Volume 27,Issue 4,2020 Table of Contents
ZHANG Kuihua
,
CAO Zhongxiang
,
WANG Yue
,
ZHANG Guanlong
,
XUE Yan
,
WANG Shengzhu
,
QU Yansheng
,
WANG Yuxin
2020, 27(4):1-12.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.001
Abstract:
The Lucaogou Formation in Bogda area is an important hydrocarbon source rock in the southern margin of Junggar Basin. The early study of sedimentary characteristics often focused on the mud shale on the north side of Bogda mountain or the glutenite on the south side of Chaiwopu Sag. However，the studies on the integrity of Bogda area are insufficient.Based on the detail observation and measurement of Lucaogou Formation at the typical outcrop around Bogda mountain，combined with the well logging and core data in Chaiwopu Sag，the stratigraphic characteristics，types and distribution features of sedimentary facies in this area were analyzed in detail，and the sedimentary evolution process was defined. The results show that Lucaogou Formation in Bogda area can be divided into the first member，the second member，the third member and the fourth member from bottom to top，in which the main sedimentary facies of the nearshore subaqueous fan，turbidite fan，semi-deep lake and deep lake are developed. During the sedimentation of the first and the second member of Lucaogou Formation，the nearshore subaqueous fan was widely distributed in Chaiwopu Sag，the turbidite fan and the semi-deep lake were mainly distributed to the north of present Bogda mountain. During the sedimentation of the third and the fourth member of Lucaogou Formation，the scale of the nearshore subaqueous fan and the turbidite fan decreased as the relative lake level rose，and the semi-deep lake and deep lake facies were widely distributed in the studying area，resulting in the development of large-scale high quality source rocks.
The Lucaogou Formation in Bogda area is an important hydrocarbon source rock in the southern margin of Junggar Basin. The early study of sedimentary characteristics often focused on the mud shale on the north side of Bogda mountain or the glutenite on the south side of Chaiwopu Sag. However，the studies on the integrity of Bogda area are insufficient.Based on the detail observation and measurement of Lucaogou Formation at the typical outcrop around Bogda mountain，combined with the well logging and core data in Chaiwopu Sag，the stratigraphic characteristics，types and distribution features of sedimentary facies in this area were analyzed in detail，and the sedimentary evolution process was defined. The results show that Lucaogou Formation in Bogda area can be divided into the first member，the second member，the third member and the fourth member from bottom to top，in which the main sedimentary facies of the nearshore subaqueous fan，turbidite fan，semi-deep lake and deep lake are developed. During the sedimentation of the first and the second member of Lucaogou Formation，the nearshore subaqueous fan was widely distributed in Chaiwopu Sag，the turbidite fan and the semi-deep lake were mainly distributed to the north of present Bogda mountain. During the sedimentation of the third and the fourth member of Lucaogou Formation，the scale of the nearshore subaqueous fan and the turbidite fan decreased as the relative lake level rose，and the semi-deep lake and deep lake facies were widely distributed in the studying area，resulting in the development of large-scale high quality source rocks.
WANG Shengzhu
,
WANG Qianjun
,
ZHANG Guanlong
,
BAI Zhongcai
,
XIONG Zhengrong
,
MEI Wenke
,
ZHAO Leqiang
2020, 27(4):13-25.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.002
Abstract:
The Carboniferous strata is important for hydrocarbon exploration in Junggar Basin，and its hydrocarbon accumulation is mainly controlled by source rocks. Identifying geochemical characteristics of the Carboniferous source rocks is significant to determine the effective source rocks in detail and to guide hydrocarbon exploration. The outcrop and drilling samples of source rock were systematically collected and the analysis methods were used including organic carbon content，rock pyrolysis，chromatography-mass spectrometry saturated hydrocarbon，single hydrocarbon carbon isotope，and experiment of hydrocarbon generation thermal simulation in gold tube-autoclave to study the geochemical characteristics and hydrocarbon generation capacity of source rocks. The results show that there are five types of source rock development modes of the Carboniferous strata in Junggar basin resulted from five types of sedimentary settings，namely residual ocean（sea），back-arc basin，intra-arc basin，marine rift，and continental rift basins. The source rocks in different sedimentary environments show different geochemical characteristics，and can be divided into 5 types，including Well Wucan1 type source rock，Dishuiquan type source rock，Wucaicheng type source rock，Zaheba type source rock，and Dixi8 well type source rock.The hydrocarbon generation capacity of source rocks developed in different sedimentary environments have huge difference.Among them，the source rocks in back-arc basin and intra-arc basin show strong hydrocarbon generation capacity and are high-quality source rocks，and the generated hydrocarbon is an important exploration target.
The Carboniferous strata is important for hydrocarbon exploration in Junggar Basin，and its hydrocarbon accumulation is mainly controlled by source rocks. Identifying geochemical characteristics of the Carboniferous source rocks is significant to determine the effective source rocks in detail and to guide hydrocarbon exploration. The outcrop and drilling samples of source rock were systematically collected and the analysis methods were used including organic carbon content，rock pyrolysis，chromatography-mass spectrometry saturated hydrocarbon，single hydrocarbon carbon isotope，and experiment of hydrocarbon generation thermal simulation in gold tube-autoclave to study the geochemical characteristics and hydrocarbon generation capacity of source rocks. The results show that there are five types of source rock development modes of the Carboniferous strata in Junggar basin resulted from five types of sedimentary settings，namely residual ocean（sea），back-arc basin，intra-arc basin，marine rift，and continental rift basins. The source rocks in different sedimentary environments show different geochemical characteristics，and can be divided into 5 types，including Well Wucan1 type source rock，Dishuiquan type source rock，Wucaicheng type source rock，Zaheba type source rock，and Dixi8 well type source rock.The hydrocarbon generation capacity of source rocks developed in different sedimentary environments have huge difference.Among them，the source rocks in back-arc basin and intra-arc basin show strong hydrocarbon generation capacity and are high-quality source rocks，and the generated hydrocarbon is an important exploration target.
