Volume 22,Issue 1,2015 Table of Contents
1 Problems and recommendations for the Regulation of shale gas resources/reserves estimation in China
2015, 22(1):1-4.
Abstract:
As an important follow-up strategic resource，shale gas is now explored and industrially produced in China，and obvious results have been obtained. However，the inexperience in evaluating the shale gas resources/reserves estimationleads to incorrectness，unreliability and even error in estimating geological and recoverable reserves of shale gas in the Regulation of shale gas resources/reserves estimation published on June 1，2014，which deserves more attention. The core of the regulation is to estimate the reserves of the shale gas，and great importance should be attached to insure its correctness in order to avoid mistake in evaluation results and even investment risk. The estimating method of the adsorption gas reserves in the shale gas reservoir，free gas reserves in fractural system are incorrect and the corresponding estimating method of the recoverable reserves is incorrect or even mistake. Moreover，using the initials of Chinese Pinyin x，y and z as subscript of different symbols is irrational，which doesn’t maintain the principle of using English professional terms as the subscript.Existing problems in estimating geological reserves and technical recoverable reserves of shale gas were analyzed. It is sug? gested to discuss about the estimating method of shale gas reserves and the scientificity and reasonability of its symbols. Also，rules of dynamic estimating methods and application case are recommended. Other methods，such as prediction model，may be introduced at the same time.
As an important follow-up strategic resource，shale gas is now explored and industrially produced in China，and obvious results have been obtained. However，the inexperience in evaluating the shale gas resources/reserves estimationleads to incorrectness，unreliability and even error in estimating geological and recoverable reserves of shale gas in the Regulation of shale gas resources/reserves estimation published on June 1，2014，which deserves more attention. The core of the regulation is to estimate the reserves of the shale gas，and great importance should be attached to insure its correctness in order to avoid mistake in evaluation results and even investment risk. The estimating method of the adsorption gas reserves in the shale gas reservoir，free gas reserves in fractural system are incorrect and the corresponding estimating method of the recoverable reserves is incorrect or even mistake. Moreover，using the initials of Chinese Pinyin x，y and z as subscript of different symbols is irrational，which doesn’t maintain the principle of using English professional terms as the subscript.Existing problems in estimating geological reserves and technical recoverable reserves of shale gas were analyzed. It is sug? gested to discuss about the estimating method of shale gas reserves and the scientificity and reasonability of its symbols. Also，rules of dynamic estimating methods and application case are recommended. Other methods，such as prediction model，may be introduced at the same time.
2015, 22(1):5-13.
Abstract:
Based on the drill and seismic data and the organic geochemical analysis data of the source rocks，the geochemi?thinner from centre to outsides. In Bozhong sag，the distribution of high-quality source rocks controls oil and gas distribu? tion and the slope areas near the depression center are the favorable exploration targets. cal characteristics of Paleogene source rocks in Bozhong sag have been studied from several aspects such as organic abun? dance and types，maturity，sedimentary environment，original source of rock and biological markers，etc. The area，where the high-quality source rocks developed，has been pointed out. And then the forming conditions and distribution of the high-quality source rocks have been described. On this basis，all the relationships between high-quality source rocks and hydrocarbon reservoirs have been analyzed to reveal the exploration potential in Bozhong sag. The studied results show that there are three sets of hydrocarbon source rocks developing respectively in the third member of Shahejie Formation，the sec? ond member and the first member of Shahejie Formation，and Dongying Formation. The source rocks have high quality， good types and great potential for hydrocarbon generation and expulsion. The types of source rocks in the third member of Shahejie Formation are mainlyⅠandⅡ1，and the rocks have the highest abundance of organic matter and are in the thresh? old of hydrocarbon generation with the highest quality. It is found that the main conditions for high-quality rocks generation are high rate of biological generation，good source material and good preservation conditions through analyzing forming con? ditions of the three sets of hydrocarbon source rocks from the aspects of source material and sedimentary environment. Then the spatial and temporal distribution characteristics were summarized. The high-quality source rocks generation is con? trolled by sedimentary environment and centre，where semi-deep lake or deep lake developed and the source rocks became
Based on the drill and seismic data and the organic geochemical analysis data of the source rocks，the geochemi?thinner from centre to outsides. In Bozhong sag，the distribution of high-quality source rocks controls oil and gas distribu? tion and the slope areas near the depression center are the favorable exploration targets. cal characteristics of Paleogene source rocks in Bozhong sag have been studied from several aspects such as organic abun? dance and types，maturity，sedimentary environment，original source of rock and biological markers，etc. The area，where the high-quality source rocks developed，has been pointed out. And then the forming conditions and distribution of the high-quality source rocks have been described. On this basis，all the relationships between high-quality source rocks and hydrocarbon reservoirs have been analyzed to reveal the exploration potential in Bozhong sag. The studied results show that there are three sets of hydrocarbon source rocks developing respectively in the third member of Shahejie Formation，the sec? ond member and the first member of Shahejie Formation，and Dongying Formation. The source rocks have high quality， good types and great potential for hydrocarbon generation and expulsion. The types of source rocks in the third member of Shahejie Formation are mainlyⅠandⅡ1，and the rocks have the highest abundance of organic matter and are in the thresh? old of hydrocarbon generation with the highest quality. It is found that the main conditions for high-quality rocks generation are high rate of biological generation，good source material and good preservation conditions through analyzing forming con? ditions of the three sets of hydrocarbon source rocks from the aspects of source material and sedimentary environment. Then the spatial and temporal distribution characteristics were summarized. The high-quality source rocks generation is con? trolled by sedimentary environment and centre，where semi-deep lake or deep lake developed and the source rocks became
2015, 22(1):14-19.
