Volume 22,Issue 2,2015 Table of Contents
2015, 22(2):1-8.
Abstract:
Continuous hydrocarbon reservoir is an important type of hydrocarbon accumulation. Determining its distribution borders is significant for oil petroleum exploration. Based on analysis of continuous reservoirs found in domestic and overseas，the characteristics of hydrocarbon enrichment in the fourth member of Shahejie Formation were determined according to actual geologic conditions in Bonan area. The method for determining the type of hydrocarbon reservoir was provided through analyzing the formation mechanism of the continuous hydrocarbon reservoir. The study results show that widely dis? tributed source rock with high-quality，high formation pressure for hydrocarbon generation and continuous tight reservoir are the main characteristics of continuous reservoirs. The fourth member in Bonan area in the centre basin-slope has the geological conditions for continuous hydrocarbon reservoirs formation. The hydrocarbon accumulation could be seen as “pressure in source rock decreasing while hydrocarbon expelling and pressure in reservoir reconstructing while hydrocar? bon charging”. The minimum values of physical properties of reservoirs when hydrocarbon charging could be calculated by the relationship between the hydrocarbon generation pressure and capillary resistance，and the maximum values could be calculated by the pressure difference of continuous oil column and the relationship between the buoyancy of oil column and the capillary resistance at the top of the oil column. A method for calculating the minimum and maximum value of the property was put forward according to the recognition. The porosity of the hydrocarbon reservoirs is 2%-11% calculated by this method and errors would be made since its accuracy may be affected by the quantification extent of pressure，porosity and resistance. The calculated results will be more closed to the actual geological condition when the quantitative model of the influencing factors is improved.
Continuous hydrocarbon reservoir is an important type of hydrocarbon accumulation. Determining its distribution borders is significant for oil petroleum exploration. Based on analysis of continuous reservoirs found in domestic and overseas，the characteristics of hydrocarbon enrichment in the fourth member of Shahejie Formation were determined according to actual geologic conditions in Bonan area. The method for determining the type of hydrocarbon reservoir was provided through analyzing the formation mechanism of the continuous hydrocarbon reservoir. The study results show that widely dis? tributed source rock with high-quality，high formation pressure for hydrocarbon generation and continuous tight reservoir are the main characteristics of continuous reservoirs. The fourth member in Bonan area in the centre basin-slope has the geological conditions for continuous hydrocarbon reservoirs formation. The hydrocarbon accumulation could be seen as “pressure in source rock decreasing while hydrocarbon expelling and pressure in reservoir reconstructing while hydrocar? bon charging”. The minimum values of physical properties of reservoirs when hydrocarbon charging could be calculated by the relationship between the hydrocarbon generation pressure and capillary resistance，and the maximum values could be calculated by the pressure difference of continuous oil column and the relationship between the buoyancy of oil column and the capillary resistance at the top of the oil column. A method for calculating the minimum and maximum value of the property was put forward according to the recognition. The porosity of the hydrocarbon reservoirs is 2%-11% calculated by this method and errors would be made since its accuracy may be affected by the quantification extent of pressure，porosity and resistance. The calculated results will be more closed to the actual geological condition when the quantitative model of the influencing factors is improved.
2015, 22(2):9-16.
Abstract:
According to basin drilling data，logging，core analysis，burial history，paleotempreture，etc.，the spatial distribution，diagenesis and sealing capability evolution mode，porosity，permeability and breakthrough pressures of mudstone in the Upper Paleozoic of south Ordos Basin were studied. And based on that，corresponding evaluation standard and method were proposed to make a comprehensive assessment of the sealing capability of mudstone in the Upper Paleozoic. The obtained results show that：classⅠmudstone caprock in the Shiqianfeng Formation developed with the best sealing capability in the south Ordos Basin，especially in well areas of Zhentan1 and Huangshen1 where the comprehensive evolution weighted value reaches 3.5；abnormal high pressures develop in the Upper Shihezi Formation，where classⅣcaprock distributes widely with the worst physical sealing capability. ClassⅣmudstone caprock is developed in the Lower Shihezi Formation in the west and the south of the research area and classⅠand classⅡcaprock are in the northeast. For mudstone in the Shanxi Formation，those at the late diagenesis C stage is classⅢor classⅣcaprock and those at the late diagenesis B stage is class Ⅰor classⅡcaprock. Industrial gas flow wells distribute in areas with good caprock sealing capability. The comprehensive evaluation results coincide with the exploration practice，which can provide references for gas exploration of the south area.
According to basin drilling data，logging，core analysis，burial history，paleotempreture，etc.，the spatial distribution，diagenesis and sealing capability evolution mode，porosity，permeability and breakthrough pressures of mudstone in the Upper Paleozoic of south Ordos Basin were studied. And based on that，corresponding evaluation standard and method were proposed to make a comprehensive assessment of the sealing capability of mudstone in the Upper Paleozoic. The obtained results show that：classⅠmudstone caprock in the Shiqianfeng Formation developed with the best sealing capability in the south Ordos Basin，especially in well areas of Zhentan1 and Huangshen1 where the comprehensive evolution weighted value reaches 3.5；abnormal high pressures develop in the Upper Shihezi Formation，where classⅣcaprock distributes widely with the worst physical sealing capability. ClassⅣmudstone caprock is developed in the Lower Shihezi Formation in the west and the south of the research area and classⅠand classⅡcaprock are in the northeast. For mudstone in the Shanxi Formation，those at the late diagenesis C stage is classⅢor classⅣcaprock and those at the late diagenesis B stage is class Ⅰor classⅡcaprock. Industrial gas flow wells distribute in areas with good caprock sealing capability. The comprehensive evaluation results coincide with the exploration practice，which can provide references for gas exploration of the south area.
2015, 22(2):17-23.