2020, 27(4):26-31.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.003
Abstract:
The western wing of Chepaizi Uplift is next to Sikeshu Sag. In the early stage，it was believed that the hydrocarbon in light oil reservoirs in this area were mainly from the Jurassic source rocks. Through comprehensive analysis of the geochemical indicators，such as the biomarker compounds，carbon isotope，maturity of the crude oil discovered in multiple strata and the main source rocks in Sikeshu Sag，it was discovered that the light oil in the study area could be divided into two types，the source of light oil was clarified and the comprehensive criterion for identifying the crude oil was established.The results show that TypeⅠcrude oil mainly distributes in C，J，K，E formation，which has the characteristics of regular sterane C27-C29 in shape of“inverted L”，low levels of γ-cerane，high Pr/Ph，weight carbon isotope and relatively high maturity，and its parent material was formed in the environment of weak oxidization-weak reduction freshwater lake，and the source of organic matter was mainly higher plants，and TypeⅠcrude oil was mainly from the source rock of J1b Formation in Sikeshu Sag. While TypeⅡcrude oil mainly distributes in the N1s with regular sterane C27–C29 in shape of“V”，high levels of γ-cerane，smaller Pr/Ph，lighter carbon isotope and relatively low maturity of crude oil，and its parent material was formed in the environment of strongly reduced brackish water deep lacustrine，and the source of organic matter was mainly planktonic algae，and TypeⅡcrude oil was mainly from the source rock of the Paleogene E2-3a Formation. The research results further confirm that two sets of effective source rocks，Jurassic and paleogene，have been developed in Sikeshu Sag，and the oil and gas generated by them have been transported for a long distance.
The western wing of Chepaizi Uplift is next to Sikeshu Sag. In the early stage，it was believed that the hydrocarbon in light oil reservoirs in this area were mainly from the Jurassic source rocks. Through comprehensive analysis of the geochemical indicators，such as the biomarker compounds，carbon isotope，maturity of the crude oil discovered in multiple strata and the main source rocks in Sikeshu Sag，it was discovered that the light oil in the study area could be divided into two types，the source of light oil was clarified and the comprehensive criterion for identifying the crude oil was established.The results show that TypeⅠcrude oil mainly distributes in C，J，K，E formation，which has the characteristics of regular sterane C27-C29 in shape of“inverted L”，low levels of γ-cerane，high Pr/Ph，weight carbon isotope and relatively high maturity，and its parent material was formed in the environment of weak oxidization-weak reduction freshwater lake，and the source of organic matter was mainly higher plants，and TypeⅠcrude oil was mainly from the source rock of J1b Formation in Sikeshu Sag. While TypeⅡcrude oil mainly distributes in the N1s with regular sterane C27–C29 in shape of“V”，high levels of γ-cerane，smaller Pr/Ph，lighter carbon isotope and relatively low maturity of crude oil，and its parent material was formed in the environment of strongly reduced brackish water deep lacustrine，and the source of organic matter was mainly planktonic algae，and TypeⅡcrude oil was mainly from the source rock of the Paleogene E2-3a Formation. The research results further confirm that two sets of effective source rocks，Jurassic and paleogene，have been developed in Sikeshu Sag，and the oil and gas generated by them have been transported for a long distance.
2020, 27(4):35-44.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.004
Abstract:
Miaoxinan Sag is on the edge of Bohaiwan Basin and it is formed by the strong transformation of strike-slip fault.In order to study the controlling effect of strike-slip fault on hydrocarbon accumulation，the characteristics of strike-slip tectonic belt and the sag tectonic evolution was studied by means of variance slice and fine structure interpretation. The results show that there are two strike-slip fault branches in the study area：the east and the west. The east branch has obvious segmentation characteristics. The west branch runs through north and south. The forming of large trap groups are controlled by the flexural section and overburden area of strike-slip fault. The strike-slip fault activities in different periods had different controlling effects on hydrocarbon accumulation conditions. In the Eocene，the high-quality source rocks were developed at the intersection of strike-slip faults and extension zones in the southern subsag，and the environment of the intense transformation of strike-slip faults，high temperature and saline sedimentary was favorable to the early generation and early expulsion of hydrocarbon in the source rocks due to strong fault activities. In the late Eocene，strike-slip faults were coupled with the negative geomorphic units to form effective sand transport pathways，controlling the distribution of the delta sedimentary system. In the Oligocene，the formation of caprock in thick clay layers was controlled by the right-handed strike-slip pull-out action. In the Pliocene，two types of oil-gas accumulation modes：far-source convergence type and near-source vertical connection type were formed by the configurations of the strike-slip adjustment faults formed by the neotectonic movements，source rocks and structural ridges.
Miaoxinan Sag is on the edge of Bohaiwan Basin and it is formed by the strong transformation of strike-slip fault.In order to study the controlling effect of strike-slip fault on hydrocarbon accumulation，the characteristics of strike-slip tectonic belt and the sag tectonic evolution was studied by means of variance slice and fine structure interpretation. The results show that there are two strike-slip fault branches in the study area：the east and the west. The east branch has obvious segmentation characteristics. The west branch runs through north and south. The forming of large trap groups are controlled by the flexural section and overburden area of strike-slip fault. The strike-slip fault activities in different periods had different controlling effects on hydrocarbon accumulation conditions. In the Eocene，the high-quality source rocks were developed at the intersection of strike-slip faults and extension zones in the southern subsag，and the environment of the intense transformation of strike-slip faults，high temperature and saline sedimentary was favorable to the early generation and early expulsion of hydrocarbon in the source rocks due to strong fault activities. In the late Eocene，strike-slip faults were coupled with the negative geomorphic units to form effective sand transport pathways，controlling the distribution of the delta sedimentary system. In the Oligocene，the formation of caprock in thick clay layers was controlled by the right-handed strike-slip pull-out action. In the Pliocene，two types of oil-gas accumulation modes：far-source convergence type and near-source vertical connection type were formed by the configurations of the strike-slip adjustment faults formed by the neotectonic movements，source rocks and structural ridges.