Abstract:
Geochemical features of source rocks have great significance on resource evaluation and exploration target optimization in Fushan sag. Multiple geochemical parameters analysis and comparison of the source rocks in the Liushagang Formation of Fushan sag suggest that hydrocarbon source rocks in the 3rd member of the formation developed in freshwater lakes，weak oxidation environments with high abundance of organic matter which is type Ⅱ1-Ⅱ2. They are high quality source rocks. The source rocks in the 2nd member of the Liushagang Formation developed in freshwater or brackish water，weak oxidation or slightly deoxidization environments with higher abundance of organic matter which is mainly type Ⅱ1.They are high quality and high abundance source rocks. The source rocks in the 1st member of the Liushagang Formation developed in freshwater，weak oxidation sedimentary environment with high abundance of organic matter which is type Ⅱ2.They are secondary high quality source rocks. Source rocks of the Liushagang Formation entered into its oil generation threshold at the late depositional stage of the E2l1 Formation（about 38 Ma），reached the peak period of oil eneration at the early depositional stage of E3w1（about 30 Ma），and entered into its gas generation threshold at the early depositional stage of N（about 20 Ma），and it is still in the stage of a large amount of hydrocarbon generation. At present，hydrocarbon-generating intensity of Bailian subsag is higher than that of Huangtong subsag. The geochemcial features of source rocks show that the lower petroleum system of Bailian subsag is the best in Fushan sag，and the exploration potential in the E2l31 and E2l2 Formation in Bailian is greater with better reservoir-seal assemblage.
Geochemical features of source rocks have great significance on resource evaluation and exploration target optimization in Fushan sag. Multiple geochemical parameters analysis and comparison of the source rocks in the Liushagang Formation of Fushan sag suggest that hydrocarbon source rocks in the 3rd member of the formation developed in freshwater lakes，weak oxidation environments with high abundance of organic matter which is type Ⅱ1-Ⅱ2. They are high quality source rocks. The source rocks in the 2nd member of the Liushagang Formation developed in freshwater or brackish water，weak oxidation or slightly deoxidization environments with higher abundance of organic matter which is mainly type Ⅱ1.They are high quality and high abundance source rocks. The source rocks in the 1st member of the Liushagang Formation developed in freshwater，weak oxidation sedimentary environment with high abundance of organic matter which is type Ⅱ2.They are secondary high quality source rocks. Source rocks of the Liushagang Formation entered into its oil generation threshold at the late depositional stage of the E2l1 Formation（about 38 Ma），reached the peak period of oil eneration at the early depositional stage of E3w1（about 30 Ma），and entered into its gas generation threshold at the early depositional stage of N（about 20 Ma），and it is still in the stage of a large amount of hydrocarbon generation. At present，hydrocarbon-generating intensity of Bailian subsag is higher than that of Huangtong subsag. The geochemcial features of source rocks show that the lower petroleum system of Bailian subsag is the best in Fushan sag，and the exploration potential in the E2l31 and E2l2 Formation in Bailian is greater with better reservoir-seal assemblage.
2015, 22(1):20-25.
Abstract:
Controlled by deposition process and tectonic evolution，different pressure systems generated vertically in the faulted basins. Hydrocarbon accumulation conditions in normal and in abnormal pressure systems are different，resulting in different oil and gas accumulation models and distributions. In order to ascertain the pressure distribution and reservoir forming characteristics in faulted basins，the Palaeogene series in Gunan subsag was studied in detail as an example. According to the measured and calculated data，it is known that normal pressure system with pressure coefficient less than 1.2 exists in Palaeogene formations shallower than 3 000 meter（including Es2 and the strata above）in Gunan subsag，and high pressure system with pressure coefficient more than 1.2 in exists in the formations deeper than 3 000 meter（strata below Es3）. According to formation pressure and hydrocarbon distribution，two hydrocarbon accumulation systems，one with normal pressure outside the source rock and the other with abnormal pressure inside the source rock，were identified in the Palaeogene in Gunan subsag. The hydrocarbon accumulation system with normal pressure outside the source rock is above the source rocks mainly developing tectonic traps in faulted blocks，where hydrocarbons generated from the middle and the lower segments of Es3 migrated vertically into Es2 and the formations above through faults outside the source rocks，or directly migrated into the faulted blocks and rollover anticlines to accumulate，or laterally migrated into appropriate traps to accumulate. The hydrocarbons are entrapped in the fault zones near the source. The hydrocarbon accumulation system with abnormal pressure exists in the source rocks with dominant lithologic or structural-lithologic traps，where hydrocarbons were driven by the high pressure in the source rock and migrated laterally into the adjacent sand bodies or structural-lithologic traps to accumulate. The oil-bearing reservoir distribution is controlled by pressure and lithologic bodies.
Controlled by deposition process and tectonic evolution，different pressure systems generated vertically in the faulted basins. Hydrocarbon accumulation conditions in normal and in abnormal pressure systems are different，resulting in different oil and gas accumulation models and distributions. In order to ascertain the pressure distribution and reservoir forming characteristics in faulted basins，the Palaeogene series in Gunan subsag was studied in detail as an example. According to the measured and calculated data，it is known that normal pressure system with pressure coefficient less than 1.2 exists in Palaeogene formations shallower than 3 000 meter（including Es2 and the strata above）in Gunan subsag，and high pressure system with pressure coefficient more than 1.2 in exists in the formations deeper than 3 000 meter（strata below Es3）. According to formation pressure and hydrocarbon distribution，two hydrocarbon accumulation systems，one with normal pressure outside the source rock and the other with abnormal pressure inside the source rock，were identified in the Palaeogene in Gunan subsag. The hydrocarbon accumulation system with normal pressure outside the source rock is above the source rocks mainly developing tectonic traps in faulted blocks，where hydrocarbons generated from the middle and the lower segments of Es3 migrated vertically into Es2 and the formations above through faults outside the source rocks，or directly migrated into the faulted blocks and rollover anticlines to accumulate，or laterally migrated into appropriate traps to accumulate. The hydrocarbons are entrapped in the fault zones near the source. The hydrocarbon accumulation system with abnormal pressure exists in the source rocks with dominant lithologic or structural-lithologic traps，where hydrocarbons were driven by the high pressure in the source rock and migrated laterally into the adjacent sand bodies or structural-lithologic traps to accumulate. The oil-bearing reservoir distribution is controlled by pressure and lithologic bodies.
2015, 22(1):26-31.
