Volume 25,Issue 3,2018 Table of Contents
2018, 25(3):1-10.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.001
Abstract:
Based on the data of abundant wells and core analysis，combined with the characteristics of petrology，diagenesis and reservoir quality，the high-resolution sequence stratigraphic framework of the Baikouquan Formation in Bai21 Block of Baikouquan Oilfield was built through the analysis of single well sequence and sedimentary characteristics. Moreover，the sedimentary characteristics and mechanism of reservoir quality in different orders of base-level cycle were clarified. And then control factors that cause the difference of reservoir quality were discussed. The research results show that：①The hierarchy base-level ascending hemicycles are well developed in the Baikouquan Formation which belongs to a long-term cycle. 3 middle-term cycles and 9 short-term cycles were divided respectively corresponding to 3 sandbeds and 9 layers with in the formation；②The long-term base-level cycles control the alluvial fan distributed in retrogradational stacking pattern.The middle-term base-level cycles control the distribution of sandbodies in the Baikouquan Formation. Fan root subfacies，named B3 member，characterized with massive sandy conglomerated evolves into B2 member characterized with alternative deposition of massive sandy conglomerate and thick-layer fine conglomerate，and finally evolves into isolated braided channel subfacies named B1 member；③The Baikouquan Formation mainly consists of debris conglomerate with high content of plastic minerals and low textural-compositional maturity. Compaction is the main factor caused the loss of porosity. Hydrodynamic forces in the middle of long-term and middle-term base-level cycle tend to be stable and strong，and there are braided channels with low matrix content and strong anti-compaction ability. Therefore，the braided channels in the longterm and middle-term base-level cycle are the best reservoir.
Based on the data of abundant wells and core analysis，combined with the characteristics of petrology，diagenesis and reservoir quality，the high-resolution sequence stratigraphic framework of the Baikouquan Formation in Bai21 Block of Baikouquan Oilfield was built through the analysis of single well sequence and sedimentary characteristics. Moreover，the sedimentary characteristics and mechanism of reservoir quality in different orders of base-level cycle were clarified. And then control factors that cause the difference of reservoir quality were discussed. The research results show that：①The hierarchy base-level ascending hemicycles are well developed in the Baikouquan Formation which belongs to a long-term cycle. 3 middle-term cycles and 9 short-term cycles were divided respectively corresponding to 3 sandbeds and 9 layers with in the formation；②The long-term base-level cycles control the alluvial fan distributed in retrogradational stacking pattern.The middle-term base-level cycles control the distribution of sandbodies in the Baikouquan Formation. Fan root subfacies，named B3 member，characterized with massive sandy conglomerated evolves into B2 member characterized with alternative deposition of massive sandy conglomerate and thick-layer fine conglomerate，and finally evolves into isolated braided channel subfacies named B1 member；③The Baikouquan Formation mainly consists of debris conglomerate with high content of plastic minerals and low textural-compositional maturity. Compaction is the main factor caused the loss of porosity. Hydrodynamic forces in the middle of long-term and middle-term base-level cycle tend to be stable and strong，and there are braided channels with low matrix content and strong anti-compaction ability. Therefore，the braided channels in the longterm and middle-term base-level cycle are the best reservoir.
2018, 25(3):11-19.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.002
Abstract:
The hydrocarbon accumulation conditions in LD21 Oilfield were analyzed，using mud logging，well logging，coring and core analysis test data from five aspects，including the source rocks and oil source conditions，reservoir-seal assemblage，trap characteristics，oil and gas migration and preservation condition. The results show that the crude oil in LD21 Oilfield are mainly from the source rocks of the third member of Shahejie Formation and part of them from the source rocks of the first member of Shahejie Formation. The main reservoirs are the clastic rocks deposited in the braided river in the Guantao Formation. The style of source-reservoir-seal assemblage is source at the bottom，reservoir at the middle and seal at the top. Being controlled by central strike-slip fault，the trap in the west plate is a semi-anticline structure，and in the east plate is a complex fault block structure. The long activation of the inherited faults in the Neotectonic movement creates good conditions for oil and gas migration in LD21 Oilfield. The sealing capacity of faults in the fault-controlled traps of different fault blocks is different. The oil and gas reservoirs are mainly distributed in the semi-anticline structure of west plate and the flower-like structure of east plate，which is formed under the influence of strike-slip reversal in plane. In the longitudinal direction，the oil and gas are mainly concentrated in the ⅣandⅤoil groups under the mudstone cap rock of the Guantao Formation，and the oil reservoirs discovered by single well are characterized by large thickness，long length oilbearingsections and concentrated distribution of oil layers. Finally，the oil and gas accumulation of the LD21 Oilfield in the plane and vertical is controlled by the coupling of three elements，which are strike-slip reversal，regional cap and lateral sealing of fault.
The hydrocarbon accumulation conditions in LD21 Oilfield were analyzed，using mud logging，well logging，coring and core analysis test data from five aspects，including the source rocks and oil source conditions，reservoir-seal assemblage，trap characteristics，oil and gas migration and preservation condition. The results show that the crude oil in LD21 Oilfield are mainly from the source rocks of the third member of Shahejie Formation and part of them from the source rocks of the first member of Shahejie Formation. The main reservoirs are the clastic rocks deposited in the braided river in the Guantao Formation. The style of source-reservoir-seal assemblage is source at the bottom，reservoir at the middle and seal at the top. Being controlled by central strike-slip fault，the trap in the west plate is a semi-anticline structure，and in the east plate is a complex fault block structure. The long activation of the inherited faults in the Neotectonic movement creates good conditions for oil and gas migration in LD21 Oilfield. The sealing capacity of faults in the fault-controlled traps of different fault blocks is different. The oil and gas reservoirs are mainly distributed in the semi-anticline structure of west plate and the flower-like structure of east plate，which is formed under the influence of strike-slip reversal in plane. In the longitudinal direction，the oil and gas are mainly concentrated in the ⅣandⅤoil groups under the mudstone cap rock of the Guantao Formation，and the oil reservoirs discovered by single well are characterized by large thickness，long length oilbearingsections and concentrated distribution of oil layers. Finally，the oil and gas accumulation of the LD21 Oilfield in the plane and vertical is controlled by the coupling of three elements，which are strike-slip reversal，regional cap and lateral sealing of fault.