2020, 27(4):45-51.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.005
Abstract:
The selection of rock resistivity parameters in Archie formula is important during the logging interpretation of oil saturation. However，the influence of the oil and water occurrence mode in reservoirs is rarely considered. The oil and water occurrence mode in shallow unconsolidated sandstone heavy oil reservoirs is different from that in the conventional oil reservoirs. The pore water in the form of“isolated water droplets”is separated by oil，which makes it difficult to form a conductive network. As a result，the oil saturation of heavy oil reservoirs interpreted by Archie formula is higher than the actual one. Therefore，it is necessary to optimize and correct the saturation interpreted by logging data.In this study，the heavy oil reservoir of Guantao Formation in Zhanhua Sag，Jiyang Depression is selected as the research target to illustrate that the main factor influencing the occurrence of“isolated water droplets”in pore is the pore structure. And then the oil saturation analyzed by oil-based mud core is taken as the standard，the correction amount of the initial interpretation value is calculated to be 4.1%-5.4% with an average of 5% by the methods of experimental analysis and equation interpretation，such as CT scans，Archie formula，oil height and capillary pressure，and water cut equation. The results provide a basis for the interpretation and correction of the oil saturation in heavy oil reservoir，and provide a method for the oil saturation correction of shallow unconsolidated sandstone heavy oil reservoirs.
The selection of rock resistivity parameters in Archie formula is important during the logging interpretation of oil saturation. However，the influence of the oil and water occurrence mode in reservoirs is rarely considered. The oil and water occurrence mode in shallow unconsolidated sandstone heavy oil reservoirs is different from that in the conventional oil reservoirs. The pore water in the form of“isolated water droplets”is separated by oil，which makes it difficult to form a conductive network. As a result，the oil saturation of heavy oil reservoirs interpreted by Archie formula is higher than the actual one. Therefore，it is necessary to optimize and correct the saturation interpreted by logging data.In this study，the heavy oil reservoir of Guantao Formation in Zhanhua Sag，Jiyang Depression is selected as the research target to illustrate that the main factor influencing the occurrence of“isolated water droplets”in pore is the pore structure. And then the oil saturation analyzed by oil-based mud core is taken as the standard，the correction amount of the initial interpretation value is calculated to be 4.1%-5.4% with an average of 5% by the methods of experimental analysis and equation interpretation，such as CT scans，Archie formula，oil height and capillary pressure，and water cut equation. The results provide a basis for the interpretation and correction of the oil saturation in heavy oil reservoir，and provide a method for the oil saturation correction of shallow unconsolidated sandstone heavy oil reservoirs.
2020, 27(4):52-62.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.006
Abstract:
The detail exploration of non-structure hydrocarbon reservoirs in Miocene progradational delta in Block J of South Sumatra Basin is restricted by the unclear understanding of the superimposition patterns and spatial evolution law of sandbodies. Based on the analysis of the high-resolution sequence stratigraphy，regional geological setting，lithofacies，logging response，and seismic features，the genetic unit types of progradational delta are identified. A depositional model reflecting the sandstone architectures of progradational delta is established according to their spatial distribution. The genetic-architecture sandbody classification and reservoir prediction methods restricted by the sandbody superimposition patterns are further proposed. The results show that five genetic unit types are identified in study area，including underwater distributary channel，mouth bar，sheet sand，distributary inter-channel and pre-delta mud in the deltaic depositional system. At early stage of progradational delta sedimentation，the isolated mono-genetic sandbodies were developed and the updip tip-out lithologic trap and multi-layered thin sand reverse block-lithologic trap formed. At the middle stage，the superimposed bi-genetic sandbodies were mainly developed and followed by isolated mono-genetic sandbody，and multi-layered reverse block-lithologic trap formed. At the final stage，the multi-genetic incised superimposed sandbodies were mainly developed and followed by bi-genetic sandbodies，and multilayer complex fault block-lithologic trap and block formation unconformity trap formed.From bottom to top，the superimposed pattern shows as the isolated mono-genetic sandbody-superimposed bi-genetic sandbodies-multi-genetic incised superimposed sandbodies.
The detail exploration of non-structure hydrocarbon reservoirs in Miocene progradational delta in Block J of South Sumatra Basin is restricted by the unclear understanding of the superimposition patterns and spatial evolution law of sandbodies. Based on the analysis of the high-resolution sequence stratigraphy，regional geological setting，lithofacies，logging response，and seismic features，the genetic unit types of progradational delta are identified. A depositional model reflecting the sandstone architectures of progradational delta is established according to their spatial distribution. The genetic-architecture sandbody classification and reservoir prediction methods restricted by the sandbody superimposition patterns are further proposed. The results show that five genetic unit types are identified in study area，including underwater distributary channel，mouth bar，sheet sand，distributary inter-channel and pre-delta mud in the deltaic depositional system. At early stage of progradational delta sedimentation，the isolated mono-genetic sandbodies were developed and the updip tip-out lithologic trap and multi-layered thin sand reverse block-lithologic trap formed. At the middle stage，the superimposed bi-genetic sandbodies were mainly developed and followed by isolated mono-genetic sandbody，and multi-layered reverse block-lithologic trap formed. At the final stage，the multi-genetic incised superimposed sandbodies were mainly developed and followed by bi-genetic sandbodies，and multilayer complex fault block-lithologic trap and block formation unconformity trap formed.From bottom to top，the superimposed pattern shows as the isolated mono-genetic sandbody-superimposed bi-genetic sandbodies-multi-genetic incised superimposed sandbodies.