Abstract:
There is abundant natural gas resource in China with huge reserves and increasing production potential. In the next 5-10 years，conventional gas will be still in the dominant place of gas development. However，unconventional gas will play a more and more important role in the long-term process of natural gas development. At present，the exploration and development of unconventional oil and gas is still at the starting stage in China. Ministry of Land and Resources and three Chinese state-owned oil companies have already started to make evaluations on unconventional gas resource of tight gas，CBM and shale gas in varying degrees. In 2012，the total Chinese tight gas resource proven reserves were 16×1012 m3，and the production was 320×108 m3/a. Tight gas development had entered the development stage of large commercialization. By the end of December 2011，CBM proven reserves were about 4 155×108 m3. The less reserves and production showed CBM was still in its early stage of industrialization and commercialization. Shale gas exploration is still at its initial stage since it has no proven reserves. Some research institutions have only evaluated shale gas initially in some areas and established demonstration areas in Sichuan to carry out practice research. Natural gas hydrates have also been paid more attention. The natural gas hydrates developing in South China Sea and the Qinghai-Tibet plateau have been prospected hierarchically according to different exploration degrees. In order to develop unconventional gas resources effectively，it is particularly important to carry out geological theory research and reserves assessment，integrate a series of engineering techniques which have been tested and demonstrated to solve properly the contradiction created between resource exploitation and environmental protection at the same time.
There is abundant natural gas resource in China with huge reserves and increasing production potential. In the next 5-10 years，conventional gas will be still in the dominant place of gas development. However，unconventional gas will play a more and more important role in the long-term process of natural gas development. At present，the exploration and development of unconventional oil and gas is still at the starting stage in China. Ministry of Land and Resources and three Chinese state-owned oil companies have already started to make evaluations on unconventional gas resource of tight gas，CBM and shale gas in varying degrees. In 2012，the total Chinese tight gas resource proven reserves were 16×1012 m3，and the production was 320×108 m3/a. Tight gas development had entered the development stage of large commercialization. By the end of December 2011，CBM proven reserves were about 4 155×108 m3. The less reserves and production showed CBM was still in its early stage of industrialization and commercialization. Shale gas exploration is still at its initial stage since it has no proven reserves. Some research institutions have only evaluated shale gas initially in some areas and established demonstration areas in Sichuan to carry out practice research. Natural gas hydrates have also been paid more attention. The natural gas hydrates developing in South China Sea and the Qinghai-Tibet plateau have been prospected hierarchically according to different exploration degrees. In order to develop unconventional gas resources effectively，it is particularly important to carry out geological theory research and reserves assessment，integrate a series of engineering techniques which have been tested and demonstrated to solve properly the contradiction created between resource exploitation and environmental protection at the same time.
2015, 22(1):32-36.
Abstract:
Hydrocarbon carrier system is important as“the bridge and vinculum”between the oil sources and traps in hydrocarbon accumulation. Based on previous study，hydrocarbon carrier systems were studied through analyzing the migration mechanism. The results obtained show that the hydrocarbon migration mechanism is in essence hydrocarbon migration in space，which includes carriers，driving force and their intrinsic links and evolution. The naming principles of hydrocarbon migration classification were put forward as key migration period，transportation direction，driving force and transportation space，which can be used in the effectiveness evaluation of hydrocarbon carrier system and the prediction of hydrocarbon reservoir distribution to provide guidance for hydrocarbon exploration. As a case of the southern slope in Dongying sag，the hydrocarbon carrier systems formed at the end of the Minghuazhen Formation sedimentary period are divided into 3types，which are the end of the Minghuazhen Formation sedimentary period-vertical migration-middle to high pressuremiddle porosity hydrocarbon carrier system，the end of Minghuazhen Formation sedimentary period-lateral and vertical migration-middle to high pressure-large porosity hydrocarbon carrier system and the end of Minghuazhen Formation sedimentary period-lateral migration-middle to high pressure-buoyancy-large porosity hydrocarbon carrier system.
Hydrocarbon carrier system is important as“the bridge and vinculum”between the oil sources and traps in hydrocarbon accumulation. Based on previous study，hydrocarbon carrier systems were studied through analyzing the migration mechanism. The results obtained show that the hydrocarbon migration mechanism is in essence hydrocarbon migration in space，which includes carriers，driving force and their intrinsic links and evolution. The naming principles of hydrocarbon migration classification were put forward as key migration period，transportation direction，driving force and transportation space，which can be used in the effectiveness evaluation of hydrocarbon carrier system and the prediction of hydrocarbon reservoir distribution to provide guidance for hydrocarbon exploration. As a case of the southern slope in Dongying sag，the hydrocarbon carrier systems formed at the end of the Minghuazhen Formation sedimentary period are divided into 3types，which are the end of the Minghuazhen Formation sedimentary period-vertical migration-middle to high pressuremiddle porosity hydrocarbon carrier system，the end of Minghuazhen Formation sedimentary period-lateral and vertical migration-middle to high pressure-large porosity hydrocarbon carrier system and the end of Minghuazhen Formation sedimentary period-lateral migration-middle to high pressure-buoyancy-large porosity hydrocarbon carrier system.
2015, 22(1):37-41.
Abstract:
Zhenwu fault is an important basement fault in Gaoyou sag，which is crucial to understanding the structural characteristics of Gaoyou sag. Based on the fault interpretation and the regional stress field，the evolution of Zhenwu fault could be divided into three stages：compression stage，inversion stage and extension stage. During the compression stage，Zhenwu fault was a thrust fault formed by the collision of the Indosinian plate；during the inversion stage，Zhenwu fault evolved inherently into Zhen① fault and Wu① fault which differ from each other；during the extension stage，a series of secondary faults formed under the influence of Zhen① fault and Wu① fault，such us Zhen② fault and Wu② fault，which resulted in the formation of Zhenwu fault zones and Wubao fault zones. The results of sandbox experiment modeling Zhenwu fault during the extension stage show that Zhenwu fault，as the basement fault，and regional stress field are the most important two factors that control the evolution of southern boundary fault zones in Gaoyou sag.
Zhenwu fault is an important basement fault in Gaoyou sag，which is crucial to understanding the structural characteristics of Gaoyou sag. Based on the fault interpretation and the regional stress field，the evolution of Zhenwu fault could be divided into three stages：compression stage，inversion stage and extension stage. During the compression stage，Zhenwu fault was a thrust fault formed by the collision of the Indosinian plate；during the inversion stage，Zhenwu fault evolved inherently into Zhen① fault and Wu① fault which differ from each other；during the extension stage，a series of secondary faults formed under the influence of Zhen① fault and Wu① fault，such us Zhen② fault and Wu② fault，which resulted in the formation of Zhenwu fault zones and Wubao fault zones. The results of sandbox experiment modeling Zhenwu fault during the extension stage show that Zhenwu fault，as the basement fault，and regional stress field are the most important two factors that control the evolution of southern boundary fault zones in Gaoyou sag.