2018, 25(3):20-28.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.003
Abstract:
In order to understand the control of faults on hydrocarbon accumulation in the Neogene of the west of Bozhong Subsag，based on the detailed analysis of fault structure，distribution characteristics and transport mechanism，it was first proposed to quantitatively evaluate the vertical transmission capacity of the faults by using the fault-caprock parameter and fault-transporting ability index. The result indicates that the fault-caprock parameter and fault-transporting ability index can effectively quantitatively characterize the hydrocarbon charging capacity and hydrocarbon accumulation strata of different tectonic belts in CFD12-6 Oilfield. In the northern fault zone，the fault-caprock parameters are larger and the faulttransporting ability index is smaller，and thus the hydrocarbon charging capacity is relatively weak and the hydrocarbon is mainly accumulated in the Guantao Formation；while in the southern fault zone，the fault-caprock parameters are smaller and the fault-transporting ability index is much larger，and thus the hydrocarbon charging capacity is much stronger and the hydrocarbon is mainly accumulated in the Minghuazhen Formation. Based on the fault transmission capacity，the hydrocarbon accumulation models for the north-south fault zone in CFD12-6 Oilfield were established. The“HydrocarbonFault-Sand”lateral diversion reservoir model is for the northern fault zone；while the“Hydrocarbon-Unconformity-Fault”vertical penetrating reservoir model is mainly for the southern fault zone.
In order to understand the control of faults on hydrocarbon accumulation in the Neogene of the west of Bozhong Subsag，based on the detailed analysis of fault structure，distribution characteristics and transport mechanism，it was first proposed to quantitatively evaluate the vertical transmission capacity of the faults by using the fault-caprock parameter and fault-transporting ability index. The result indicates that the fault-caprock parameter and fault-transporting ability index can effectively quantitatively characterize the hydrocarbon charging capacity and hydrocarbon accumulation strata of different tectonic belts in CFD12-6 Oilfield. In the northern fault zone，the fault-caprock parameters are larger and the faulttransporting ability index is smaller，and thus the hydrocarbon charging capacity is relatively weak and the hydrocarbon is mainly accumulated in the Guantao Formation；while in the southern fault zone，the fault-caprock parameters are smaller and the fault-transporting ability index is much larger，and thus the hydrocarbon charging capacity is much stronger and the hydrocarbon is mainly accumulated in the Minghuazhen Formation. Based on the fault transmission capacity，the hydrocarbon accumulation models for the north-south fault zone in CFD12-6 Oilfield were established. The“HydrocarbonFault-Sand”lateral diversion reservoir model is for the northern fault zone；while the“Hydrocarbon-Unconformity-Fault”vertical penetrating reservoir model is mainly for the southern fault zone.
2018, 25(3):29-35.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.004
Abstract:
Bongor Basin，located in the south-west of the Republic of Chad，is a Mesozoic-Cenozoic passive rift basin evolved under the influence of shear zone of Central Africa Rift. Bongor Basin was in the beginning of a rift lacustrine basin development and always kept expansion through a continuous transgression progress during the sedimentation of the P Formation，during which terrestrial fan delta-lacustrine deposited. The results of core observation show that the P Formation are characterized by near-provenance，deep-water，coarse-grain，gravity-flow and consecutive transgression sediments.Combined with the indication of well-logging and seismic data，it is determined that fan delta，lacustrine and gravity flow develop in the study area. The fan delta consists of fan delta front and pre-fan delta sub-facies，and the fan delta front consists of submarine distributary channel，estuary bar，interdistributary and sand sheet. Taking the sub-sag in the north slope of Bongor Basin as an example，it is concluded that two main provenance systems exist through coupling analysis of structure and sedimentation，where delta deposits along the long axis. There are two structure-defined sedimentary modes built along the short axis：fan delta grows in the structure-controlled（fault-connected）zone，while gravity flow grows in the nonstructurecontrolled zone.
Bongor Basin，located in the south-west of the Republic of Chad，is a Mesozoic-Cenozoic passive rift basin evolved under the influence of shear zone of Central Africa Rift. Bongor Basin was in the beginning of a rift lacustrine basin development and always kept expansion through a continuous transgression progress during the sedimentation of the P Formation，during which terrestrial fan delta-lacustrine deposited. The results of core observation show that the P Formation are characterized by near-provenance，deep-water，coarse-grain，gravity-flow and consecutive transgression sediments.Combined with the indication of well-logging and seismic data，it is determined that fan delta，lacustrine and gravity flow develop in the study area. The fan delta consists of fan delta front and pre-fan delta sub-facies，and the fan delta front consists of submarine distributary channel，estuary bar，interdistributary and sand sheet. Taking the sub-sag in the north slope of Bongor Basin as an example，it is concluded that two main provenance systems exist through coupling analysis of structure and sedimentation，where delta deposits along the long axis. There are two structure-defined sedimentary modes built along the short axis：fan delta grows in the structure-controlled（fault-connected）zone，while gravity flow grows in the nonstructurecontrolled zone.
2018, 25(3):36-42.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.005
Abstract:
Using core，drilling，logging and seismic data，the development and sedimentary evolution of biolimestone at the lower Es1 in Changdi area of Zhanhua sag were researched. The Es1 in Changdi area is defined as a third-order sequence，and the biolimestone developed in the lower Es1 was divided into 3 fourth-order sequences. The lacustrine transgressive system tract and the lacustrine regressive system tract，where the biolimestone both developed，were also identified. The development of biolimestone is affected by paleo water depth and paleogeomorphology. There are 3 types of paleo water depth variation in the lower Es1，namely the water withdrawal，the high position water and the low position water. Through paleogeomorphology restoration，it is clear that the biolimestone in the lower Es1 is mainly distributed in the southeast and eastern slope trough. Based on the layers and its development characteristics，3 types of interior structure were categorized in the biolimestone，and then it is determined that there are two development modes in the study area，which are the biolimestone developed in gentle slope and the biolimestone developed in trough. Due to the periodic change of the lake level，the distribution of the biolimestone in the lower Es1 also changed correspondingly. The biolimestone is thicker around the uplift and thinner along the gentle slope direction，and its belt-like distribution is parallel to the periphery of the buried hill.