Abstract:
The multi-phase supergene karst have developed with multi-plane of unconformity in Tazhong area of the Lower-Middle Ordovician Yingshan Formation that mainly went through the middle Caledonian-early Hercynian tectonic movements，but the dominated factors affecting the distribution characteristics of supergene karst were not analyzed deeply enough at the moment. In the study area the Lower-Middle Ordovician is a set of stable platform deposition. The karst palaeogeomorphology of the Yingshan Formation was recovered using isochronous residual thickness and was divided into three geomorphic units as karst highland，karst slope and karst basin. Combining with the cave-depth analysis of the supergene karst in Tarim，the depth of supergene karst in the study area is within 180 meters below the unconformity. Karst layers were identified through integrating drilling，core，log and seismic data. It is found that 3 karst platform surfaces are corresponding to 3 karst layers based on the karst layer comparative analysis in the study area，and the karst layers mainly developed in the karst slopes. The main factors affecting karst distribution are lithologic and structure.
The multi-phase supergene karst have developed with multi-plane of unconformity in Tazhong area of the Lower-Middle Ordovician Yingshan Formation that mainly went through the middle Caledonian-early Hercynian tectonic movements，but the dominated factors affecting the distribution characteristics of supergene karst were not analyzed deeply enough at the moment. In the study area the Lower-Middle Ordovician is a set of stable platform deposition. The karst palaeogeomorphology of the Yingshan Formation was recovered using isochronous residual thickness and was divided into three geomorphic units as karst highland，karst slope and karst basin. Combining with the cave-depth analysis of the supergene karst in Tarim，the depth of supergene karst in the study area is within 180 meters below the unconformity. Karst layers were identified through integrating drilling，core，log and seismic data. It is found that 3 karst platform surfaces are corresponding to 3 karst layers based on the karst layer comparative analysis in the study area，and the karst layers mainly developed in the karst slopes. The main factors affecting karst distribution are lithologic and structure.
2015, 22(2):24-27.
Abstract:
Stratigraphic composition has an important influence or restrict on fault structure. Fault structure characteristics with different sandstone contents of strata have been researched based on physical simulation experiments. The experiments show that the fault is a binary type when the sandstone content is 100%；the fault develops into a unary type while the shale content is 4%-16% and a binary type while the shale content is 16%-20%；and it develops into binary or ternary type with unclear boundaries while the shale content is 20%-35%；the fault is binary type again when the shale content is 35%-50% and becomes unary type when shale content is 50%-100%. There is an apparent positive correlation among the shale content，the width of damage zone and the number of induced joints，which is an approximately normal distribution.
Stratigraphic composition has an important influence or restrict on fault structure. Fault structure characteristics with different sandstone contents of strata have been researched based on physical simulation experiments. The experiments show that the fault is a binary type when the sandstone content is 100%；the fault develops into a unary type while the shale content is 4%-16% and a binary type while the shale content is 16%-20%；and it develops into binary or ternary type with unclear boundaries while the shale content is 20%-35%；the fault is binary type again when the shale content is 35%-50% and becomes unary type when shale content is 50%-100%. There is an apparent positive correlation among the shale content，the width of damage zone and the number of induced joints，which is an approximately normal distribution.
2015, 22(2):28-32.
Abstract:
Chengbei oilfield has been found for over 30 years，but the progressive exploration result here is not satisfied. It is imperative to finely describe tectonic-sedimentary characteristics in the Chengbei low uplift and neighboring regions in Bohai Sea area and analyze the exploration potential to ease the stress of increasing oil reserves and productions on Chengbei oilfield. The tectonic characteristics，stratigraphy and stratigraphic contact，and sedimentary controlling factors in the study region were described again or redefined using sequence stratigraphy analysis，paleo-geomorphology restoration and comprehensive reservoir prediction technology. The research results show that the Chengbei low uplift and its surrounding area can be divided into 4 tectonic belts：drape structural belt in the low uplift，steep slope zone in the south，gentle slope zone in the north and overlapping belt pitching out into the west. In the Paleogene，fan delta deposited in the south steep slope zone was controlled by a ravine-fault system，and braided river delta deposited in the north gentle slope zone was controlled by a ravine-slope break system while that deposited in the west was controlled by a trend-transform zone that pinching out into the west. The Paleogene fan deltas and braided river delta sandbodies have better reservoir conditions with provenance from the Chengbei low uplift，which could form structural and stratigraphic overlap traps combining with the south and north boundary faults and stratigraphic overlap belts.
Chengbei oilfield has been found for over 30 years，but the progressive exploration result here is not satisfied. It is imperative to finely describe tectonic-sedimentary characteristics in the Chengbei low uplift and neighboring regions in Bohai Sea area and analyze the exploration potential to ease the stress of increasing oil reserves and productions on Chengbei oilfield. The tectonic characteristics，stratigraphy and stratigraphic contact，and sedimentary controlling factors in the study region were described again or redefined using sequence stratigraphy analysis，paleo-geomorphology restoration and comprehensive reservoir prediction technology. The research results show that the Chengbei low uplift and its surrounding area can be divided into 4 tectonic belts：drape structural belt in the low uplift，steep slope zone in the south，gentle slope zone in the north and overlapping belt pitching out into the west. In the Paleogene，fan delta deposited in the south steep slope zone was controlled by a ravine-fault system，and braided river delta deposited in the north gentle slope zone was controlled by a ravine-slope break system while that deposited in the west was controlled by a trend-transform zone that pinching out into the west. The Paleogene fan deltas and braided river delta sandbodies have better reservoir conditions with provenance from the Chengbei low uplift，which could form structural and stratigraphic overlap traps combining with the south and north boundary faults and stratigraphic overlap belts.
2015, 22(2):33-38.
