the impact of CH4 and N2 on MMP was analyzed with numerical simulation method. Besides, the impact of impurities on crude oil properties was also studied. It shows that the presence of N2 and CH4 tends to increase MMP, and the influence of N2 is more notable. When the mole fraction of injected pure CO2 reaches 60%, the oil viscosity reduces by 71.9% and the coefficient of cubic expansion reaches 1.42. But when 30% mole fraction of CH4 is contained in the injected CO2, the oil viscosity reduces by 69.72% and the coefficient of cubic expansion reaches 1.41. However, when 30% mole fraction of N2 is contained in the injected gas, the oil viscosity only reduces by 65.92% and the coefficient of cubic expansion is 1.36. For the target block, the critical molar content of CH4 in the injected CO2 is 5.6%, while the critical molar content of N2 is 2%.
2014, 21(6):95-98.
Abstract:
At present, Chinese onshore fields have generally stepped into high water cut stage. The relationship between oil and water gradually becomes complex and the remaining oil is more dispersed. It’s a pressing problem to accurately reveal the distribution of the remaining oil which can provide decision-making for development adjustment measures. The core model filled with artificial quartz sand was adopted. A series of CT slice images describing microscopic pore structure and fluid distribution of the core model were obtained with the help of the micro-focus CT system. On the basis of scanned slices, three-dimensional visualization of pore structure and fluid distribution was achieved with a series of image processing methods, including pre-processing, interpolation, segmentation and three-dimensional construction. Based on the core three-dimensional pore model, this paper finds that the remaining oil in microscopic pores has different distribution features as“continuous, discrete, continuous-discrete transition”, which determines that its critical description scale from discrete feature converted to continuous feature is 2 to 7.6 times of the pore radius; on the basis of reservoir numerical simulation technology, this paper proposed the critical description scale of the reservoir macroscopic remaining oil. The research indicates that when the grid size is not higher than the critical description scale of the reservoir macroscopic remaining oil, the simulation results can effectively characterize the local enrichment phenomenon of the reservoir macroscopic remaining oil.
At present, Chinese onshore fields have generally stepped into high water cut stage. The relationship between oil and water gradually becomes complex and the remaining oil is more dispersed. It’s a pressing problem to accurately reveal the distribution of the remaining oil which can provide decision-making for development adjustment measures. The core model filled with artificial quartz sand was adopted. A series of CT slice images describing microscopic pore structure and fluid distribution of the core model were obtained with the help of the micro-focus CT system. On the basis of scanned slices, three-dimensional visualization of pore structure and fluid distribution was achieved with a series of image processing methods, including pre-processing, interpolation, segmentation and three-dimensional construction. Based on the core three-dimensional pore model, this paper finds that the remaining oil in microscopic pores has different distribution features as“continuous, discrete, continuous-discrete transition”, which determines that its critical description scale from discrete feature converted to continuous feature is 2 to 7.6 times of the pore radius; on the basis of reservoir numerical simulation technology, this paper proposed the critical description scale of the reservoir macroscopic remaining oil. The research indicates that when the grid size is not higher than the critical description scale of the reservoir macroscopic remaining oil, the simulation results can effectively characterize the local enrichment phenomenon of the reservoir macroscopic remaining oil.
2014, 21(6):99-101.
Abstract:
The paper takes one water plugging agent and two different viscosity of profile control agents as research objects. Through the physical simulation experiment on two layers of heterogeneous core, the influence of the sequences and times of profile control and water plugging for enhancing oil recovery were studied. The research results show that: compared with other sequences, profile control before water plugging has better effect, and recovery efficiency has a significant increase. The ultimate recovery of strong gel was 68.5%,and the weak one was 65%. Research on time shows that the longer the interval between profile control and water plugging, the better the effect of oil displacement, and the best interval is 0.5 PV water driving.
The paper takes one water plugging agent and two different viscosity of profile control agents as research objects. Through the physical simulation experiment on two layers of heterogeneous core, the influence of the sequences and times of profile control and water plugging for enhancing oil recovery were studied. The research results show that: compared with other sequences, profile control before water plugging has better effect, and recovery efficiency has a significant increase. The ultimate recovery of strong gel was 68.5%,and the weak one was 65%. Research on time shows that the longer the interval between profile control and water plugging, the better the effect of oil displacement, and the best interval is 0.5 PV water driving.
2014, 21(6):102-106.