Using core，drilling，logging and seismic data，the development and sedimentary evolution of biolimestone at the lower Es1 in Changdi area of Zhanhua sag were researched. The Es1 in Changdi area is defined as a third-order sequence，and the biolimestone developed in the lower Es1 was divided into 3 fourth-order sequences. The lacustrine transgressive system tract and the lacustrine regressive system tract，where the biolimestone both developed，were also identified. The development of biolimestone is affected by paleo water depth and paleogeomorphology. There are 3 types of paleo water depth variation in the lower Es1，namely the water withdrawal，the high position water and the low position water. Through paleogeomorphology restoration，it is clear that the biolimestone in the lower Es1 is mainly distributed in the southeast and eastern slope trough. Based on the layers and its development characteristics，3 types of interior structure were categorized in the biolimestone，and then it is determined that there are two development modes in the study area，which are the biolimestone developed in gentle slope and the biolimestone developed in trough. Due to the periodic change of the lake level，the distribution of the biolimestone in the lower Es1 also changed correspondingly. The biolimestone is thicker around the uplift and thinner along the gentle slope direction，and its belt-like distribution is parallel to the periphery of the buried hill.
6 Reservoir architectural analysis of fan delta in the faulted block Guan195 of Wangguantun Oilfield
2018, 25(3):43-49.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.006
Abstract:
The fan deltas developed widely in several faulted basins in China. As a kind of important oil and gas reservoir，it is very necessary to make the internal architecture clear for prediction of the residual oil distribution in the late period of oilfield development. Therefore，taking the 5th Zao oil layer of Kongdian Formation in the faulted block Guan195 of Wangguantun Oilfield as an example，the reservoir architecture of fan delta front was characterized quantitatively based on core data，well logs and production data. The main reservoir architecture elements of fan delta front consists of distributary channel，estuary sandbar，sheet sand and inter channel. And then the division scheme was established for the division of reservoir architecture of fan delta front into different levels，and the markers was defined for the identification of distributary channel estuary sandbar and inner accretion body in estuary sandbar. Taking single sandbody as a unit，data，being acquired from field outcrop defined as fan delta in the Xiguayuan Formation of Luanping Basin，were matched to derive a formula for quantitative characterization of distributary channel and estuary sandbar，calculation of the dip of interbed inner estuary sandbar and prediction of the development of inner accretion body. The residual oil controlled by a single genetic sand body distributes at the top of the margin of sandbars and channels，and the distribution of residual oil controlled by the interlayer should be analyzed according to the specific rhythm of the sandbar.
The fan deltas developed widely in several faulted basins in China. As a kind of important oil and gas reservoir，it is very necessary to make the internal architecture clear for prediction of the residual oil distribution in the late period of oilfield development. Therefore，taking the 5th Zao oil layer of Kongdian Formation in the faulted block Guan195 of Wangguantun Oilfield as an example，the reservoir architecture of fan delta front was characterized quantitatively based on core data，well logs and production data. The main reservoir architecture elements of fan delta front consists of distributary channel，estuary sandbar，sheet sand and inter channel. And then the division scheme was established for the division of reservoir architecture of fan delta front into different levels，and the markers was defined for the identification of distributary channel estuary sandbar and inner accretion body in estuary sandbar. Taking single sandbody as a unit，data，being acquired from field outcrop defined as fan delta in the Xiguayuan Formation of Luanping Basin，were matched to derive a formula for quantitative characterization of distributary channel and estuary sandbar，calculation of the dip of interbed inner estuary sandbar and prediction of the development of inner accretion body. The residual oil controlled by a single genetic sand body distributes at the top of the margin of sandbars and channels，and the distribution of residual oil controlled by the interlayer should be analyzed according to the specific rhythm of the sandbar.
2018, 25(3):50-54.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.007
Abstract:
Overlying formation pressure，fault dip angle and shale content are the significant parameters for fault sealing capacity evaluation，and the reliability of evaluation results depends on the accuracy quantification of these 3 parameters. In the research of fault sealing of the central-southern Liaoxi Uplift，it is found that the actual overburden density increases with the increase of compaction. Overburden density function was obtained by density logging and depth regression，and then it was integrated to calculate the overburden pressure. The fault dip angle changes with lithology and stress，and it was calculated by 3D seismic interpretation results and spatial stereo method. The overall trend of mud content was determined according to the seismic data，and then it was corrected by well logging gamma value to obtain the more accurate shale content in fault zone. The 3 parameters of No.1 Liaoxi Fault and its branched faults in the research area uplift were calculated accurately，and then their products were used as the fault sealing indexes. Combined with the analysis of differences in oil and gas distribution，it is found that the sealing capacity of the northern section of the study area is the best，followed by the southern section，and the central part is the worst. The lower limit values of fault sealing index are related to the physical properties of oil and gas，and the lower limit values of natural gas，normal oil and heavy oil are 9.34，8.31 and 6.12，respectively.