2020, 27(4):63-66.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.007
Abstract:
The shale gas and coalbed methane are very important unconventional natural gas resources in China. The isothermal adsorption parameters are used in resource evaluation. The determination of the parameters needs to be solved by setting up isothermal adsorption curve through the adsorption experiments. According to the characteristics of the adsorption experimental device，the current adsorption instruments can be divided into weighing instrument and pressure testing instrument. When a rock sample is loaded into a sample cell or test barrel，the void volume needs to be calibrated before calculating the molar amount of free methane in them，either by pressure testing or by weighing method. The sum of the molality of methane in the void volume and the molality of methane absorbed from the rock sample is equal to the total molality of methane injected at a certain stable pressure. Therefore，it is very important to accurately calibrate the void volume size.As helium（He）is stable in physical properties and does not adsorb with rock samples，helium gas is usually used as the medium to calibrate the volume of free space. Based on free state equations and instrumental principles，this paper provides the weighing method and pressure testing method to calibrate the void volume by using He. Application of an example indicates that the method presented in the paper is effective.
The shale gas and coalbed methane are very important unconventional natural gas resources in China. The isothermal adsorption parameters are used in resource evaluation. The determination of the parameters needs to be solved by setting up isothermal adsorption curve through the adsorption experiments. According to the characteristics of the adsorption experimental device，the current adsorption instruments can be divided into weighing instrument and pressure testing instrument. When a rock sample is loaded into a sample cell or test barrel，the void volume needs to be calibrated before calculating the molar amount of free methane in them，either by pressure testing or by weighing method. The sum of the molality of methane in the void volume and the molality of methane absorbed from the rock sample is equal to the total molality of methane injected at a certain stable pressure. Therefore，it is very important to accurately calibrate the void volume size.As helium（He）is stable in physical properties and does not adsorb with rock samples，helium gas is usually used as the medium to calibrate the volume of free space. Based on free state equations and instrumental principles，this paper provides the weighing method and pressure testing method to calibrate the void volume by using He. Application of an example indicates that the method presented in the paper is effective.
SU Haibo
,
ZHANG Shiming
,
SUN Yeheng
,
YU Jinbiao
,
YANG Minglin
,
MENG Wei
,
WANG Yong
,
YU Mingli
2020, 27(4):67-78.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.008
Abstract:
Oil-water relative permeability is an important parameter for studying the characteristics of water flooding development in low permeability reservoirs. It is of great practical significance to understand the percolation law in the low permeability reservoir by determining the influencing factors of oil-water relative permeability. Based on the fractal theory of porous media，a mathematical model of oil-water relative permeability in the low permeability reservoirs and a normalized oil-water relative permeability model are established respectively. The established oil-water relative permeability model is a function of water saturation，displacement pressure，and capillary pressure，which can comprehensively reflect the influence of reservoir pore structure，nonlinear percolation and percolation interference on oil-water relative permeability. The theoretical analysis result shows that the more complex core pore structure is，the lower oil-water relative permeability is；the displacement pressure influences relative permeability of oil phase，which shows that there is a dynamic change of relative permeability in the process of water flooding. Nonlinear percolation has a great influence on the relative permeability of oil phase，but the influence on the relative permeability of water phase may be ignored. The relative permeability of oil phase decreases with the increase of the nonlinear coefficient of oil phase. The percolation interference influences the relative permeability of the oil and water phase which decreases with the increase of the interference coefficient. To verify the reliability of the model，the oil-water relative permeability predicted by the model is compared with the experimental results. The predicted oil-water relative permeability of the model is highly consistent with the experimental results. In addition，the comparison with the prediction results of the classical relative permeability theoretical model shows that the prediction results of the new model for the relative permeability of water phase are better than those of the classical theoretical models.
Oil-water relative permeability is an important parameter for studying the characteristics of water flooding development in low permeability reservoirs. It is of great practical significance to understand the percolation law in the low permeability reservoir by determining the influencing factors of oil-water relative permeability. Based on the fractal theory of porous media，a mathematical model of oil-water relative permeability in the low permeability reservoirs and a normalized oil-water relative permeability model are established respectively. The established oil-water relative permeability model is a function of water saturation，displacement pressure，and capillary pressure，which can comprehensively reflect the influence of reservoir pore structure，nonlinear percolation and percolation interference on oil-water relative permeability. The theoretical analysis result shows that the more complex core pore structure is，the lower oil-water relative permeability is；the displacement pressure influences relative permeability of oil phase，which shows that there is a dynamic change of relative permeability in the process of water flooding. Nonlinear percolation has a great influence on the relative permeability of oil phase，but the influence on the relative permeability of water phase may be ignored. The relative permeability of oil phase decreases with the increase of the nonlinear coefficient of oil phase. The percolation interference influences the relative permeability of the oil and water phase which decreases with the increase of the interference coefficient. To verify the reliability of the model，the oil-water relative permeability predicted by the model is compared with the experimental results. The predicted oil-water relative permeability of the model is highly consistent with the experimental results. In addition，the comparison with the prediction results of the classical relative permeability theoretical model shows that the prediction results of the new model for the relative permeability of water phase are better than those of the classical theoretical models.
2020, 27(4):79-84.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.009
Abstract:
At present，the commonly used evaluation indicators of water flooding development effects are mostly constructed based on the basic production data of the reservoir，and the evaluation process is relatively cumbersome，and it cannot directly characterize the displacement change characteristics of the underground flow field. Therefore，in view of the distribution characteristics of the subsurface flow field in water flooding reservoirs，by extracting the attribute data of the spatial position coordinates of the streamline and the flow rate and saturation distribution of oil and water phases on the streamline，a flow field potential coefficient characterizing the water flooding capacity is constructed. Furthermore，an evaluation method of water flooding development effect based on the instantaneous flow field potential coefficient is proposed. Taking the north Ng3-4 unit in the west area of Gudao Oilfield as an example，the evaluation of the water flooding development effect after the adjustment of the reservoir flow field was conducted. The analysis results show that there is a positive correlation between the instantaneous flow field potential coefficient and the actual cumulative oil production indicators. Compared with the evaluation methods by means of reservoir engineering or numerical simulation calculation，the newly established evaluation method of water flooding development effect only uses the instantaneous flow field potential coefficient to directly characterize the water flooding potential of the underground flow field，which gets rid of the time dependence of the evaluation index calculation，and realizes the rapid and quantitative evaluation of the long-term development effect of water flooding reservoirs. The practical application in the evaluation of large-scale water flooding reservoir development effects is of great significance.