2015, 22(1):42-46.
Abstract:
Based on core observation and test and mud logging data analysis，the sedimentary characteristics and distribution of beach-bar in the upper fourth member of Shahejie Formation in Zhanhua depression were researched，and the main controlling factors were analyzed. The results show that there are sandy beach-bar and carbonate beach-bar in the study area. The sandy beach-bars mainly distribute in Luojia nose structure and in neighboring regions. The lithology of the sandy beach-bars is mainly gray fine sandstone and siltstone with good sorting and high maturity. Carbonate beach-bar is classified into organic reefs and limestone. The organic reefs mainly distribute along Yidong fault zone with a strip shape，and the lithology is mainly gray limestone and limy dolomite with poor sorting. They deposited generally in situ or settled down after a short distance migration. The limestone beach-bars mainly distribute in Shaojia sag，and the lithology is mainly gray limestone. The main controlling factors are paleo-climate，paleo-landform and paleo-provenance：the specific paleo-climate resulted in a lack of water in the study area；the ancient landform developed a steep slope zone in the north and a gentle slope zone in the south；and the paleo-provenance was characteristic of lacking western provenance. The distribution area，scale and type of the beach-bars are controlled by the three factors jointly.
Based on core observation and test and mud logging data analysis，the sedimentary characteristics and distribution of beach-bar in the upper fourth member of Shahejie Formation in Zhanhua depression were researched，and the main controlling factors were analyzed. The results show that there are sandy beach-bar and carbonate beach-bar in the study area. The sandy beach-bars mainly distribute in Luojia nose structure and in neighboring regions. The lithology of the sandy beach-bars is mainly gray fine sandstone and siltstone with good sorting and high maturity. Carbonate beach-bar is classified into organic reefs and limestone. The organic reefs mainly distribute along Yidong fault zone with a strip shape，and the lithology is mainly gray limestone and limy dolomite with poor sorting. They deposited generally in situ or settled down after a short distance migration. The limestone beach-bars mainly distribute in Shaojia sag，and the lithology is mainly gray limestone. The main controlling factors are paleo-climate，paleo-landform and paleo-provenance：the specific paleo-climate resulted in a lack of water in the study area；the ancient landform developed a steep slope zone in the north and a gentle slope zone in the south；and the paleo-provenance was characteristic of lacking western provenance. The distribution area，scale and type of the beach-bars are controlled by the three factors jointly.
2015, 22(1):47-51.
Abstract:
Hydrocarbon source conditions in Sanhecun area of Zhanhua sag are complex and hydrocarbon distribution rules are not clear，which constrain the exploration in the area. The hydrocarbon sources and migration pathways have been analyzed systematically based on crude oil physical properties，biomarker and carbon isotopes and maturity parameters. The results obtained show that the crude oil in the Sanhecun area is classified into two types：Es4 type crude oil and mixed crude oil. The former is migrating from hydrocarbon rocks in the 4th member of Shahejie Formation in Bonan subsag，and the latter is migrating from both the hydrocarbon rocks in the 4th member of Shahejie Formation in Bonan subsag and the rocks in the 3rd member of Shahejie Formation in Gunan subsag. It is known that the main crude oil filling direction is from the northeast to the southwest according to the analysis of tracing index of hydrocarbon migration. Combining with the analyses on structures and hydrocarbon scale，the favorable traps in the sub-depression of the northern subsag and in the nose structure of southern Gudao uplift are the next exploration targets.
Hydrocarbon source conditions in Sanhecun area of Zhanhua sag are complex and hydrocarbon distribution rules are not clear，which constrain the exploration in the area. The hydrocarbon sources and migration pathways have been analyzed systematically based on crude oil physical properties，biomarker and carbon isotopes and maturity parameters. The results obtained show that the crude oil in the Sanhecun area is classified into two types：Es4 type crude oil and mixed crude oil. The former is migrating from hydrocarbon rocks in the 4th member of Shahejie Formation in Bonan subsag，and the latter is migrating from both the hydrocarbon rocks in the 4th member of Shahejie Formation in Bonan subsag and the rocks in the 3rd member of Shahejie Formation in Gunan subsag. It is known that the main crude oil filling direction is from the northeast to the southwest according to the analysis of tracing index of hydrocarbon migration. Combining with the analyses on structures and hydrocarbon scale，the favorable traps in the sub-depression of the northern subsag and in the nose structure of southern Gudao uplift are the next exploration targets.
2015, 22(1):52-56.
Abstract:
Faulting is essential for the migration and accumulation of oil and gas. However，expanding space of reservoir resulted from a number of cracks being formed with faulting and the prediction of favorable reservoir formed have not been paid enough attention. Based on the basic theories and methods of fractal geometry，the fractal fracture characteristics of the seismic reflection layer T6 in Linnan subsag of Huimin sag，Bohai Bay Basin（middle section of the third member of Shahejie Formation）has been analyzed quantitatively. The relationship between fractal dimension values of fracture and the proved oil and gas reservoirs distribution has been discussed and the favorable reservoir space resulted from faulting has been predicted. The results show that the fault structures in the research area within the measurement section of 0.187 5-1.5 km have good self-similarity and the correlation coefficients are generally above 0.970. The larger the value of fractal dimension，the more complex the fault structure. The fractal dimension value correlates with the fracture development. The favorable reservoir in the middle of the sag distributes within the closed contours ranging from 1.1 to 1.4. The favorable reservoir in the south and the north of the sag distributes within the closed contours above 1.2. The fault structure positions with fractal dimensions between 0.8 and 1.4 in this area are the advantage areas for oil and gas accumulation，and the positions with fractal dimensions above 1.4 are the areas for oil and gas migration. The area，where is west to Well Xia224 and south to Well Xia53 and Well Jiexie201，is predicted to be the favorable crack for hydrocarbon exploration combining with sedimentary features.