Overlying formation pressure，fault dip angle and shale content are the significant parameters for fault sealing capacity evaluation，and the reliability of evaluation results depends on the accuracy quantification of these 3 parameters. In the research of fault sealing of the central-southern Liaoxi Uplift，it is found that the actual overburden density increases with the increase of compaction. Overburden density function was obtained by density logging and depth regression，and then it was integrated to calculate the overburden pressure. The fault dip angle changes with lithology and stress，and it was calculated by 3D seismic interpretation results and spatial stereo method. The overall trend of mud content was determined according to the seismic data，and then it was corrected by well logging gamma value to obtain the more accurate shale content in fault zone. The 3 parameters of No.1 Liaoxi Fault and its branched faults in the research area uplift were calculated accurately，and then their products were used as the fault sealing indexes. Combined with the analysis of differences in oil and gas distribution，it is found that the sealing capacity of the northern section of the study area is the best，followed by the southern section，and the central part is the worst. The lower limit values of fault sealing index are related to the physical properties of oil and gas，and the lower limit values of natural gas，normal oil and heavy oil are 9.34，8.31 and 6.12，respectively.
2018, 25(3):55-60.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.008
Abstract:
Coal microfacies are closely related to the gas-bearing properties of coal reservoirs，which determines the sedimentary environment and sedimentary source of coal and directly affects the potential of coalbed methane generation and the occurrence environment. The control effect of coal microfacies on coal reservoir gas-bearing properties was analyzed comprehensively from three aspects：coal seam thickness，coal reservoir physical property and ash yield. The coal microfacies was quantitatively divided to predict the gas production prospect of coal reservoir based on the logging data. In the study area，there are 5 kinds of coal microfacies in 3# coal seam，such as moist forest detained swamp facies，dry forest swamp facies，water-overlying forest living swamp facies，wet herbaceous living marsh facies and dry herbaceous marsh facies. The effective coal reservoir is thicker in moist forest detained swamp facies，dry forest swamp facies and water-covering forest living swamp facies. The physical property of water-overlying forest living swamp facies is relatively good. There are a little ash and gangue in moist forest detained swamp facies and wet herbaceous living marsh facies. The potential of gas generation in moist forest detained swamp facies is great，it is moderate in dry forest swamp facies，water-covering forest living swamp facies and wet herbaceous living marsh facies，and it is poor in dry herbaceous marsh facies. Density，natural gamma and natural potential logging curves can be used effectively to divide the effective thickness of coal seam，the thickness of gangue and characteristic parameters such as ash content，which can be matched to the corresponding coal microfacies according to the statistical law so as to effectively evaluate the gas-bearing property of coal reservoirs.
Coal microfacies are closely related to the gas-bearing properties of coal reservoirs，which determines the sedimentary environment and sedimentary source of coal and directly affects the potential of coalbed methane generation and the occurrence environment. The control effect of coal microfacies on coal reservoir gas-bearing properties was analyzed comprehensively from three aspects：coal seam thickness，coal reservoir physical property and ash yield. The coal microfacies was quantitatively divided to predict the gas production prospect of coal reservoir based on the logging data. In the study area，there are 5 kinds of coal microfacies in 3# coal seam，such as moist forest detained swamp facies，dry forest swamp facies，water-overlying forest living swamp facies，wet herbaceous living marsh facies and dry herbaceous marsh facies. The effective coal reservoir is thicker in moist forest detained swamp facies，dry forest swamp facies and water-covering forest living swamp facies. The physical property of water-overlying forest living swamp facies is relatively good. There are a little ash and gangue in moist forest detained swamp facies and wet herbaceous living marsh facies. The potential of gas generation in moist forest detained swamp facies is great，it is moderate in dry forest swamp facies，water-covering forest living swamp facies and wet herbaceous living marsh facies，and it is poor in dry herbaceous marsh facies. Density，natural gamma and natural potential logging curves can be used effectively to divide the effective thickness of coal seam，the thickness of gangue and characteristic parameters such as ash content，which can be matched to the corresponding coal microfacies according to the statistical law so as to effectively evaluate the gas-bearing property of coal reservoirs.
2018, 25(3):61-67.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.009
Abstract:
The characteristics of low porosity，low permeability and strong heterogeneity in tight sandstone reservoirs make the pore structure of rocks complicated. Intensive study on pore structure parameters is of great significance to improve oil and gas recovery and reservoir development for the low permeability reservoirs. The rock thin section analysis is the most basic way to analyze the pore structure. The method is a manual approach，which has the shortage of large random error and time-consuming. In order to fully exploit the abundant information of the pore structure in the rock thin section，six samples from Chang9 oil layer in Jiyuan Oilfield were selected to obtain pore structure parameters based on the pore extracted from binarization image with high SNR of pore-skeleton. Through the Bayesian classification method based on the RGB color space model，the parameters such as pore，pore shape factors and porosity were obtained through statistical methods. The calculated porosity by method of image analysis based on Bayesian classification is in linear agreement with the measured porosity and permeability. At the same time，we can concluded that there is a high correlation coefficient（above 0.8）between the pore structure parameters obtained by the method above and the mercury penetration. The calculated results show that this method could obtain more accurate pore structure parameters，which improves the efficiency of rock image analysis. This method provides an effective approach for the characterization of the pore structure in the tight sandstone reservoir.
The characteristics of low porosity，low permeability and strong heterogeneity in tight sandstone reservoirs make the pore structure of rocks complicated. Intensive study on pore structure parameters is of great significance to improve oil and gas recovery and reservoir development for the low permeability reservoirs. The rock thin section analysis is the most basic way to analyze the pore structure. The method is a manual approach，which has the shortage of large random error and time-consuming. In order to fully exploit the abundant information of the pore structure in the rock thin section，six samples from Chang9 oil layer in Jiyuan Oilfield were selected to obtain pore structure parameters based on the pore extracted from binarization image with high SNR of pore-skeleton. Through the Bayesian classification method based on the RGB color space model，the parameters such as pore，pore shape factors and porosity were obtained through statistical methods. The calculated porosity by method of image analysis based on Bayesian classification is in linear agreement with the measured porosity and permeability. At the same time，we can concluded that there is a high correlation coefficient（above 0.8）between the pore structure parameters obtained by the method above and the mercury penetration. The calculated results show that this method could obtain more accurate pore structure parameters，which improves the efficiency of rock image analysis. This method provides an effective approach for the characterization of the pore structure in the tight sandstone reservoir.