Abstract:
The lower member of Xingouzui Formation（Ex）of Paleogene in Jiangling sag is rich in gypsum-salt rocks. The hydrocarbon accumulation is closely related to the distribution of gypsum-salt rock. By analyzing the cores，logs and seismic data，it is found that the lithologic and the electric characteristics of gypsum-salt rocks are low density and high electronic resistivity. Based on forward modeling，their seismic responses are characterized by high amplitude and low frequency. Combined with well-seismic calibrating，it is found that different lithologic has different seismic response. The seismic reflection characteristics of gypsum-salt rock are strong amplitude，low frequency and good continuity. Seismic responses of the interbeded sand and shale are characterized by strong amplitude and bad continuity. Weak amplitude reflection feature appears in mudstone. By extracting the seismic attribute data，the characteristics of seismic attributes of typical facies were determined，and the relationship among lithological facies，seismic response and seismic attribute was established to predict the gypsum-salt distribution in the undrilled zone based on the drilled area in Jiangling sag. In conclusion，gypsumsalt rock in Lower Ex of Jiangling sag distributes in two areas of the southern of Meihuaiqiao subsag and Zifusi subsag.
The lower member of Xingouzui Formation（Ex）of Paleogene in Jiangling sag is rich in gypsum-salt rocks. The hydrocarbon accumulation is closely related to the distribution of gypsum-salt rock. By analyzing the cores，logs and seismic data，it is found that the lithologic and the electric characteristics of gypsum-salt rocks are low density and high electronic resistivity. Based on forward modeling，their seismic responses are characterized by high amplitude and low frequency. Combined with well-seismic calibrating，it is found that different lithologic has different seismic response. The seismic reflection characteristics of gypsum-salt rock are strong amplitude，low frequency and good continuity. Seismic responses of the interbeded sand and shale are characterized by strong amplitude and bad continuity. Weak amplitude reflection feature appears in mudstone. By extracting the seismic attribute data，the characteristics of seismic attributes of typical facies were determined，and the relationship among lithological facies，seismic response and seismic attribute was established to predict the gypsum-salt distribution in the undrilled zone based on the drilled area in Jiangling sag. In conclusion，gypsumsalt rock in Lower Ex of Jiangling sag distributes in two areas of the southern of Meihuaiqiao subsag and Zifusi subsag.
2015, 22(2):39-44.
Abstract:
The potential of hydrocarbon accumulating in drape structure on the uplift in Neogene differs with uplifts，which is the main reservoir type in Zhanhua sag. Using drilling and geophysical data，the relationship between uplift belt rotationshearing movement and oil and gas accumulation of Neogene in Zhanhua sag was studied through analyzing the regional geological mechanics，the fault rotation-shearing characteristics and hydrocarbon reservoir. The research results show that Zhanhua uplift sheared and rotated to the right clockwise induced by the dextral strike slip of Tanlu faulted belt and the weak regional NE-SW compressional stress field duing Neogene. Under the rotation-shearing action，the faults，locating on the left side of uplift（North for the reference direction），twisted and opened to make a dominant pathway for hydrocarbon migrating or accumulating. The faults，locating on the right side of uplift，are characterized by compress-shear properties which are unfavorable for oil and gas vertical migration. The drape structures of Neogene on the left side of the uplift（dominant pathway）are easy to form large-scale oil and gas reservoirs. The faulted zone on the left side of the uplift is favorable for subtle reservoir exploration in Neogene for the next step.
The potential of hydrocarbon accumulating in drape structure on the uplift in Neogene differs with uplifts，which is the main reservoir type in Zhanhua sag. Using drilling and geophysical data，the relationship between uplift belt rotationshearing movement and oil and gas accumulation of Neogene in Zhanhua sag was studied through analyzing the regional geological mechanics，the fault rotation-shearing characteristics and hydrocarbon reservoir. The research results show that Zhanhua uplift sheared and rotated to the right clockwise induced by the dextral strike slip of Tanlu faulted belt and the weak regional NE-SW compressional stress field duing Neogene. Under the rotation-shearing action，the faults，locating on the left side of uplift（North for the reference direction），twisted and opened to make a dominant pathway for hydrocarbon migrating or accumulating. The faults，locating on the right side of uplift，are characterized by compress-shear properties which are unfavorable for oil and gas vertical migration. The drape structures of Neogene on the left side of the uplift（dominant pathway）are easy to form large-scale oil and gas reservoirs. The faulted zone on the left side of the uplift is favorable for subtle reservoir exploration in Neogene for the next step.
2015, 22(2):45-50.
Abstract:
The difficulty of Carboniferous igneous exploration in the Chepaizi area which is located in the west edge of Junggar Basin was studied. The seismic reflection of reservoir rock is clutter，so it is difficult to predict the favorable reservoir and crack areas. According to the drilling and seismic data，the gravity，magnetic，electric data and the seismic prediction technology were used to study hydrocarbon source rock conditions，hydrocarbon accumulation conditions and the key exploration technologies of the igneous rocks. The results showed that the study area was uplifted successively in a long term since it was formed during the Hercynian，and it is favorable for hydrocarbon migration. The oil and gas from Changji sag and Sikeshu sag migrated into fractured-porous reservoirs of igneous rock through faults and fractures and then accumulated there. The igneous rocks should have hydrocarbon generating conditions，which maybe provide oil source and was able to form a self-sourced and self-reservoired oil and gas pool. The industrial oil and gas obtained from the thick igneous rock developed in Carboniferous in the Chepaizi area. The oil-bearing property of the igneous rock reservoir is mainly correlated with the degree of fractures development. According to the predicted results of igneous rock reservoir，fracture zone and crack distribution，32 wells were drilled successfully，among which 11 wells were drilled at industrial oil and gas. The controlled geological oil reserves were reported to be 6 101×104 t.