At present，the commonly used evaluation indicators of water flooding development effects are mostly constructed based on the basic production data of the reservoir，and the evaluation process is relatively cumbersome，and it cannot directly characterize the displacement change characteristics of the underground flow field. Therefore，in view of the distribution characteristics of the subsurface flow field in water flooding reservoirs，by extracting the attribute data of the spatial position coordinates of the streamline and the flow rate and saturation distribution of oil and water phases on the streamline，a flow field potential coefficient characterizing the water flooding capacity is constructed. Furthermore，an evaluation method of water flooding development effect based on the instantaneous flow field potential coefficient is proposed. Taking the north Ng3-4 unit in the west area of Gudao Oilfield as an example，the evaluation of the water flooding development effect after the adjustment of the reservoir flow field was conducted. The analysis results show that there is a positive correlation between the instantaneous flow field potential coefficient and the actual cumulative oil production indicators. Compared with the evaluation methods by means of reservoir engineering or numerical simulation calculation，the newly established evaluation method of water flooding development effect only uses the instantaneous flow field potential coefficient to directly characterize the water flooding potential of the underground flow field，which gets rid of the time dependence of the evaluation index calculation，and realizes the rapid and quantitative evaluation of the long-term development effect of water flooding reservoirs. The practical application in the evaluation of large-scale water flooding reservoir development effects is of great significance.
2020, 27(4):85-93.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.010
Abstract:
Aiming at the optimization of injection-production parameters in the process of waterflooding development，it is proposed to use neural network instead of numerical simulation to predict the distribution of remaining oil，and combine the gradient-free differential evolution algorithm to optimize injection and production parameters. This model not only establishes the nonlinear relationship between injection-production parameters and the objective function，but also accurately predicts the distribution characteristics of remaining oil in different production stages. The prediction principle of the model is that the injection-production parameters and production time are regarded as advanced features of the remaining oil distribution image. Then，the convolution layer is used to extract image features and the transposed convolution layer is used to carry out up-sampling on the image. The original image is recovered step by step through a combination of multi-layer “convolution+transpose convolution”，so as to achieve the effect of accurate prediction. During the construction of the neural network，multiple 3×3 small convolution kernels are selected to replace the large convolution kernels. Without affecting the receptive field，the amount of parameters is reduced，and the calculation cost is saved. The iteration efficiency during model training is effectively improved. Taking the five-point well pattern of 4 injection wells and 5 production wells in a block as an example，a neural network prediction model was established by taking the bottom hole pressure of the production well，the injection volume of the injection well and production time as input parameters. Taking the net present value （NPV）as the objective function，the injection-production parameters of the four stages were optimized through the differential optimization algorithm. Compared with the basic plan，the NPV of the optimized plan has increased by about 21%.
Aiming at the optimization of injection-production parameters in the process of waterflooding development，it is proposed to use neural network instead of numerical simulation to predict the distribution of remaining oil，and combine the gradient-free differential evolution algorithm to optimize injection and production parameters. This model not only establishes the nonlinear relationship between injection-production parameters and the objective function，but also accurately predicts the distribution characteristics of remaining oil in different production stages. The prediction principle of the model is that the injection-production parameters and production time are regarded as advanced features of the remaining oil distribution image. Then，the convolution layer is used to extract image features and the transposed convolution layer is used to carry out up-sampling on the image. The original image is recovered step by step through a combination of multi-layer “convolution+transpose convolution”，so as to achieve the effect of accurate prediction. During the construction of the neural network，multiple 3×3 small convolution kernels are selected to replace the large convolution kernels. Without affecting the receptive field，the amount of parameters is reduced，and the calculation cost is saved. The iteration efficiency during model training is effectively improved. Taking the five-point well pattern of 4 injection wells and 5 production wells in a block as an example，a neural network prediction model was established by taking the bottom hole pressure of the production well，the injection volume of the injection well and production time as input parameters. Taking the net present value （NPV）as the objective function，the injection-production parameters of the four stages were optimized through the differential optimization algorithm. Compared with the basic plan，the NPV of the optimized plan has increased by about 21%.
2020, 27(4):94-103.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.011
Abstract:
A large amount of water-based fracturing fluid containing dissolved oxygen needs to be pumped into the formation for hydraulic fracturing in shale gas reservoirs，but the flowback rate of fracturing fluid is generally lower than 30%.The analysis on water imbibition mechanism plays an important role in interpreting the distribution behavior of fracturing fluid leak-off. The organic-rich shale deposited in the hypoxic reduction environment is prone to oxidation reaction under the oxygen-rich condition，however，the effect of oxidation dissolution on the imbibition behavior is still unclear. The shale outcrop samples from Longmaxi Formation in Sichuan Basin were selected in this study，then the experiments of spontaneous imbibition of distilled water and oxidative fluid were carried out in large-scale shale samples successively. And the spontaneous imbibition of distilled water into shale plug samples were performed，exploring the change in water imbibition behaviors in the plugs before and after the treatment of oxidative fluid. The results showed that compared with distilled water，oxidative fluid accelerates the propagation of microfractures and generation of new fractures，promoting more soluble salt to separate out along the microfractures，and showing a larger distribution range of water phase. The imbibed water masses of shale plugs with parallel and perpendicular bedding are 0.425 0 g and 0.446 1 g before oxidation，and they are increased to 0.490 0 g and 0.497 8 g respectively after oxidation. Similarly，the imbibed water masses of shale plugs with fractures are 0.991 2 g and 0.950 0 g，and they are increased to 1.088 6 g and 1.066 9 g respectively after oxidation. The oxidation increases the imbibition capacity of shale plug with matrix by 11.6%-15.3%，and the imbibition potential is increased by 2.32%-8.26%. The imbibed water masses of shale plugs with fracture are increased by 9.8%-12.3%，and the imbibition balance time is decreased by 13.68%-20.23%. The results indicated that the net material removal effect of oxidative dissolution on shale components enlarges the storage space of water phase，improves the porosity and permeability，enhances the water wettability of fracture surface，induces the generation and propagation of microfractures，and decreases the saturation of imbibition front，accelerating water diffusion and increasing the imbibition distance.