2018, 25(3):68-76.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.010
Abstract:
The Lower Cambrian is the main target intervals of marine shale gas exploration and exploitation in China. Shale gas content varies greatly in different intervals and how to determine favorable targets is an important problem to be solved urgently. Taking Well XN-1 in Xiuwu Basin as an example，according to core description，logging data analysis，mineral and elemental composition analysis and total organic carbon（TOC）content tests，the shale in Lower Cambrian Wangyinpu Formation and Guanyintang Formation was studied. Results show that water redox conditions and bioproductivity control the enrichment of sedimentary organic matter. Hydrothermal activities are helpful for the increase of reducibility of seawater and enhancing bioproductivity，and thus controls the enrichment of sedimentary organic matter and the enrichment of shale gas is further affected. The water reducibility during the deposition of SQ1 at early Cambrian varies greatly，and it is generally strong during the deposition of SQ2 and SQ3 of the Wangyinpu Formation. The reducibility of all the three sequences is stronger than that during the deposition of SQ4 and SQ5. The bioproductivity during the deposition of SQ3 is the highest and little difference in the bioproductivity has been found between SQ1 and SQ2，both of which show higher values than that of SQ4 and SQ5. Siliceous origin of SQ1 varies greatly in the study area；most siliceous minerals of SQ2 and SQ3 are hydrothermal origin，whose content is high；content of hydrothermal origin siliceous minerals drops in SQ4 and terrigeneous siliceous content increases；siliceous minerals of SQ5 originate from normal terrigeneous clastic deposition. SQ2 and SQ3 are favorable targets of shale gas in the Lower Cambrian.
The Lower Cambrian is the main target intervals of marine shale gas exploration and exploitation in China. Shale gas content varies greatly in different intervals and how to determine favorable targets is an important problem to be solved urgently. Taking Well XN-1 in Xiuwu Basin as an example，according to core description，logging data analysis，mineral and elemental composition analysis and total organic carbon（TOC）content tests，the shale in Lower Cambrian Wangyinpu Formation and Guanyintang Formation was studied. Results show that water redox conditions and bioproductivity control the enrichment of sedimentary organic matter. Hydrothermal activities are helpful for the increase of reducibility of seawater and enhancing bioproductivity，and thus controls the enrichment of sedimentary organic matter and the enrichment of shale gas is further affected. The water reducibility during the deposition of SQ1 at early Cambrian varies greatly，and it is generally strong during the deposition of SQ2 and SQ3 of the Wangyinpu Formation. The reducibility of all the three sequences is stronger than that during the deposition of SQ4 and SQ5. The bioproductivity during the deposition of SQ3 is the highest and little difference in the bioproductivity has been found between SQ1 and SQ2，both of which show higher values than that of SQ4 and SQ5. Siliceous origin of SQ1 varies greatly in the study area；most siliceous minerals of SQ2 and SQ3 are hydrothermal origin，whose content is high；content of hydrothermal origin siliceous minerals drops in SQ4 and terrigeneous siliceous content increases；siliceous minerals of SQ5 originate from normal terrigeneous clastic deposition. SQ2 and SQ3 are favorable targets of shale gas in the Lower Cambrian.
2018, 25(3):77-81.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.011
Abstract:
For the development of heavy oil reservoirs，the recovery principle and method of steam injection in dual-horizontal well for the heavy oil reservoirs proposed by BUTLER in 1991 has been paid more attention by the experts and scholars at home and abroad. However，the definition of SAGD is inappropriate，because the gravity drainage contributes less than the injection pressure during the process of SAGD. Therefore，the definition of GASD（Gravity-Assisted Steam Drive） was proposed. In the process of BUTLER’s derivation of the productivity formula，steady flow of the Darcy’s law has been mistaken as differential flow and several wrong solutions existed during the formula derivation，which results in the inaccuracy of SAGD productivity calculation formula. Based on the model of movable oil formed by steam chamber proposed by BULTER，the tilted linear flow formula of Darcy’s law was used to obtain the GASD productivity calculation formula for dual-horizontal wells. At the same time，important results were achieved and show that the GASD productivity is in direct proportion to the sinθ and is in inverse proportion to the vertical distance between the dual horizontal wells.
For the development of heavy oil reservoirs，the recovery principle and method of steam injection in dual-horizontal well for the heavy oil reservoirs proposed by BUTLER in 1991 has been paid more attention by the experts and scholars at home and abroad. However，the definition of SAGD is inappropriate，because the gravity drainage contributes less than the injection pressure during the process of SAGD. Therefore，the definition of GASD（Gravity-Assisted Steam Drive） was proposed. In the process of BUTLER’s derivation of the productivity formula，steady flow of the Darcy’s law has been mistaken as differential flow and several wrong solutions existed during the formula derivation，which results in the inaccuracy of SAGD productivity calculation formula. Based on the model of movable oil formed by steam chamber proposed by BULTER，the tilted linear flow formula of Darcy’s law was used to obtain the GASD productivity calculation formula for dual-horizontal wells. At the same time，important results were achieved and show that the GASD productivity is in direct proportion to the sinθ and is in inverse proportion to the vertical distance between the dual horizontal wells.