The difficulty of Carboniferous igneous exploration in the Chepaizi area which is located in the west edge of Junggar Basin was studied. The seismic reflection of reservoir rock is clutter，so it is difficult to predict the favorable reservoir and crack areas. According to the drilling and seismic data，the gravity，magnetic，electric data and the seismic prediction technology were used to study hydrocarbon source rock conditions，hydrocarbon accumulation conditions and the key exploration technologies of the igneous rocks. The results showed that the study area was uplifted successively in a long term since it was formed during the Hercynian，and it is favorable for hydrocarbon migration. The oil and gas from Changji sag and Sikeshu sag migrated into fractured-porous reservoirs of igneous rock through faults and fractures and then accumulated there. The igneous rocks should have hydrocarbon generating conditions，which maybe provide oil source and was able to form a self-sourced and self-reservoired oil and gas pool. The industrial oil and gas obtained from the thick igneous rock developed in Carboniferous in the Chepaizi area. The oil-bearing property of the igneous rock reservoir is mainly correlated with the degree of fractures development. According to the predicted results of igneous rock reservoir，fracture zone and crack distribution，32 wells were drilled successfully，among which 11 wells were drilled at industrial oil and gas. The controlled geological oil reserves were reported to be 6 101×104 t.
2015, 22(2):51-54.
Abstract:
The shale developing in the Lower Cretaceous distributes widely in Gamba-Tingri basin. The shale gas exploration potential has been evaluated through the analysis of its thickness，organic abundance，organic evolution and brittleness.Cretaceous Gamba-Dongshan Formation in the study area consists of a set of shale or silty shale having siderite nodules or strips，which was formed under shelf-slope depositional environment. The formation distributes widely in the horizon direction including Tingri，Tingjie-Bamba and Gyangze-Nagarze areas，where shale thickness is generally over 100 m. Its organ? ic type is good mainly developing sapropelic or partial sapropelicⅡ1 type. And the organic matter is overall high mature or over mature and generates moisture-dry gas mainly. The shale mineral composition mainly consists of brittle quartz and feldspar，which is favorable for induced fracture formation and has strong adsorption at the same time. It is concluded that the shale in the Lower Cretaceous of the Gamba-Tingri basin has favorable conditions for shale gas accumulation based on organic geochemical parameters analysis and other shale gas exploration practice.
The shale developing in the Lower Cretaceous distributes widely in Gamba-Tingri basin. The shale gas exploration potential has been evaluated through the analysis of its thickness，organic abundance，organic evolution and brittleness.Cretaceous Gamba-Dongshan Formation in the study area consists of a set of shale or silty shale having siderite nodules or strips，which was formed under shelf-slope depositional environment. The formation distributes widely in the horizon direction including Tingri，Tingjie-Bamba and Gyangze-Nagarze areas，where shale thickness is generally over 100 m. Its organ? ic type is good mainly developing sapropelic or partial sapropelicⅡ1 type. And the organic matter is overall high mature or over mature and generates moisture-dry gas mainly. The shale mineral composition mainly consists of brittle quartz and feldspar，which is favorable for induced fracture formation and has strong adsorption at the same time. It is concluded that the shale in the Lower Cretaceous of the Gamba-Tingri basin has favorable conditions for shale gas accumulation based on organic geochemical parameters analysis and other shale gas exploration practice.
2015, 22(2):55-59.
Abstract:
Based on the structural interpretation and fault system of Qingnan subsag，the fault evolution and tectonic styles were analyzed in detail. The effects on hydrocarbon source rock evolution，reservoir development and controls on hydrocarbon accumulation were studied. The results show that Qingnan subsag began to build up during the sedimentation of Kongdian Formation while multi-phase faults with directions of NW，EW and NNE developed due to the interaction of stretch of the Dongying sag and the strike-slip mechanism of TanLu faults. As a result the extensional tectonic style，the extensional tectonic-strike-slip style and strike-slip style developed in different evolutional stages and controlled the tectonic evolution，thus bring on its specification and complication. The tectonic evolution controls the evolution of hydrocarbon source rocks and the development of reservoirs and cap rock. Excellent source rock of Es4 developed in Qingnan subsag；the littoral and shallow lake bars developed widely in Qingnan subsag are the main oil and gas entrapment to form bar and shoal reservoirs in Es4 that are mainly tectonic and tectonic-lithology type.
Based on the structural interpretation and fault system of Qingnan subsag，the fault evolution and tectonic styles were analyzed in detail. The effects on hydrocarbon source rock evolution，reservoir development and controls on hydrocarbon accumulation were studied. The results show that Qingnan subsag began to build up during the sedimentation of Kongdian Formation while multi-phase faults with directions of NW，EW and NNE developed due to the interaction of stretch of the Dongying sag and the strike-slip mechanism of TanLu faults. As a result the extensional tectonic style，the extensional tectonic-strike-slip style and strike-slip style developed in different evolutional stages and controlled the tectonic evolution，thus bring on its specification and complication. The tectonic evolution controls the evolution of hydrocarbon source rocks and the development of reservoirs and cap rock. Excellent source rock of Es4 developed in Qingnan subsag；the littoral and shallow lake bars developed widely in Qingnan subsag are the main oil and gas entrapment to form bar and shoal reservoirs in Es4 that are mainly tectonic and tectonic-lithology type.
2015, 22(2):60-65.
Abstract:
Compared to the conventional reverse time migration（RTM），RTM of multiples has a higher imaging precision.Based on the analysis of the imaging principle and conditions of RTM of multiples，the paper studied the steps of multiples prediction，wave field extrapolation and so on in the imaging process of RTM of multiples. Then，the shot gathers with only multiples were obtained by applying the surface-related multiples elimination method based on feedback loop theory to the Sigsbee2B geological model，and the imaging processing of RTM of multiples was implemented based on the acceleration of multi-card GPU. The processing results show that the imaging result of the middle-shallow layer obtained by RTM of multiples is clear，and the imaging precision of shallow structures is obviously higher than that obtained by conventional RTM.Besides，the computational speed and efficiency can be improved significantly by the application of multi-card GPU，which makes it possible for the imaging processing of RTM of multiples based on big data.