Faulting is essential for the migration and accumulation of oil and gas. However，expanding space of reservoir resulted from a number of cracks being formed with faulting and the prediction of favorable reservoir formed have not been paid enough attention. Based on the basic theories and methods of fractal geometry，the fractal fracture characteristics of the seismic reflection layer T6 in Linnan subsag of Huimin sag，Bohai Bay Basin（middle section of the third member of Shahejie Formation）has been analyzed quantitatively. The relationship between fractal dimension values of fracture and the proved oil and gas reservoirs distribution has been discussed and the favorable reservoir space resulted from faulting has been predicted. The results show that the fault structures in the research area within the measurement section of 0.187 5-1.5 km have good self-similarity and the correlation coefficients are generally above 0.970. The larger the value of fractal dimension，the more complex the fault structure. The fractal dimension value correlates with the fracture development. The favorable reservoir in the middle of the sag distributes within the closed contours ranging from 1.1 to 1.4. The favorable reservoir in the south and the north of the sag distributes within the closed contours above 1.2. The fault structure positions with fractal dimensions between 0.8 and 1.4 in this area are the advantage areas for oil and gas accumulation，and the positions with fractal dimensions above 1.4 are the areas for oil and gas migration. The area，where is west to Well Xia224 and south to Well Xia53 and Well Jiexie201，is predicted to be the favorable crack for hydrocarbon exploration combining with sedimentary features.
2015, 22(1):57-62.
Abstract:
In order to solve the problems of high cost and long cycle in the interwell connectivity research of reservoirs in Liuzhongdong block，Junggar basin，the connectivity coefficient of the oil and water wells was inversed using multiple linear regression mathematical method on the basis of dynamic data including fluid production of oil wells and water injection of water wells. The research results have been verified by tracer data. It shows that there are 4 connectivity types between oil and water wells：single well onrush，single connectivity，one-way connectivity and multidirectional connectivity. The factors controlling the connectivity are mainly affected by the configuration element，fault，physical properties of reservoirs，reservoir stimulation etc. Single well onrush and single connectivity types develop in layer S74 and layer S73 of fan root system，which are mainly controlled by the physical properties of the reservoirs. Single connectivity and one-way connectivity types mainly develop in layer S72 and layer S71 of middle fan system，which are controlled by the configuration unit.
In order to solve the problems of high cost and long cycle in the interwell connectivity research of reservoirs in Liuzhongdong block，Junggar basin，the connectivity coefficient of the oil and water wells was inversed using multiple linear regression mathematical method on the basis of dynamic data including fluid production of oil wells and water injection of water wells. The research results have been verified by tracer data. It shows that there are 4 connectivity types between oil and water wells：single well onrush，single connectivity，one-way connectivity and multidirectional connectivity. The factors controlling the connectivity are mainly affected by the configuration element，fault，physical properties of reservoirs，reservoir stimulation etc. Single well onrush and single connectivity types develop in layer S74 and layer S73 of fan root system，which are mainly controlled by the physical properties of the reservoirs. Single connectivity and one-way connectivity types mainly develop in layer S72 and layer S71 of middle fan system，which are controlled by the configuration unit.
2015, 22(1):63-67.
Abstract:
Bottom water reservoir is the main reservoir type in the Caofeidian oilfield characterized by fluvial facies in Bohai Bay. It is developed by large-scale horizontal wells. Discontinuous interlayer distribution in the reservoir is the key factor that affects development of the bottom water reservoir. So it is very important to study the interlayer distribution and its controlling effect on the bottom water. Taking Massive sand in Caofeidian11-6 oilfield as an example，3D framework of the interlayer distribution was obtained through fine correlation of layers in the appraisal wells and pilot wells that penetrating into oil-bearing reservoirs. The interlayer distribution pattern in thick braided river reservoir was established according to the relationship between interlayer and production performance response of water cut rise，fluid production capability，formation pressure etc. And the control of the pattern on the bottom water movement was analyzed. The research suggests that two main phases of interlayers developed in the Massive sand longitudinally block some of the horizontal wells simultaneously. According to the bottom water blocking ability，the interlayers are divided into three classes：strong barrier，middle barrier and no barrier. This method guides the study of remaining oil distribution and adjustment strategy of the bottom water reservoir in middle-high water cut periods. Finally，23 adjustment wells have been deployed and the average incremental oil for single well is 17×104 t.
Bottom water reservoir is the main reservoir type in the Caofeidian oilfield characterized by fluvial facies in Bohai Bay. It is developed by large-scale horizontal wells. Discontinuous interlayer distribution in the reservoir is the key factor that affects development of the bottom water reservoir. So it is very important to study the interlayer distribution and its controlling effect on the bottom water. Taking Massive sand in Caofeidian11-6 oilfield as an example，3D framework of the interlayer distribution was obtained through fine correlation of layers in the appraisal wells and pilot wells that penetrating into oil-bearing reservoirs. The interlayer distribution pattern in thick braided river reservoir was established according to the relationship between interlayer and production performance response of water cut rise，fluid production capability，formation pressure etc. And the control of the pattern on the bottom water movement was analyzed. The research suggests that two main phases of interlayers developed in the Massive sand longitudinally block some of the horizontal wells simultaneously. According to the bottom water blocking ability，the interlayers are divided into three classes：strong barrier，middle barrier and no barrier. This method guides the study of remaining oil distribution and adjustment strategy of the bottom water reservoir in middle-high water cut periods. Finally，23 adjustment wells have been deployed and the average incremental oil for single well is 17×104 t.
2015, 22(1):68-73.
Abstract:
Physica MCR301 rheometer was used to measure interfacial shear viscoelasticity between different chemical flooding systems and crude oil in order to explore effects of components in combination system（alkali，surfactant，polymer）on oil-water interfacial shear viscoelasticity. The results show that rigid interfacial film can be formed between crude oil and deionized water with high interfacial shear viscoelasticity. Small amounts of surfactant（like mass concentration of 100 mg/L）will significantly reduce interfacial viscoelasticity of crude oil and water. Within the examined mass concentration of the surfactant，higher concentration of the surfactant brings lower interfacial shear viscoelasticity of the interfacial film. Under the condition of high mass concentration of the surfactant（like 3 000 mg/L）and high oscillation angular frequency（like 1 rad/s），interfacial storage modulus exceeds the lower limit of the instrument. Alkali may cause serious damage to the interfacial film. Interfacial loss modulus of lye-oil system are far less than that of water-oil system and interfacial storage modulus of the lye-oil system is too small to be tested，but the damage of organic base on the interfacial film is smaller than that of inorganic base. Polymer will increase the oil-water interfacial viscoelasticity，but the interfacial film can be destroyed easily.