ZHANG Yunbao
,
LU Xiangguo
,
WANG Tingting
,
LIU Yigang
,
XIA Huan
,
CHEN Yang
,
PAN He
,
LIU Jinxiang
2018, 25(3):82-88.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.012
Abstract:
In order to solve the problem of injected fluid channeling caused by large-size advantage channels in offshore oilfield，the basic performance evaluation，plugging rate，multi-stage plugging and increasing oil and decreasing water effect of three plugging agent was studied through experiment and mechanism analysis taking reservoirs and fluid of Bohai Oilfield as the research object. The results show that the plugging agent BH-1 is a viscous fluid before solidification and has good injectivity. After curing it is a kind of gray-black dense solid，whose curing time ranges from 24 h to 120 h. It has high solid compressive strength and abrasion resistance，which is suitable for plugging large-size advantage channels near wellbore area. Before gelling，the gel with semi-interpenetrating network structure is a kind of viscous fluid with favorable injectivity. After waiting on cementing for 24 h in the pores of core，the mixture began to appear obvious cross-linking reaction and became to form the“mesh”molecular aggregates after 120 h，and the colloid has the characteristics of high compressive and erosion resistance，whcih is suitable for the plugging of large-size advantage channels in the deep reservoirs.After all the high-permeability core holes were plugged，the Cr3+ polymer gel flooding can improve the swept effect of matrix in low and high permeability cores，and the oil recovery was increased by 29.4%，while the oil recovery was only 13.1% when the plugging distance is 50% of the total plugging distance. Therefore，the plugging distance of the large-size advantage channels in Bohai heavy oil reservoirs should be more than 50% of the injector-producer distance. From the technical and economic point of view，the plugging agent consists of multi-stage combination of slugs，and the injection order is：Cr3+ polymer gel（about 50%），the gel with semi-interpenetrating network structure（about 35%），plugging agent（about 15%）.
In order to solve the problem of injected fluid channeling caused by large-size advantage channels in offshore oilfield，the basic performance evaluation，plugging rate，multi-stage plugging and increasing oil and decreasing water effect of three plugging agent was studied through experiment and mechanism analysis taking reservoirs and fluid of Bohai Oilfield as the research object. The results show that the plugging agent BH-1 is a viscous fluid before solidification and has good injectivity. After curing it is a kind of gray-black dense solid，whose curing time ranges from 24 h to 120 h. It has high solid compressive strength and abrasion resistance，which is suitable for plugging large-size advantage channels near wellbore area. Before gelling，the gel with semi-interpenetrating network structure is a kind of viscous fluid with favorable injectivity. After waiting on cementing for 24 h in the pores of core，the mixture began to appear obvious cross-linking reaction and became to form the“mesh”molecular aggregates after 120 h，and the colloid has the characteristics of high compressive and erosion resistance，whcih is suitable for the plugging of large-size advantage channels in the deep reservoirs.After all the high-permeability core holes were plugged，the Cr3+ polymer gel flooding can improve the swept effect of matrix in low and high permeability cores，and the oil recovery was increased by 29.4%，while the oil recovery was only 13.1% when the plugging distance is 50% of the total plugging distance. Therefore，the plugging distance of the large-size advantage channels in Bohai heavy oil reservoirs should be more than 50% of the injector-producer distance. From the technical and economic point of view，the plugging agent consists of multi-stage combination of slugs，and the injection order is：Cr3+ polymer gel（about 50%），the gel with semi-interpenetrating network structure（about 35%），plugging agent（about 15%）.
2018, 25(3):89-94.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.013
Abstract:
The tight sandstone matrix is characterized by development of micro-nano pore throats and strong capillary forces. Fracturing fluids can interact with reservoir rocks and cause formation damage resulting in decrease of productivity in oil reservoir. However，considerable previous studies are focused on the damage of the fracturing fluids on the fractures of formations without taking the effect of matrix damage on productivity into consideration. The damage rule of the fracturing fluid on Keshen tight sandstone and the shale matrix of Xujiahe Formation and Lujiaping Formation was studied systematically using a transient pressure pulse instrument that was developed according to the matrix permeability model based on the principle of transient pressure pulse method. Compared with the conventional damage evaluation method measuring the outlet flow of core，the transient pressure pulse method only records the variation of downstream pressure with time during the fluid flowing through the cores，which can evaluate core permeability and damage degree and overcome the problems of large experiment error and long flow monitoring caused by extreme low permeability of the low-permeability cores.
The tight sandstone matrix is characterized by development of micro-nano pore throats and strong capillary forces. Fracturing fluids can interact with reservoir rocks and cause formation damage resulting in decrease of productivity in oil reservoir. However，considerable previous studies are focused on the damage of the fracturing fluids on the fractures of formations without taking the effect of matrix damage on productivity into consideration. The damage rule of the fracturing fluid on Keshen tight sandstone and the shale matrix of Xujiahe Formation and Lujiaping Formation was studied systematically using a transient pressure pulse instrument that was developed according to the matrix permeability model based on the principle of transient pressure pulse method. Compared with the conventional damage evaluation method measuring the outlet flow of core，the transient pressure pulse method only records the variation of downstream pressure with time during the fluid flowing through the cores，which can evaluate core permeability and damage degree and overcome the problems of large experiment error and long flow monitoring caused by extreme low permeability of the low-permeability cores.
2018, 25(3):95-100.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.014
Abstract:
Influenced by selective dissolution and fracture development degree，fault-karst reservoirs in Tahe Oilfield have the characteristics of extremely complex inner structure and obvious fracture-vug separation，which results in difficulty in understanding of water flood development. Based on the relationship between storage and flow in the oil reservoirs and five typical types of fault-karst，numerical simulation was carried out to study water drive law and remaining oil distribution characteristic of the five typical types of fault-karst from the aspects of injection velocity，injection-production position and fracture participation based on fluid dynamics. The results show that the displacement efficiency of the type“Y”faultkarst and the compound type fault-karst increases continuously when the injection velocity increases and the injection-production position changes from low to high. However，the displacement efficiency of type“V”fault-karst，type“T”faultkarst and belt-shaped fault-karst are hardly influenced by the above factors. The existence of fractures makes the displacement efficiency of the fracture-karst decrease. The distribution of remaining oil depends on the injection-production position and the connectivity mode of the fracture-karst. The remaining oil mainly distributes in bypass fault-karst of non-dominant channel，small arch and the bottom of fault-karst.