A large amount of water-based fracturing fluid containing dissolved oxygen needs to be pumped into the formation for hydraulic fracturing in shale gas reservoirs，but the flowback rate of fracturing fluid is generally lower than 30%.The analysis on water imbibition mechanism plays an important role in interpreting the distribution behavior of fracturing fluid leak-off. The organic-rich shale deposited in the hypoxic reduction environment is prone to oxidation reaction under the oxygen-rich condition，however，the effect of oxidation dissolution on the imbibition behavior is still unclear. The shale outcrop samples from Longmaxi Formation in Sichuan Basin were selected in this study，then the experiments of spontaneous imbibition of distilled water and oxidative fluid were carried out in large-scale shale samples successively. And the spontaneous imbibition of distilled water into shale plug samples were performed，exploring the change in water imbibition behaviors in the plugs before and after the treatment of oxidative fluid. The results showed that compared with distilled water，oxidative fluid accelerates the propagation of microfractures and generation of new fractures，promoting more soluble salt to separate out along the microfractures，and showing a larger distribution range of water phase. The imbibed water masses of shale plugs with parallel and perpendicular bedding are 0.425 0 g and 0.446 1 g before oxidation，and they are increased to 0.490 0 g and 0.497 8 g respectively after oxidation. Similarly，the imbibed water masses of shale plugs with fractures are 0.991 2 g and 0.950 0 g，and they are increased to 1.088 6 g and 1.066 9 g respectively after oxidation. The oxidation increases the imbibition capacity of shale plug with matrix by 11.6%-15.3%，and the imbibition potential is increased by 2.32%-8.26%. The imbibed water masses of shale plugs with fracture are increased by 9.8%-12.3%，and the imbibition balance time is decreased by 13.68%-20.23%. The results indicated that the net material removal effect of oxidative dissolution on shale components enlarges the storage space of water phase，improves the porosity and permeability，enhances the water wettability of fracture surface，induces the generation and propagation of microfractures，and decreases the saturation of imbibition front，accelerating water diffusion and increasing the imbibition distance.
2020, 27(4):104-110.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.012
Abstract:
Considering the wide distribution of bedding fractures in tight sandstone reservoir，it is of great significance to further study the hydraulic fracturing of tight sandstone reservoir by investigating the effect of imbibition displacement of bedding fractures. The tight sandstone reservoir of Lucaogou formation in Jimsar Depression is selected as the research object，and the static imbibition experiments and dynamic simulation experiments at high temperature and high pressure are carried out to compare the imbibition displacement performance between the bedding fractures and structural fractures，and explore the reason caused the difference of imbibition performance. The main controlling factors for imbibition displacement of bedding fractures are determined. Results show that average imbibition efficiency of structural fractures and bed? ding fractures are about 26% and 20% at room temperature. That is to say the imbibition efficiency of the bedding fractures is 77% of that of the structural fractures. The imbibition performance of bedding fractures on improving oil recovery is better. Under normal temperature and pressure or formation temperature and pressure，the imbibition process can be divided into an extremely fast reaction stage，a fast reaction stage，and a slow-stop stage. As the formation temperature rises，the difference of imbibition efficiency between bedding fractures and structural fractures decreases slightly，and the imbibition efficiency of the bedding fractures is 93.4% of that of the structural fractures. When the structural fractures and bedding fractures with the same area are opened together，the imbibition efficiency is basically unchanged，but the imbibition time is greatly reduced.Due to the difference of pore structure in vertical and horizontal direction between bedding fractures and structural fractures，the imbibition efficiency of them is different.
Considering the wide distribution of bedding fractures in tight sandstone reservoir，it is of great significance to further study the hydraulic fracturing of tight sandstone reservoir by investigating the effect of imbibition displacement of bedding fractures. The tight sandstone reservoir of Lucaogou formation in Jimsar Depression is selected as the research object，and the static imbibition experiments and dynamic simulation experiments at high temperature and high pressure are carried out to compare the imbibition displacement performance between the bedding fractures and structural fractures，and explore the reason caused the difference of imbibition performance. The main controlling factors for imbibition displacement of bedding fractures are determined. Results show that average imbibition efficiency of structural fractures and bed? ding fractures are about 26% and 20% at room temperature. That is to say the imbibition efficiency of the bedding fractures is 77% of that of the structural fractures. The imbibition performance of bedding fractures on improving oil recovery is better. Under normal temperature and pressure or formation temperature and pressure，the imbibition process can be divided into an extremely fast reaction stage，a fast reaction stage，and a slow-stop stage. As the formation temperature rises，the difference of imbibition efficiency between bedding fractures and structural fractures decreases slightly，and the imbibition efficiency of the bedding fractures is 93.4% of that of the structural fractures. When the structural fractures and bedding fractures with the same area are opened together，the imbibition efficiency is basically unchanged，but the imbibition time is greatly reduced.Due to the difference of pore structure in vertical and horizontal direction between bedding fractures and structural fractures，the imbibition efficiency of them is different.
13 Influence of permeability on gravity segregation during CO2 flooding in low-permeability reservoirs
2020, 27(4):111-116.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.013
Abstract:
In order to clarify the effect of permeability on gravity segregation and related mechanisms during CO2 flooding in low-permeability reservoirs，the CO2 immiscible and miscible flooding experiments on cores with different permeability are carried out according to gas gravity segregation model，and the recovery of top layer at gas breakthrough and final recovery are used to evaluate gravity segregation level and to reveal its mechanism. The results indicate that within a small permeability variation range，the increase of permeability has little effect on the increase of the viscosity and gravity，especially in miscible flooding，the viscosity and density difference of oil and gas are small，the increase of gravity segregation is not obvious after the permeability increase；the increase of permeability also increases the moving velocity of gas front and decreases the miscibility of oil and gas in immsicible flooding test，which produces a low final recovery with the influence of gravity segregation. The variation of gravity segregation with permeability can be applied to the production of rhythmic reservoirs to avoid or use the gravity segregation，especially in immiscible flooding，CO2 flooding performance in positive rhythm reservoirs could be better under the gravity segregation.