Physica MCR301 rheometer was used to measure interfacial shear viscoelasticity between different chemical flooding systems and crude oil in order to explore effects of components in combination system（alkali，surfactant，polymer）on oil-water interfacial shear viscoelasticity. The results show that rigid interfacial film can be formed between crude oil and deionized water with high interfacial shear viscoelasticity. Small amounts of surfactant（like mass concentration of 100 mg/L）will significantly reduce interfacial viscoelasticity of crude oil and water. Within the examined mass concentration of the surfactant，higher concentration of the surfactant brings lower interfacial shear viscoelasticity of the interfacial film. Under the condition of high mass concentration of the surfactant（like 3 000 mg/L）and high oscillation angular frequency（like 1 rad/s），interfacial storage modulus exceeds the lower limit of the instrument. Alkali may cause serious damage to the interfacial film. Interfacial loss modulus of lye-oil system are far less than that of water-oil system and interfacial storage modulus of the lye-oil system is too small to be tested，but the damage of organic base on the interfacial film is smaller than that of inorganic base. Polymer will increase the oil-water interfacial viscoelasticity，but the interfacial film can be destroyed easily.
2015, 22(1):74-77.
Abstract:
In the low permeability reservoir where nature fractures developed，anisotropy has a great impact on areal sweep efficiency of water flooding. However the current methods have not taken the influence of anisotropy into consideration. The frontal water isosaturation interface was introduced，and the concept of areal sweep efficiency was defined. A new method for evaluating the areal sweep efficiency was established in the low permeability reservoir using streamline simulation technique. The results show that the calculated areal sweep efficiency while water breakthrough by this method is the same as that by reservoir engineering method. Based on the data from a block in Changqing oilfield，the method was applied to make the charts of the areal sweep efficiency under various aeolotropies in quadrate inverted nine-spot pattern，and the areal sweep properties under different aeolotropies were analyzed. Improvement strategies of easing areal sweep contradictions were proposed and the range of the increased areal sweep efficiency after the adjustment was predicted and the corresponding charts were made.
In the low permeability reservoir where nature fractures developed，anisotropy has a great impact on areal sweep efficiency of water flooding. However the current methods have not taken the influence of anisotropy into consideration. The frontal water isosaturation interface was introduced，and the concept of areal sweep efficiency was defined. A new method for evaluating the areal sweep efficiency was established in the low permeability reservoir using streamline simulation technique. The results show that the calculated areal sweep efficiency while water breakthrough by this method is the same as that by reservoir engineering method. Based on the data from a block in Changqing oilfield，the method was applied to make the charts of the areal sweep efficiency under various aeolotropies in quadrate inverted nine-spot pattern，and the areal sweep properties under different aeolotropies were analyzed. Improvement strategies of easing areal sweep contradictions were proposed and the range of the increased areal sweep efficiency after the adjustment was predicted and the corresponding charts were made.
2015, 22(1):78-83.
Abstract:
To enhance oil recovery in Saertu oilfield of Daqing，an experimental study of polymer flooding was performed in a layered heterogeneous reservoir model with different molecular weight polymer using CT scan imagery technology. The layered heterogeneous model consists of three connected sandstone layers of equal thickness. Special core holder was designed for CT scanning. CT scanning technology was applied to tracing the development of the saturation profile of the layered model during polymer flooding process，which can quantitatively characterize the oil saturation distribution. Enhanced oil recovery and remaining oil distribution in each layer were analyzed during the process of water flooding and polymer flooding. Oil recoveries of group DQZ3 and group DQZF1 are up to 77.3% and 72.2% respectively by polymer flooding，which have increased by 39.4% and 21.9% each compared with water flooding. Average water saturation of group DQZ3 and group DQZF1 in the high permeability layers is improved by 4.1% and 2.7% respectively after polymer flooding. Experimental results show that the polymer flooding may effectively sweep the remaining oil in the middle-to-low permeability layers after water flooding，and also reduce the residual oil saturation of the high permeability layers that has very low residual oil saturation after water flooding. Oil recovery would be enhanced as the polymer molecular weight increases.
To enhance oil recovery in Saertu oilfield of Daqing，an experimental study of polymer flooding was performed in a layered heterogeneous reservoir model with different molecular weight polymer using CT scan imagery technology. The layered heterogeneous model consists of three connected sandstone layers of equal thickness. Special core holder was designed for CT scanning. CT scanning technology was applied to tracing the development of the saturation profile of the layered model during polymer flooding process，which can quantitatively characterize the oil saturation distribution. Enhanced oil recovery and remaining oil distribution in each layer were analyzed during the process of water flooding and polymer flooding. Oil recoveries of group DQZ3 and group DQZF1 are up to 77.3% and 72.2% respectively by polymer flooding，which have increased by 39.4% and 21.9% each compared with water flooding. Average water saturation of group DQZ3 and group DQZF1 in the high permeability layers is improved by 4.1% and 2.7% respectively after polymer flooding. Experimental results show that the polymer flooding may effectively sweep the remaining oil in the middle-to-low permeability layers after water flooding，and also reduce the residual oil saturation of the high permeability layers that has very low residual oil saturation after water flooding. Oil recovery would be enhanced as the polymer molecular weight increases.
2015, 22(1):84-87.
Abstract:
In the process of CO2 flooding，CO2 can change the physical properties of oil by dissolving into the oil，thereby improving the oil recovery factor. However，the effects of temperature and injection pressure on the displacement efficiency and the change rules of the oil properties in the process need further research. It was studied through rock displacement ex? periments and oil physical properties testing experiments. The results show that the oil recovery factor remains almost un? changed as the injection pressure increases under 22 ℃. While the effect of injection pressure on the oil recovery factor is limited when the injected CO2 is in gas state under 60 ℃. However，when the injection pressure increases to a point at which the CO2 is in supercritical sate，the oil recovery factor will be largely improved，but the gas to oil exchange ratio will decrease quickly. And when the injection pressure increases to the minimum miscible pressure，the growth of oil recovery factor slows down. The CO2 breakthrough is more likely to occur when the CO2 is in gas state than in supercritical or liquid state. The analysis of oil physical properties shows that the produced oil becomes lighter and its density and viscosity de? crease with the increase of production time and injection pressure at constant temperature.