Influenced by selective dissolution and fracture development degree，fault-karst reservoirs in Tahe Oilfield have the characteristics of extremely complex inner structure and obvious fracture-vug separation，which results in difficulty in understanding of water flood development. Based on the relationship between storage and flow in the oil reservoirs and five typical types of fault-karst，numerical simulation was carried out to study water drive law and remaining oil distribution characteristic of the five typical types of fault-karst from the aspects of injection velocity，injection-production position and fracture participation based on fluid dynamics. The results show that the displacement efficiency of the type“Y”faultkarst and the compound type fault-karst increases continuously when the injection velocity increases and the injection-production position changes from low to high. However，the displacement efficiency of type“V”fault-karst，type“T”faultkarst and belt-shaped fault-karst are hardly influenced by the above factors. The existence of fractures makes the displacement efficiency of the fracture-karst decrease. The distribution of remaining oil depends on the injection-production position and the connectivity mode of the fracture-karst. The remaining oil mainly distributes in bypass fault-karst of non-dominant channel，small arch and the bottom of fault-karst.
2018, 25(3):101-106.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.015
Abstract:
At present，most relative permeability curves are achieved at room temperature with inadequate representativeness. In order to know the flow mechanism during water flooding in the shallow super heavy oil reservoir，core displacement experiment was carried out to study the relative permeability curves of the water flooding in the shallow super heavy oil and threshold pressure gradient at different temperatures. The results show that the temperature has great influence on the threshold pressure gradient. The oil phase permeability curve and the water phase permeability curve are very different，and the oil phase descends rapidly and the water phase ascends slowly. With the increase of temperature，oil-water two phase relative permeability increases and the isotonic point moves to the right，and the relative permeability at the isotonic point increases gradually；the irreducible water saturation increases，and the residual oil saturation decreases. The oil displacement efficiency by steam flooding at the temperature of 140 and 180 ℃ is higher than that by water flooding，which are 10.6% and 11.9%，respectively. To a certain extent，it shows that the hot water flooding can increase the development efficiency of the super heavy oil reservoir.
At present，most relative permeability curves are achieved at room temperature with inadequate representativeness. In order to know the flow mechanism during water flooding in the shallow super heavy oil reservoir，core displacement experiment was carried out to study the relative permeability curves of the water flooding in the shallow super heavy oil and threshold pressure gradient at different temperatures. The results show that the temperature has great influence on the threshold pressure gradient. The oil phase permeability curve and the water phase permeability curve are very different，and the oil phase descends rapidly and the water phase ascends slowly. With the increase of temperature，oil-water two phase relative permeability increases and the isotonic point moves to the right，and the relative permeability at the isotonic point increases gradually；the irreducible water saturation increases，and the residual oil saturation decreases. The oil displacement efficiency by steam flooding at the temperature of 140 and 180 ℃ is higher than that by water flooding，which are 10.6% and 11.9%，respectively. To a certain extent，it shows that the hot water flooding can increase the development efficiency of the super heavy oil reservoir.
2018, 25(3):107-111.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.016
Abstract:
In order to reveal the influencing mechanism of asphaltene precipitation on oil recovery during CO2 flooding in the tight sandstone reservoirs，three kinds of crude oil samples with different asphaltene contents and low-permeability artificial cores（epoxy resin cemented quartz sand）were selected for flooding tests. The flooding tests were carried out by stimulating actual formation temperature and pressure. The effect of asphaltene precipitation on the oil recovery of different scales of pore throat was analyzed by nuclear magnetic resonance（NMR）technique. The results show that the amount of asphaltene precipitation is proportionate to asphaltene contents of the crude oil during flooding. It also increases with the increasing CO2 injection volume. At the same time，the oil recovery will be affected by asphaltene，which decreases with the increasing precipitation amount. The results of NMR test show that the asphaltene precipitation had little effect on the oil recovery of the larger pore-throats（2.0-200.0 ms）. However，the asphaltene precipitation produced a certain degree of clogging in the smaller pore-throats（0.1-2.0 ms），resulting in the remaining oil being difficult to be recovered and ultimately affecting the overall recovery.
In order to reveal the influencing mechanism of asphaltene precipitation on oil recovery during CO2 flooding in the tight sandstone reservoirs，three kinds of crude oil samples with different asphaltene contents and low-permeability artificial cores（epoxy resin cemented quartz sand）were selected for flooding tests. The flooding tests were carried out by stimulating actual formation temperature and pressure. The effect of asphaltene precipitation on the oil recovery of different scales of pore throat was analyzed by nuclear magnetic resonance（NMR）technique. The results show that the amount of asphaltene precipitation is proportionate to asphaltene contents of the crude oil during flooding. It also increases with the increasing CO2 injection volume. At the same time，the oil recovery will be affected by asphaltene，which decreases with the increasing precipitation amount. The results of NMR test show that the asphaltene precipitation had little effect on the oil recovery of the larger pore-throats（2.0-200.0 ms）. However，the asphaltene precipitation produced a certain degree of clogging in the smaller pore-throats（0.1-2.0 ms），resulting in the remaining oil being difficult to be recovered and ultimately affecting the overall recovery.
2018, 25(3):112-116.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.017
Abstract:
In order to evaluate the potential of different thermal-recovery technologies for heavy oil in SINOPEC，two EOR technologies，cyclic steam stimulation with infill wells and steam flooding，were studied. The methods of financial net present value，reservoir numerical simulation and cost analysis were used to draw the charts of single-well oil economic limit production of the cyclic steam stimulation and economic limit of oil-steam ratio for the steam flooding. And then the evaluation standards of the potential of cyclic steam stimulation with infill wells aimed at two kinds of buried depths and two kinds of well types were set up and the evaluation standards of the potential of steam flooding was revised. Finally，the potential was evaluated by taking W Oilfield of SINOPEC as an example. The results show that at a certain burial depth，single-well oil economic limit production of the cyclic steam stimulation increases exponentially as the oil price decreases for the vertical and the horizontal well. At the oil price of US＄60/bbl，the economic limit of oil-steam ratio for the steam flooding in the heavy oil reservoirs of SINOPEC is 0.096 t/t. The cyclic steam stimulation with infill wells and the steam flooding directly after cyclic steam stimulation can increase 32.4×104 and 71.1×104 tons of recoverable reserves respectively，and the total potential of W Oilfield is 103.5×104 t. At the oil price of US＄80/bbl，the total potential is 426.5×104 t for the W Oilfield. At the same time，it is suggested that the potential of steam flooding for the horizontal well should be evaluated as the potential of technological breakthrough.