Compared to the conventional reverse time migration（RTM），RTM of multiples has a higher imaging precision.Based on the analysis of the imaging principle and conditions of RTM of multiples，the paper studied the steps of multiples prediction，wave field extrapolation and so on in the imaging process of RTM of multiples. Then，the shot gathers with only multiples were obtained by applying the surface-related multiples elimination method based on feedback loop theory to the Sigsbee2B geological model，and the imaging processing of RTM of multiples was implemented based on the acceleration of multi-card GPU. The processing results show that the imaging result of the middle-shallow layer obtained by RTM of multiples is clear，and the imaging precision of shallow structures is obviously higher than that obtained by conventional RTM.Besides，the computational speed and efficiency can be improved significantly by the application of multi-card GPU，which makes it possible for the imaging processing of RTM of multiples based on big data.
2015, 22(2):66-71.
Abstract:
Dynamic variation rule of coal reservoir permeability is one of the most important issues in development geology field of coalbed methane（CBM）. According to the method of dimensionless production analysis，the whole drainage and production process is divided into four stages as water drainage，unstable gas production，stable gas production and gas production decline based on drainage and production data of fifteen high-rank CBM wells in southern Qinshui Basin. The coal permeability variation value at different stages were analyzed with production data by material balance method. The dynamic variation value and mechanism of permeability in high-rank CBM wells at different drainage and production stages are interpreted in five aspects：permeability variation trend，leading mechanism，systemic energy，phase composition and dynamic productivity. The study reveals that the coal bed permeability in high-rank CBM wells show the trend of decline-recovering-rising during produced process. Effective stress effect and matrix shrinkage effect directly control the dynamic variation characteristics of the coal reservoir permeability. Characteristics of adsorption（desorption）control the acting time and strength of the matrix shrinkage effect fundamentally.
Dynamic variation rule of coal reservoir permeability is one of the most important issues in development geology field of coalbed methane（CBM）. According to the method of dimensionless production analysis，the whole drainage and production process is divided into four stages as water drainage，unstable gas production，stable gas production and gas production decline based on drainage and production data of fifteen high-rank CBM wells in southern Qinshui Basin. The coal permeability variation value at different stages were analyzed with production data by material balance method. The dynamic variation value and mechanism of permeability in high-rank CBM wells at different drainage and production stages are interpreted in five aspects：permeability variation trend，leading mechanism，systemic energy，phase composition and dynamic productivity. The study reveals that the coal bed permeability in high-rank CBM wells show the trend of decline-recovering-rising during produced process. Effective stress effect and matrix shrinkage effect directly control the dynamic variation characteristics of the coal reservoir permeability. Characteristics of adsorption（desorption）control the acting time and strength of the matrix shrinkage effect fundamentally.
2015, 22(2):72-77.
Abstract:
There is a threshold pressure gradient in the flow of fluid in low-permeability reservoirs. Based on the non-Darcy flow theory，a new computing method of natural depletion oil recovery considering the threshold pressure gradient in different flow forms was analyzed. The calculating formulas for depletion oil recovery of the vertical well，fractured vertical well，horizontal well，and fractured horizontal well in the low-permeability reservoir were developed. The effect of each parameter on the depletion oil recovery was discussed while applying the formulas to real cases. The results show that the de? pletion oil recovery decreased linearly with the increase of threshold pressure gradient. The oil recovery of the vertical wells is very sensitive to the threshold pressure gradient，the horizontal well is less sensitive，and the effect for the fractured horizontal wells is the weakest. The depletion oil recovery and the one per unit pressure drawdown increases with pressure drawdown linearly and in a gradually slower manner respectively. The depletion oil recovery of the fractured vertical well increases with the half fracture length，but the effect decreases gradually. Half fracture length is more sensitive than fracture space to the depletion oil recovery in the fractured horizontal wells. There is optimized half fracture length. It is recommended that the low-permeability reservoir with large threshold pressure gradient under depletion development should be developed with hydraulic fracturing.
There is a threshold pressure gradient in the flow of fluid in low-permeability reservoirs. Based on the non-Darcy flow theory，a new computing method of natural depletion oil recovery considering the threshold pressure gradient in different flow forms was analyzed. The calculating formulas for depletion oil recovery of the vertical well，fractured vertical well，horizontal well，and fractured horizontal well in the low-permeability reservoir were developed. The effect of each parameter on the depletion oil recovery was discussed while applying the formulas to real cases. The results show that the de? pletion oil recovery decreased linearly with the increase of threshold pressure gradient. The oil recovery of the vertical wells is very sensitive to the threshold pressure gradient，the horizontal well is less sensitive，and the effect for the fractured horizontal wells is the weakest. The depletion oil recovery and the one per unit pressure drawdown increases with pressure drawdown linearly and in a gradually slower manner respectively. The depletion oil recovery of the fractured vertical well increases with the half fracture length，but the effect decreases gradually. Half fracture length is more sensitive than fracture space to the depletion oil recovery in the fractured horizontal wells. There is optimized half fracture length. It is recommended that the low-permeability reservoir with large threshold pressure gradient under depletion development should be developed with hydraulic fracturing.
2015, 22(2):78-82.
Abstract:
Nowadays，parameter at both ends of the core may be gotten through conventional profile control experiments.However，the flow process of fluid such as oil，water or profile control system could not be visually presented in those experiments. In this paper，CT technology was applied to observe the dynamical flooding processes in core model casted by epoxy resin without damage，and then the front location of the water flooding and migration characteristics of modified starch gel in different times were re-established. Experimental results show that the CT technology can be effectively used in migration characteristics research and presentation for the profile control system. When it is applied to a positive rhythm core model with a permeability contrast of 30，the starting location of the low permeability layer in the first water drive could be given and seen. In the meantime，the profile control system can flow forward with the whole slug state in the high permeability layer，which can effectively shut off the flow channel in the high permeability layer after the gel is formed. Positioning profile control and water plugging may be realized and swept volume of the subsequent water may be expanded obviously. Oil recovery efficiency by water flooding is increased by 15.08%. This paper provides a new experimental method and research idea about the deep water plugging and profile control in heterogeneous reservoirs.