In the process of CO2 flooding，CO2 can change the physical properties of oil by dissolving into the oil，thereby improving the oil recovery factor. However，the effects of temperature and injection pressure on the displacement efficiency and the change rules of the oil properties in the process need further research. It was studied through rock displacement ex? periments and oil physical properties testing experiments. The results show that the oil recovery factor remains almost un? changed as the injection pressure increases under 22 ℃. While the effect of injection pressure on the oil recovery factor is limited when the injected CO2 is in gas state under 60 ℃. However，when the injection pressure increases to a point at which the CO2 is in supercritical sate，the oil recovery factor will be largely improved，but the gas to oil exchange ratio will decrease quickly. And when the injection pressure increases to the minimum miscible pressure，the growth of oil recovery factor slows down. The CO2 breakthrough is more likely to occur when the CO2 is in gas state than in supercritical or liquid state. The analysis of oil physical properties shows that the produced oil becomes lighter and its density and viscosity de? crease with the increase of production time and injection pressure at constant temperature.
2015, 22(1):88-92.
Abstract:
In order to avoid the inefficient or invalid polymer solution cycle，optimize oilfield chemical dosage reasonably，improve oil production and increase oil production per ton of polymer and other parameter values，the change rule of development indexes，including polymer volume，composite water cut，polymer concentration of production and increased multiple of oil，were analyzed thoroughly among each well groups in later polymer injection period in Daqing oilfield. Considering economical benefit and geological condition differences between wells and between layers，the plan of polymer injection should be stopped when the composite water cut of the block is 92%. Polymer injection should be stopped when the composite water cut of single well is 94%. For the producers with composite water cut of 92%-94%，the time of polymer injection stopping can be determined from the intersection point of the three curves：the recovery increment curve，the derivative curve of polymer consumption and the economic limit curve. Polymer injection implementation method was established as “oil layers stop while wells keeping，and wells stop while stations working，and stations stop while blocks working”. On this basis，the utilization rate of polymer and the effect of polymer flooding development will be improved.
In order to avoid the inefficient or invalid polymer solution cycle，optimize oilfield chemical dosage reasonably，improve oil production and increase oil production per ton of polymer and other parameter values，the change rule of development indexes，including polymer volume，composite water cut，polymer concentration of production and increased multiple of oil，were analyzed thoroughly among each well groups in later polymer injection period in Daqing oilfield. Considering economical benefit and geological condition differences between wells and between layers，the plan of polymer injection should be stopped when the composite water cut of the block is 92%. Polymer injection should be stopped when the composite water cut of single well is 94%. For the producers with composite water cut of 92%-94%，the time of polymer injection stopping can be determined from the intersection point of the three curves：the recovery increment curve，the derivative curve of polymer consumption and the economic limit curve. Polymer injection implementation method was established as “oil layers stop while wells keeping，and wells stop while stations working，and stations stop while blocks working”. On this basis，the utilization rate of polymer and the effect of polymer flooding development will be improved.
18 Experimental study of improving the recovery in super heavy oil reservoir after dissolved gas drive
2015, 22(1):98-101.
Abstract:
Since amounts of residual oil still remains after dissolved gas drive in super heavy oil reservoir，effects of flooding conversion on oil displacement efficiency were studied through experiments under various conditions focusing on this problem. The lab experiment results illustrate that the oil recovery by the traditional dissolved gas drive for homogeneous lab core model is about 10%. Either steam stimulation or CO2 stimulation after dissolved gas driving stimulation can enhance oil recovery to some extent. Steam stimulation is more applicable with a final oil recovery of more than 70%，whereas the oil recovery after CO2 stimulation can only achieve about 25%. Additionally，the influences of the pressure drop speed，temperature and permeability on oil recovery are different. A faster pressure drop can lead to a faster recovery speed and enhance recovery efficiency for a certain time. The oil recovery is controlled by temperature with time effect. Lower temperature can enhance oil recovery. The effect of formation permeability on the oil recovery is limited，and a higher permeability can boost recovery speed.
Since amounts of residual oil still remains after dissolved gas drive in super heavy oil reservoir，effects of flooding conversion on oil displacement efficiency were studied through experiments under various conditions focusing on this problem. The lab experiment results illustrate that the oil recovery by the traditional dissolved gas drive for homogeneous lab core model is about 10%. Either steam stimulation or CO2 stimulation after dissolved gas driving stimulation can enhance oil recovery to some extent. Steam stimulation is more applicable with a final oil recovery of more than 70%，whereas the oil recovery after CO2 stimulation can only achieve about 25%. Additionally，the influences of the pressure drop speed，temperature and permeability on oil recovery are different. A faster pressure drop can lead to a faster recovery speed and enhance recovery efficiency for a certain time. The oil recovery is controlled by temperature with time effect. Lower temperature can enhance oil recovery. The effect of formation permeability on the oil recovery is limited，and a higher permeability can boost recovery speed.
2015, 22(1):102-105.
Abstract:
It is important to study the moving law of oil-gas contact in oil reservoir with condensate gas cap in the interest of developing the gas cap and oil rim concurrently. Considering factors of retrograde condensation，water vapor content and rock compressibility，a new method of calculating the moving range of oil-gas contact in the oil reservoir with condensate gas cap was derived based on material balance principle and an assumption of elliptic-cone-shaped reservoir. Application case shows that the moving velocity of oil-gas contact increases after the retrograde condensation of gas cap；all the computing results of the vertical moving range of the oil-gas contact are smaller when the factors of retrograde condensation，rock compressibility or water vapor content is neglected；the influence of retrograde condensation on the vertical moving range of the oil-gas contact is larger than that from rock compressibility and water vapor content. The computing result of the new method agrees well with the one obtained by pressure gradient method.
It is important to study the moving law of oil-gas contact in oil reservoir with condensate gas cap in the interest of developing the gas cap and oil rim concurrently. Considering factors of retrograde condensation，water vapor content and rock compressibility，a new method of calculating the moving range of oil-gas contact in the oil reservoir with condensate gas cap was derived based on material balance principle and an assumption of elliptic-cone-shaped reservoir. Application case shows that the moving velocity of oil-gas contact increases after the retrograde condensation of gas cap；all the computing results of the vertical moving range of the oil-gas contact are smaller when the factors of retrograde condensation，rock compressibility or water vapor content is neglected；the influence of retrograde condensation on the vertical moving range of the oil-gas contact is larger than that from rock compressibility and water vapor content. The computing result of the new method agrees well with the one obtained by pressure gradient method.