Abstract:
Shale gas reservoirs are characteristic of potential damage of stress sensitivity due to their fractures and rich in clay minerals. The immersion of massive fracturing fluid makes stress sensitivity of shale complex, which strengthens the severity of stress sensitivity and hinders the success of reservoir stimulation. This paper takes shale outcrop samples from the Silurian Longmaxi formation in the Sichuan Basin. The experiments of stress sensitivity were conducted in use of dry fractured plug samples and fractured plug samples immersed by fracturing fluid, some of which are supported by fracturing proppants. Experimental results show that stress sensitivity of samples immersed by fracturing fluid is the highest, and stress sensitivity of fractured samples propped up by proppant is the weakest. It was considered by integrated analysis that the physicochemical interaction between fracturing fluid and shale makes fractures easily compressed and the fracture width decreased to strengthen shale stress sensitivity because of fracturing fluid immersion, and proppant weakens stress sensitivity. By controlling the invasion of fracturing fluid, improving the filtrate return capacity, reducing crack surface erosion optimizing the proppant placement method and designing reasonable production pressure can effectively control shale gas formation damage.
Shale gas reservoirs are characteristic of potential damage of stress sensitivity due to their fractures and rich in clay minerals. The immersion of massive fracturing fluid makes stress sensitivity of shale complex, which strengthens the severity of stress sensitivity and hinders the success of reservoir stimulation. This paper takes shale outcrop samples from the Silurian Longmaxi formation in the Sichuan Basin. The experiments of stress sensitivity were conducted in use of dry fractured plug samples and fractured plug samples immersed by fracturing fluid, some of which are supported by fracturing proppants. Experimental results show that stress sensitivity of samples immersed by fracturing fluid is the highest, and stress sensitivity of fractured samples propped up by proppant is the weakest. It was considered by integrated analysis that the physicochemical interaction between fracturing fluid and shale makes fractures easily compressed and the fracture width decreased to strengthen shale stress sensitivity because of fracturing fluid immersion, and proppant weakens stress sensitivity. By controlling the invasion of fracturing fluid, improving the filtrate return capacity, reducing crack surface erosion optimizing the proppant placement method and designing reasonable production pressure can effectively control shale gas formation damage.
2014, 21(6):107-110.
Abstract:
The segmented multi-cluster fractured horizontal well is one of the effective measures to develop ultra-low permeability reservoir. Based on the typical ultra-low permeability reservoir in Ordos Basin, the HP-34-22 well is selected and its fracture and segmented perforating parameters were optimized. The numerical simulation model of HP-34-22 well was built and its fractures were realized by local grid refinement (LGR).With this model factors influencing productivity effect of segmented multi-cluster fractured horizontal well were analyzed, which contain stress sensitivity, fracture half-length, fracture conductivity, permeability of stimulated region and un-stimulated region and oil production rate. The results of this study show that when the reservoir is developed by natural depletion, the influence of these factors is more significant compared with that of water flooding. Stress sensitivity is detrimental to productivity. Fracture half-length and fracture conductivity is beneficial to productivity, but considering the benefits, costs and the difficulty of measures, they have reasonable value range as well as oil production rate. The productivity improvement by further enhancing the permeability of stimulated region is limited, while it’s remarkable by enhancing the permeability of un-stimulated region. There are five flow stages for segmented multi-cluster fractured horizontal well in bounded reservoir.
The segmented multi-cluster fractured horizontal well is one of the effective measures to develop ultra-low permeability reservoir. Based on the typical ultra-low permeability reservoir in Ordos Basin, the HP-34-22 well is selected and its fracture and segmented perforating parameters were optimized. The numerical simulation model of HP-34-22 well was built and its fractures were realized by local grid refinement (LGR).With this model factors influencing productivity effect of segmented multi-cluster fractured horizontal well were analyzed, which contain stress sensitivity, fracture half-length, fracture conductivity, permeability of stimulated region and un-stimulated region and oil production rate. The results of this study show that when the reservoir is developed by natural depletion, the influence of these factors is more significant compared with that of water flooding. Stress sensitivity is detrimental to productivity. Fracture half-length and fracture conductivity is beneficial to productivity, but considering the benefits, costs and the difficulty of measures, they have reasonable value range as well as oil production rate. The productivity improvement by further enhancing the permeability of stimulated region is limited, while it’s remarkable by enhancing the permeability of un-stimulated region. There are five flow stages for segmented multi-cluster fractured horizontal well in bounded reservoir.
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