Nowadays，parameter at both ends of the core may be gotten through conventional profile control experiments.However，the flow process of fluid such as oil，water or profile control system could not be visually presented in those experiments. In this paper，CT technology was applied to observe the dynamical flooding processes in core model casted by epoxy resin without damage，and then the front location of the water flooding and migration characteristics of modified starch gel in different times were re-established. Experimental results show that the CT technology can be effectively used in migration characteristics research and presentation for the profile control system. When it is applied to a positive rhythm core model with a permeability contrast of 30，the starting location of the low permeability layer in the first water drive could be given and seen. In the meantime，the profile control system can flow forward with the whole slug state in the high permeability layer，which can effectively shut off the flow channel in the high permeability layer after the gel is formed. Positioning profile control and water plugging may be realized and swept volume of the subsequent water may be expanded obviously. Oil recovery efficiency by water flooding is increased by 15.08%. This paper provides a new experimental method and research idea about the deep water plugging and profile control in heterogeneous reservoirs.
2015, 22(2):83-87.
Abstract:
In later steam flooding period，steam breakthrough occurs easily. As a result，the oil production will decrease after the steam breakthrough. Serious steam breakthrough will lead to declination of oil-steam ratio and poorer development effect. In order to optimize the recovery factor and the economy of the development，the study of converting time in later steam flooding period is a very important issue. The decline history of heavy oil production in later steam flooding period was analyzed to understand the decline trend. A formula for oil recovery factor was obtained after characteristic formula of steam injection and production was derived. Finally the converting time was calculated by combining the equations.Through the analysis of certain well group of Qi40 block in Liaohe oilfield，a conclusion can be drawn that it is not suitable to convert to other development methods even the steam breakthrough occurs at the present period. The calculation result indicates that it is appropriate to convert steam flooding to steam-water alternate injection in January 2017. The simulation study also shows that the steam chamber can be fully developed in the reservoir till January 2017. More serious steam breakthrough will occur. So it is appropriate to convert steam flooding to other development methods. The calculation result agrees well with the numerical simulation results and it is important for the oilfield development guidance.
In later steam flooding period，steam breakthrough occurs easily. As a result，the oil production will decrease after the steam breakthrough. Serious steam breakthrough will lead to declination of oil-steam ratio and poorer development effect. In order to optimize the recovery factor and the economy of the development，the study of converting time in later steam flooding period is a very important issue. The decline history of heavy oil production in later steam flooding period was analyzed to understand the decline trend. A formula for oil recovery factor was obtained after characteristic formula of steam injection and production was derived. Finally the converting time was calculated by combining the equations.Through the analysis of certain well group of Qi40 block in Liaohe oilfield，a conclusion can be drawn that it is not suitable to convert to other development methods even the steam breakthrough occurs at the present period. The calculation result indicates that it is appropriate to convert steam flooding to steam-water alternate injection in January 2017. The simulation study also shows that the steam chamber can be fully developed in the reservoir till January 2017. More serious steam breakthrough will occur. So it is appropriate to convert steam flooding to other development methods. The calculation result agrees well with the numerical simulation results and it is important for the oilfield development guidance.
2015, 22(2):88-92.
Abstract:
When the development of low permeability reservoir reaches the high water-cut stage，infill well or well spacing adjustment is needed to exploit the remaining oil and enhance the oil recovery efficiency. The technical limited well spacing is an important factor of tapping the potential of the remaining oil. Based on the feature of start-up pressure gradient in the low permeability reservoir and the theory of the oil-water two-phase flow，concepts of pseudo-viscosity and pseudo-potential were introduced. A calculation formula of the technical limited well spacing in the low permeability reservoir was es? tablished based on the potential superposition principle. The influencing factors such as the reservoir permeability，water saturation and the inject-production pressure difference were analyzed with the actual reservoir parameters. The results show that the technical limited well spacing increases with the reservoir permeability，water saturation and the inject-production pressure difference. The calculation results were applied into the actual well pattern arrangement. The maximum well spacing is about 350 m in the areas with better physical properties and low remaining oil saturation and the minimum one is about 250 m in the areas with poor physical properties and high remaining oil saturation. Adjusted well pattern has stronger control ability on remaining recoverable reserves and the oil recovery efficiency will be enhanced by 4.1 percent.
When the development of low permeability reservoir reaches the high water-cut stage，infill well or well spacing adjustment is needed to exploit the remaining oil and enhance the oil recovery efficiency. The technical limited well spacing is an important factor of tapping the potential of the remaining oil. Based on the feature of start-up pressure gradient in the low permeability reservoir and the theory of the oil-water two-phase flow，concepts of pseudo-viscosity and pseudo-potential were introduced. A calculation formula of the technical limited well spacing in the low permeability reservoir was es? tablished based on the potential superposition principle. The influencing factors such as the reservoir permeability，water saturation and the inject-production pressure difference were analyzed with the actual reservoir parameters. The results show that the technical limited well spacing increases with the reservoir permeability，water saturation and the inject-production pressure difference. The calculation results were applied into the actual well pattern arrangement. The maximum well spacing is about 350 m in the areas with better physical properties and low remaining oil saturation and the minimum one is about 250 m in the areas with poor physical properties and high remaining oil saturation. Adjusted well pattern has stronger control ability on remaining recoverable reserves and the oil recovery efficiency will be enhanced by 4.1 percent.
2015, 22(2):93-97.