In order to evaluate the potential of different thermal-recovery technologies for heavy oil in SINOPEC，two EOR technologies，cyclic steam stimulation with infill wells and steam flooding，were studied. The methods of financial net present value，reservoir numerical simulation and cost analysis were used to draw the charts of single-well oil economic limit production of the cyclic steam stimulation and economic limit of oil-steam ratio for the steam flooding. And then the evaluation standards of the potential of cyclic steam stimulation with infill wells aimed at two kinds of buried depths and two kinds of well types were set up and the evaluation standards of the potential of steam flooding was revised. Finally，the potential was evaluated by taking W Oilfield of SINOPEC as an example. The results show that at a certain burial depth，single-well oil economic limit production of the cyclic steam stimulation increases exponentially as the oil price decreases for the vertical and the horizontal well. At the oil price of US＄60/bbl，the economic limit of oil-steam ratio for the steam flooding in the heavy oil reservoirs of SINOPEC is 0.096 t/t. The cyclic steam stimulation with infill wells and the steam flooding directly after cyclic steam stimulation can increase 32.4×104 and 71.1×104 tons of recoverable reserves respectively，and the total potential of W Oilfield is 103.5×104 t. At the oil price of US＄80/bbl，the total potential is 426.5×104 t for the W Oilfield. At the same time，it is suggested that the potential of steam flooding for the horizontal well should be evaluated as the potential of technological breakthrough.
2018, 25(3):117-121.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.018
Abstract:
Steam injection is one of the most effective methods to develop heavy oil reservoirs. Steam overlap is a common phenomenon because of the density difference between steam and crude oil. The steam overlap characteristics of the heavy oil reservoir were intuitively described by 3D physical simulation experiments. The pressure，temperature field and fluid production under different perforation modes were analyzed during the steam flooding. The experimental results reveal that the main steam sweep area is at the top of the reservoir when the injection well is uniformly perforated. As the injection time increases，the central reservoir begins to absorb steam gradually and the remaining oil mainly gathers at the bottom of the reservoir. When the injection well is selectively perforated，the temperature difference between the top and bottom reservoir decreases and the steam absorption of the bottom zone increases obviously. As a result，the producing degree and oil recovery are enhanced. On this basis，the numerical simulation method was used to optimize the selective perforation plan for the injection and production wells. The results show that the selective perforation can effectively control the steam overlap.It is optimal that 1/3 of the lower reservoirs and 1/2 to 2/3 of the lower reservoirs are perforated for the injection wells and production wells respectively.
Steam injection is one of the most effective methods to develop heavy oil reservoirs. Steam overlap is a common phenomenon because of the density difference between steam and crude oil. The steam overlap characteristics of the heavy oil reservoir were intuitively described by 3D physical simulation experiments. The pressure，temperature field and fluid production under different perforation modes were analyzed during the steam flooding. The experimental results reveal that the main steam sweep area is at the top of the reservoir when the injection well is uniformly perforated. As the injection time increases，the central reservoir begins to absorb steam gradually and the remaining oil mainly gathers at the bottom of the reservoir. When the injection well is selectively perforated，the temperature difference between the top and bottom reservoir decreases and the steam absorption of the bottom zone increases obviously. As a result，the producing degree and oil recovery are enhanced. On this basis，the numerical simulation method was used to optimize the selective perforation plan for the injection and production wells. The results show that the selective perforation can effectively control the steam overlap.It is optimal that 1/3 of the lower reservoirs and 1/2 to 2/3 of the lower reservoirs are perforated for the injection wells and production wells respectively.
2018, 25(3):122-126.
DOI: 10.13673/j.cnki.cn37-1359/te.2018.03.019
Abstract:
Earlier experimental study on late water flooding are mainly focused on water flooding timing and seldom on injection-production pattern. There was error for gas and liquid separation and human reading on the outlet by traditional methods of oil displacement efficiency. An oil field abroad was taken as the research object. The influence of water flooding timing and injection-production pattern on late water flooding effect was researched on conventional oil phase behavior and oil displacement efficiency during late water flooding. Based on the study of conventional phase behavior，the influence of water injection pressurization on the phase behavior was evaluated. In the experiment method of oil displacement efficiency，the on-line NMR technique was used to evaluate the oil saturation of core in the displacement process in real time and then the accuracy of the result was improved. The results show that the water flooding recovery reached to 16.5% when water flooding was performed at 34% of saturation pressure during the depletion development. Considering the production rate，development costs and other factors，water injection was superior when the bubble point pressure was around 80%. For the long-term depletion development of severe degassing blocks，the development way of water injection pressurization can be taken. The water flooding effect was the best when the bubble point pressure increased to around 80% by water injection pressurization.
Earlier experimental study on late water flooding are mainly focused on water flooding timing and seldom on injection-production pattern. There was error for gas and liquid separation and human reading on the outlet by traditional methods of oil displacement efficiency. An oil field abroad was taken as the research object. The influence of water flooding timing and injection-production pattern on late water flooding effect was researched on conventional oil phase behavior and oil displacement efficiency during late water flooding. Based on the study of conventional phase behavior，the influence of water injection pressurization on the phase behavior was evaluated. In the experiment method of oil displacement efficiency，the on-line NMR technique was used to evaluate the oil saturation of core in the displacement process in real time and then the accuracy of the result was improved. The results show that the water flooding recovery reached to 16.5% when water flooding was performed at 34% of saturation pressure during the depletion development. Considering the production rate，development costs and other factors，water injection was superior when the bubble point pressure was around 80%. For the long-term depletion development of severe degassing blocks，the development way of water injection pressurization can be taken. The water flooding effect was the best when the bubble point pressure increased to around 80% by water injection pressurization.
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