In order to clarify the effect of permeability on gravity segregation and related mechanisms during CO2 flooding in low-permeability reservoirs，the CO2 immiscible and miscible flooding experiments on cores with different permeability are carried out according to gas gravity segregation model，and the recovery of top layer at gas breakthrough and final recovery are used to evaluate gravity segregation level and to reveal its mechanism. The results indicate that within a small permeability variation range，the increase of permeability has little effect on the increase of the viscosity and gravity，especially in miscible flooding，the viscosity and density difference of oil and gas are small，the increase of gravity segregation is not obvious after the permeability increase；the increase of permeability also increases the moving velocity of gas front and decreases the miscibility of oil and gas in immsicible flooding test，which produces a low final recovery with the influence of gravity segregation. The variation of gravity segregation with permeability can be applied to the production of rhythmic reservoirs to avoid or use the gravity segregation，especially in immiscible flooding，CO2 flooding performance in positive rhythm reservoirs could be better under the gravity segregation.
LIU Yisheng
,
LIU Yuetian
,
ZHANG Qichen
,
ZHENG Wenkuan
,
JIAN Changsong
,
LI Guangbo
,
XUE Yanpeng
2020, 27(4):117-125.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.014
Abstract:
Aiming at a thick carbonate reservoir（BU）in the Middle East Missan Oilfield，based on similarity theory，the artificial carbonate sample is used to simulate target reservoir，an large-scale physical model with size of 80 cm×80 cm×10.7 cm that is similar to the typical unit of target reservoir is built to study the water flooding performance，water flooding modes，and the development effect of different well patterns. Results show that the water flooding performance of thick carbonate reservoirs are mainly affected by the longitudinal heterogeneity and gravity，and are characterized by double peaksor single peaks. The water flooding mode is summarized as follows：the injected water moves longitudinally to the high-permeability layer near the water injection well and flow forward along the high-permeability layer. Away from the injection well，the top injected water moves downward under the effect of gravity，then moves along the lower high-permeability layer and breakthroughs to the bottom of the production well to form a secondary bottom water. Finally，the secondary bottom water moves upward，causing the production well to be completely watered. Based on above mode，the remaining oil mainly distributes in the upper layers far from the water injection well；correspondingly，the horizontal well infill well pattern shows a higher control over the reserves of the upper layer than other well patterns，hence it can lead to the higher recovery and development efficiency.
Aiming at a thick carbonate reservoir（BU）in the Middle East Missan Oilfield，based on similarity theory，the artificial carbonate sample is used to simulate target reservoir，an large-scale physical model with size of 80 cm×80 cm×10.7 cm that is similar to the typical unit of target reservoir is built to study the water flooding performance，water flooding modes，and the development effect of different well patterns. Results show that the water flooding performance of thick carbonate reservoirs are mainly affected by the longitudinal heterogeneity and gravity，and are characterized by double peaksor single peaks. The water flooding mode is summarized as follows：the injected water moves longitudinally to the high-permeability layer near the water injection well and flow forward along the high-permeability layer. Away from the injection well，the top injected water moves downward under the effect of gravity，then moves along the lower high-permeability layer and breakthroughs to the bottom of the production well to form a secondary bottom water. Finally，the secondary bottom water moves upward，causing the production well to be completely watered. Based on above mode，the remaining oil mainly distributes in the upper layers far from the water injection well；correspondingly，the horizontal well infill well pattern shows a higher control over the reserves of the upper layer than other well patterns，hence it can lead to the higher recovery and development efficiency.
2020, 27(4):126-132.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.015
Abstract:
Aiming at the problem of low vertical sweep efficiency caused by gas overlap during the CO2 flooding in thick oil reservoir，a high-temperature and high-pressure overlap model is independently developed to study the CO2 overlap migration distance. The fluid collection is completed in each layer，and the length of the core（60，50，40 cm）is changed to carry out the gas flooding experiment. The output of the upper and lower outlets characterize the development efficiency of the upper and lower parts of the core respectively to evaluate the overlap degree. The experimental results show that the migration process of CO2 under gravity segregation can be divided into three stages：the uniform gas advancement stage（0-40 cm），the transition stage（40-50 cm）and the overlap completion stage（50-60 cm）. The ratio method and area method were established to quantitatively characterize the overlap degree. The farther gas migration distance shows the bigger difference in oil production between the upper and lower outlets，the higher increase of the overlap degree index shows the bigger decline in overall oil production. Therefore，the well spacing should be reduced as much as possible to minimize the impact of gas overlap on the development efficiency while ensuring maximum economic benefits in oilfield development.
Aiming at the problem of low vertical sweep efficiency caused by gas overlap during the CO2 flooding in thick oil reservoir，a high-temperature and high-pressure overlap model is independently developed to study the CO2 overlap migration distance. The fluid collection is completed in each layer，and the length of the core（60，50，40 cm）is changed to carry out the gas flooding experiment. The output of the upper and lower outlets characterize the development efficiency of the upper and lower parts of the core respectively to evaluate the overlap degree. The experimental results show that the migration process of CO2 under gravity segregation can be divided into three stages：the uniform gas advancement stage（0-40 cm），the transition stage（40-50 cm）and the overlap completion stage（50-60 cm）. The ratio method and area method were established to quantitatively characterize the overlap degree. The farther gas migration distance shows the bigger difference in oil production between the upper and lower outlets，the higher increase of the overlap degree index shows the bigger decline in overall oil production. Therefore，the well spacing should be reduced as much as possible to minimize the impact of gas overlap on the development efficiency while ensuring maximum economic benefits in oilfield development.