Abstract:
Because the steam stimulation of heavy oil reservoir belongs to the blowdown depleted development，the reservoir energy can not effectively maintain the supply of liquid and the recovery effect gets worse at later stage of the steam stimulation. Steam overlapping is serious and vertical oil sweep factor is low. Injecting steam with some gas or chemicals to assist the steam stimulation can effectively improve mobility ratio and the development effect of the heavy oil reservoir. The indoor single tube experiment studied the effect of different assisted methods on the steam drive. The results of the experiment showed that the displacement efficiency of flue gas foam assisted steam stimulation could be increased by19% compared with that of the steam stimulation. Based on these results of physical simulation experiment，numerical simulation methods were used to compare the different influences of different assisted methods on the steam stimulation effect. The results accorded with the results of physical simulation experiments. The recovery effect of flue gas foam assisted steam stimulation was the best considering many kinds of factors followed by nitrogen foam. When the formation heterogeneity was very poor and the oil viscosity was very high，the recovery effect of flue gas foam assisted steam stimulation could be more obvious.
Because the steam stimulation of heavy oil reservoir belongs to the blowdown depleted development，the reservoir energy can not effectively maintain the supply of liquid and the recovery effect gets worse at later stage of the steam stimulation. Steam overlapping is serious and vertical oil sweep factor is low. Injecting steam with some gas or chemicals to assist the steam stimulation can effectively improve mobility ratio and the development effect of the heavy oil reservoir. The indoor single tube experiment studied the effect of different assisted methods on the steam drive. The results of the experiment showed that the displacement efficiency of flue gas foam assisted steam stimulation could be increased by19% compared with that of the steam stimulation. Based on these results of physical simulation experiment，numerical simulation methods were used to compare the different influences of different assisted methods on the steam stimulation effect. The results accorded with the results of physical simulation experiments. The recovery effect of flue gas foam assisted steam stimulation was the best considering many kinds of factors followed by nitrogen foam. When the formation heterogeneity was very poor and the oil viscosity was very high，the recovery effect of flue gas foam assisted steam stimulation could be more obvious.
2015, 22(2):98-102.
Abstract:
In view of strong reservoir heterogeneity，thick oil layers and large well spacing in the offshore oilfield，a polymer gel with controllable gel strength for deep profile control and oil displacement was developed. Gel strength modifier tert-butyl hydroperoxide（TBHP）was added into common organic phenolic resin gel to adjust the gel strength. The effects of the tert-butyl hydroperoxide（TBHP）on gelation time and gel strength were studied. The microstructures of the novel gel at different aging times were observed by scanning electron microscopy（SEM）to analyze the gel strength change mechanism.The transport properties of the novel gel in porous media were evaluated by monitoring the pressure distribution during water flooding after gelation in porous media at different aging times. Results show that the effect of gel strength modifier on gelation time is not obvious. As the aging time and gel strength modifier concentration increase，the gel strength decreases gradually under reservoir temperature and the gel strength modifier. Compared with the conventional gel，the network structure of the novel gel is destroyed more seriously and it can migrate in porous media after aging for 30 d.
In view of strong reservoir heterogeneity，thick oil layers and large well spacing in the offshore oilfield，a polymer gel with controllable gel strength for deep profile control and oil displacement was developed. Gel strength modifier tert-butyl hydroperoxide（TBHP）was added into common organic phenolic resin gel to adjust the gel strength. The effects of the tert-butyl hydroperoxide（TBHP）on gelation time and gel strength were studied. The microstructures of the novel gel at different aging times were observed by scanning electron microscopy（SEM）to analyze the gel strength change mechanism.The transport properties of the novel gel in porous media were evaluated by monitoring the pressure distribution during water flooding after gelation in porous media at different aging times. Results show that the effect of gel strength modifier on gelation time is not obvious. As the aging time and gel strength modifier concentration increase，the gel strength decreases gradually under reservoir temperature and the gel strength modifier. Compared with the conventional gel，the network structure of the novel gel is destroyed more seriously and it can migrate in porous media after aging for 30 d.
2015, 22(2):103-106.
Abstract:
Artificial edge water flooding technology can enhance oil recovery of the complex fault-block reservoir effectively. Influencing factors on the effect of the artificial edge water flooding are various. The sensibility of the influencing factors on the oil displacement effect is not clear，which has limited reservoir optimization and execution of planning. Taking the complex fault-block reservoir with obvious field result as an example，the effect of reservoir influencing factors on the degree of enhancing oil recovery by the artificial edge water flooding were studied using reservoir numerical simulation so as to provide basis for block optimization. Eight influencing factors were determined covering three aspects of structure，reservoirs and fluid. The influence mechanism was interpreted based on the theory of reservoir physics and reservoir percolation.Optimization standards of the complex fault-block reservoir were established for the artificial edge water flooding. Quantified standards and relationship charts of single reservoir factors versus enhanced oil recovery were given.
Artificial edge water flooding technology can enhance oil recovery of the complex fault-block reservoir effectively. Influencing factors on the effect of the artificial edge water flooding are various. The sensibility of the influencing factors on the oil displacement effect is not clear，which has limited reservoir optimization and execution of planning. Taking the complex fault-block reservoir with obvious field result as an example，the effect of reservoir influencing factors on the degree of enhancing oil recovery by the artificial edge water flooding were studied using reservoir numerical simulation so as to provide basis for block optimization. Eight influencing factors were determined covering three aspects of structure，reservoirs and fluid. The influence mechanism was interpreted based on the theory of reservoir physics and reservoir percolation.Optimization standards of the complex fault-block reservoir were established for the artificial edge water flooding. Quantified standards and relationship charts of single reservoir factors versus enhanced oil recovery were given.
2015, 22(2):107-111.