2020, 27(4):133-139.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.016
Abstract:
The production rate through water flooding in offshore oil field，Shengli oil province is decreasing year by year，it is urgent to convert water flooding to binary combination flooding to accelerate the development and improve producing efficiency. As an effective method to dramatically improve oil recovery and oil recovery rate，binary combination flooding technology has been widely used in onshore oil fields. However，due to the difference of reservoir conditions，offshore oil field cannot copy the reservoir development program from onshore oil fields. According to the technical requirements of binary combination flooding in offshore oil field，Shengli oil province，the key factors such as solubility，thermal stability and salt resistance of oil displacement agents are evaluated，and the selected polymer C10 and high-efficiency compound surfactant form the binary combination flooding system with excellent performance of compatibility and stability. The injection viscosity，injection rate and plug size are optimized based on physical simulation and numerical simulation. The results show that after the injection volume of 0.4 PV，the EOR of binary compound flooding system reaches 29.2%，which is 11.3% higher than that of single polymer flooding system with the same plug size. Under the condition of the optimal viscosity ratio of 0.5，the injection rate of 0.07 PV/a and the optimal injection plug size of 0.42 PV，numerical simulation predicted that the EOR of binary compound flooding is 11.6% higher than that of water flooding，which can obtain the maximum increase of the oil recovery rate and oil recovery in offshore oil field.
The production rate through water flooding in offshore oil field，Shengli oil province is decreasing year by year，it is urgent to convert water flooding to binary combination flooding to accelerate the development and improve producing efficiency. As an effective method to dramatically improve oil recovery and oil recovery rate，binary combination flooding technology has been widely used in onshore oil fields. However，due to the difference of reservoir conditions，offshore oil field cannot copy the reservoir development program from onshore oil fields. According to the technical requirements of binary combination flooding in offshore oil field，Shengli oil province，the key factors such as solubility，thermal stability and salt resistance of oil displacement agents are evaluated，and the selected polymer C10 and high-efficiency compound surfactant form the binary combination flooding system with excellent performance of compatibility and stability. The injection viscosity，injection rate and plug size are optimized based on physical simulation and numerical simulation. The results show that after the injection volume of 0.4 PV，the EOR of binary compound flooding system reaches 29.2%，which is 11.3% higher than that of single polymer flooding system with the same plug size. Under the condition of the optimal viscosity ratio of 0.5，the injection rate of 0.07 PV/a and the optimal injection plug size of 0.42 PV，numerical simulation predicted that the EOR of binary compound flooding is 11.6% higher than that of water flooding，which can obtain the maximum increase of the oil recovery rate and oil recovery in offshore oil field.
2020, 27(4):140-146.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.04.017
Abstract:
The study of charged molecular membrane system for sand consolidation was carried out to solve the problems oflow benefit of mechanical sand control and serious damage to reservoir caused by conventional sand consolidation agents in unconsolidated sandstone reservoir in Hekou oil province. The charged polymer 2012A001 was selected as the main agent of the charged molecular membrane system for sand consolidation. The reaction mechanism of sand consolidation system controlled by pH value was emphatically analyzed. The effects of different reservoir conditions on sand consolidation were investigated. The results show that the erosion resistance flow rate of the charged molecular membrane system for sand consolidation is up to 6 000 mL/h. When the temperature exceeds 40 ℃ and the salt content in water is below 10 000 mg/L，the curing speed of the charged molecular membrane system increases with the increase of temperature and salt content. The higher the clay content is，the lower the permeability retention of the core will be. The clay stabilizer should be added when the clay content exceeds 5%. The oil on the surface of sand particles will affect the adsorption of the charged molecular membrane system，so it is necessary to wash the oil thoroughly before injection. The sand control performance is improved with the decrease of sand particle size and the increase of polymer mass fraction but the permeability damage would be more serious. Therefore，the reasonable mass fraction of the charged molecular membrane system for sand consolidation should be selected according to the sand particle size of the reservoir in specific block. According to the characteristics of unconsolidated sandstone reservoir in Hekou oil province，the charged molecular membrane systems for sand consolidation with different formulations were developed. Since 2018，this system has been applied in 15 wells in Hekou oil province，with a cumulative increased oil production of 4 500 tons oil and an input-output ratio of 1∶6.
The study of charged molecular membrane system for sand consolidation was carried out to solve the problems oflow benefit of mechanical sand control and serious damage to reservoir caused by conventional sand consolidation agents in unconsolidated sandstone reservoir in Hekou oil province. The charged polymer 2012A001 was selected as the main agent of the charged molecular membrane system for sand consolidation. The reaction mechanism of sand consolidation system controlled by pH value was emphatically analyzed. The effects of different reservoir conditions on sand consolidation were investigated. The results show that the erosion resistance flow rate of the charged molecular membrane system for sand consolidation is up to 6 000 mL/h. When the temperature exceeds 40 ℃ and the salt content in water is below 10 000 mg/L，the curing speed of the charged molecular membrane system increases with the increase of temperature and salt content. The higher the clay content is，the lower the permeability retention of the core will be. The clay stabilizer should be added when the clay content exceeds 5%. The oil on the surface of sand particles will affect the adsorption of the charged molecular membrane system，so it is necessary to wash the oil thoroughly before injection. The sand control performance is improved with the decrease of sand particle size and the increase of polymer mass fraction but the permeability damage would be more serious. Therefore，the reasonable mass fraction of the charged molecular membrane system for sand consolidation should be selected according to the sand particle size of the reservoir in specific block. According to the characteristics of unconsolidated sandstone reservoir in Hekou oil province，the charged molecular membrane systems for sand consolidation with different formulations were developed. Since 2018，this system has been applied in 15 wells in Hekou oil province，with a cumulative increased oil production of 4 500 tons oil and an input-output ratio of 1∶6.
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