Abstract:
The behavior of oxidative viscosity reduction using microemulsion catalyst was investigated according to the heavy oil recovery technology of oxidizing reduction. FeB is selected from11 kinds of synthetic oil-soluble catalyst，by which a microemulsion catalyst system can be made（mass ratio of catalyst FeB∶distillate oil∶water∶emulsifier is 1.5∶40∶57.3∶1.2）with better dispersion in the heavy oil. The performance evaluation results show that under the experimental condition（the mass ratio of micoroemusion catalyst and heavy oil is 0.2%，and mass ratio of oil and water is 2∶3，and volume ra? tio of air and heavy oil is 40∶1，and the oxidation temperature is 200 ℃and reaction time is 120 h），the viscosity of heavy oil in Liaohe oilfield and Suizhong 36-1 oilfield dropped from 8 088 and 2 004 mPa?s to 683 and 267 mPa?s respectively，and the effect of viscosity reduction is obvious. Microemulsion catalysts used in the heavy oil mining technology of oxidative viscosity reducing will help to promote the efficiency of the heavy oil development and the research and application of new EOR technology.
The behavior of oxidative viscosity reduction using microemulsion catalyst was investigated according to the heavy oil recovery technology of oxidizing reduction. FeB is selected from11 kinds of synthetic oil-soluble catalyst，by which a microemulsion catalyst system can be made（mass ratio of catalyst FeB∶distillate oil∶water∶emulsifier is 1.5∶40∶57.3∶1.2）with better dispersion in the heavy oil. The performance evaluation results show that under the experimental condition（the mass ratio of micoroemusion catalyst and heavy oil is 0.2%，and mass ratio of oil and water is 2∶3，and volume ra? tio of air and heavy oil is 40∶1，and the oxidation temperature is 200 ℃and reaction time is 120 h），the viscosity of heavy oil in Liaohe oilfield and Suizhong 36-1 oilfield dropped from 8 088 and 2 004 mPa?s to 683 and 267 mPa?s respectively，and the effect of viscosity reduction is obvious. Microemulsion catalysts used in the heavy oil mining technology of oxidative viscosity reducing will help to promote the efficiency of the heavy oil development and the research and application of new EOR technology.
2015, 22(2):117-121.
Abstract:
Acid fracturing is the key production and stimulation technology for the carbonate reservoirs. Ultra-deep horizon? tal wells should be reformed through staged acid fracturing for their complex well conditions. Mechanical packer acid fracturing technology is limited and cannot be used in the ultra-deep horizontal wells due to the influence of well depth and structure. A new type of biodegradable fiber temporary plugging agent has been developed to ensure the success rate and stimulation effect of these wells. Performance evaluation indicates that the new agent has great dispersion and degradation performance，and the diverting and plugging effect is obvious；in the meanwhile，a composite acid fracturing technology has been put forward. By the end of June 2014，10 wells have been treated with this technology achieving 3-10 MPa increase in flow pressure，80% of efficiency，and 1.75-6.1 times of stimulated production. The gas production rate after treatment is about 50×104 m3/d and some are higher than 100×104 m3/d，which indicates significant stimulation effect. Laboratory experiment and field tests both confirm that this technology can realize effective stimulation in the ultra-deep horizontal wells with strong heterogeneity and developed fractures. The treatment process is simple with low operation risk and great adaptability. So it is recommended to apply widely.
Acid fracturing is the key production and stimulation technology for the carbonate reservoirs. Ultra-deep horizon? tal wells should be reformed through staged acid fracturing for their complex well conditions. Mechanical packer acid fracturing technology is limited and cannot be used in the ultra-deep horizontal wells due to the influence of well depth and structure. A new type of biodegradable fiber temporary plugging agent has been developed to ensure the success rate and stimulation effect of these wells. Performance evaluation indicates that the new agent has great dispersion and degradation performance，and the diverting and plugging effect is obvious；in the meanwhile，a composite acid fracturing technology has been put forward. By the end of June 2014，10 wells have been treated with this technology achieving 3-10 MPa increase in flow pressure，80% of efficiency，and 1.75-6.1 times of stimulated production. The gas production rate after treatment is about 50×104 m3/d and some are higher than 100×104 m3/d，which indicates significant stimulation effect. Laboratory experiment and field tests both confirm that this technology can realize effective stimulation in the ultra-deep horizontal wells with strong heterogeneity and developed fractures. The treatment process is simple with low operation risk and great adaptability. So it is recommended to apply widely.
2015, 22(2):122-126.
Abstract:
Fracturing is the major stimulation in the low permeability reservoirs，but the conventional fracturing has the problems of short effective fracture and being susceptible to fracturing fluid pollution. In order to increase the effective fracture length，to realize infinite conductivity of the fractures and to improve the success rate and effect，Hiway technology was researched from the aspects of applicable conditions，flow capability experiment of non-continuous proppant laying and method of maintaining the Hiway. The optimized fiber is：length is 10 mm，diameter is 15 μm，mass concentration is 10 kg/m3. The fiber and proppant should be injected together. Independent Hiway technology may be formed. It was applied to two wells in the oilfield with a success rate of 100%. By the end of December 2014，the cumulative incremental oil production is 3 700 t，increased by 15% compared with the oil wells in the same block by conventional fracturing. Compared with the conventional fracturing，Hiway technology has strong adaptability，low construction difficulty and good stimulation effect. It is suitable for the low permeability reservoirs with broad prospects.
Fracturing is the major stimulation in the low permeability reservoirs，but the conventional fracturing has the problems of short effective fracture and being susceptible to fracturing fluid pollution. In order to increase the effective fracture length，to realize infinite conductivity of the fractures and to improve the success rate and effect，Hiway technology was researched from the aspects of applicable conditions，flow capability experiment of non-continuous proppant laying and method of maintaining the Hiway. The optimized fiber is：length is 10 mm，diameter is 15 μm，mass concentration is 10 kg/m3. The fiber and proppant should be injected together. Independent Hiway technology may be formed. It was applied to two wells in the oilfield with a success rate of 100%. By the end of December 2014，the cumulative incremental oil production is 3 700 t，increased by 15% compared with the oil wells in the same block by conventional fracturing. Compared with the conventional fracturing，Hiway technology has strong adaptability，low construction difficulty and good stimulation effect. It is suitable for the low permeability reservoirs with broad prospects.
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