2015, 22(1):106-110.
Abstract:
Chinese onshore oilfields have generally stepped into high water cut stage. A large number of wells shut down frequently for various reasons，which results in a damaged well pattern and poor reservoir development effect. It’s necessary to accurately reveal the influences of the well loss on the reservoir development effect so as to provide decision-making basis for well loss recovery measures. The loss percentage of reservoir recoverable reserves was defined and taking as an evaluation index of the reservoir development effect under the condition of well loss. The influences of well loss on the development effect in the high permeability reservoir were analyzed quantitatively. The results indicate that with the course of well loss time，the loss percentage of reservoir recoverable reserves increases first and then reduces for the relatively high permeability wells，and it increases for the relatively low permeability wells monotonously；at the same moment of well loss，the loss percentage of reservoir recoverable reserves for the relatively low permeability wells is greater than that for the relatively high permeability wells. Meanwhile，the impact of well loss position under heterogeneous permeability condition is obvious and that under homogeneous permeability condition is weak；at the same moment of well loss，with increasing plane variation coefficient of permeability，the loss percentage of reservoir recoverable reserves reduces for the relatively high permeability wells and increases for the relatively low permeability wells；the loss percentage of reservoir recoverable reserves of the production wells is higher than that of the injection wells with the same well loss percentage. Priority should be given to recover the production well.
Chinese onshore oilfields have generally stepped into high water cut stage. A large number of wells shut down frequently for various reasons，which results in a damaged well pattern and poor reservoir development effect. It’s necessary to accurately reveal the influences of the well loss on the reservoir development effect so as to provide decision-making basis for well loss recovery measures. The loss percentage of reservoir recoverable reserves was defined and taking as an evaluation index of the reservoir development effect under the condition of well loss. The influences of well loss on the development effect in the high permeability reservoir were analyzed quantitatively. The results indicate that with the course of well loss time，the loss percentage of reservoir recoverable reserves increases first and then reduces for the relatively high permeability wells，and it increases for the relatively low permeability wells monotonously；at the same moment of well loss，the loss percentage of reservoir recoverable reserves for the relatively low permeability wells is greater than that for the relatively high permeability wells. Meanwhile，the impact of well loss position under heterogeneous permeability condition is obvious and that under homogeneous permeability condition is weak；at the same moment of well loss，with increasing plane variation coefficient of permeability，the loss percentage of reservoir recoverable reserves reduces for the relatively high permeability wells and increases for the relatively low permeability wells；the loss percentage of reservoir recoverable reserves of the production wells is higher than that of the injection wells with the same well loss percentage. Priority should be given to recover the production well.
2015, 22(1):111-117.
Abstract:
Air flooding，as a creative EOR technique，is receiving more and more attention. The existence of explosion risk severely constrains the development and application of this technique. Thus，it is of great importance to obtain a clear knowledge and control of the explosion limits of combustible gases for fire warning and production safety of the air flooding technique. For this reason，the factors that influence the explosion limits of the combustible gases were analyzed，and the results show that：the components of the mix combustible gases can influence on its explosion limits，and the combustible gases with multi-component have an explosion limits which are the harmonic mean of those components；the explosion limits increase linearly with the raise of temperature，but increase logarithmically with the raise of pressure；the explosion limits decrease with the increasing volume fraction of inert gases，and different kinds of inert gases have various influences on explosion proof. The calculation models with different factors and unified prediction model of the explosion limits of the combustible gases were matched by using mechanism of numerical analysis and combination of empirical formula，and that will provide reference for predicting the explosion limits of oil-gas mixture under different conditions in air flooding technique.
Air flooding，as a creative EOR technique，is receiving more and more attention. The existence of explosion risk severely constrains the development and application of this technique. Thus，it is of great importance to obtain a clear knowledge and control of the explosion limits of combustible gases for fire warning and production safety of the air flooding technique. For this reason，the factors that influence the explosion limits of the combustible gases were analyzed，and the results show that：the components of the mix combustible gases can influence on its explosion limits，and the combustible gases with multi-component have an explosion limits which are the harmonic mean of those components；the explosion limits increase linearly with the raise of temperature，but increase logarithmically with the raise of pressure；the explosion limits decrease with the increasing volume fraction of inert gases，and different kinds of inert gases have various influences on explosion proof. The calculation models with different factors and unified prediction model of the explosion limits of the combustible gases were matched by using mechanism of numerical analysis and combination of empirical formula，and that will provide reference for predicting the explosion limits of oil-gas mixture under different conditions in air flooding technique.
2015, 22(1):118-121.
Abstract:
As the performance of foam flooding is dominated by foam stability which may be reduced in the presence of oil，development of foam system with improved foam stability has become increasingly important in the area of enhancing oil recovery of the foam flooding. The relationship between oil and foam stability was investigated by foam decay measurements and microfluidic control method. The effect of interfacial tension（IFT）between oil and foam system on the foam stability was examined through certain oil and different foam systems. Reaction between emulsified oil drop and bubbles was evaluated. Experimental results show that the half-life decreased considerably for the low-IFT foam systems，and oil has greater influence on the lower-IFT foam systems. Additionally，oil with lower surface tension would affect foam ability more significantly. Because larger relative molecular weight of oil and surface tension will bring difficulties in spreading on the gas-water interface with weaker reaction of the foam.
As the performance of foam flooding is dominated by foam stability which may be reduced in the presence of oil，development of foam system with improved foam stability has become increasingly important in the area of enhancing oil recovery of the foam flooding. The relationship between oil and foam stability was investigated by foam decay measurements and microfluidic control method. The effect of interfacial tension（IFT）between oil and foam system on the foam stability was examined through certain oil and different foam systems. Reaction between emulsified oil drop and bubbles was evaluated. Experimental results show that the half-life decreased considerably for the low-IFT foam systems，and oil has greater influence on the lower-IFT foam systems. Additionally，oil with lower surface tension would affect foam ability more significantly. Because larger relative molecular weight of oil and surface tension will bring difficulties in spreading on the gas-water interface with weaker reaction of the foam.
23 Experimental evaluation on influencing factors of flow
conductivity for channel fracturing proppant
2015, 22(1):122-126.
Abstract:
Flow conductivity of the proppant fracture system is one of the important parameters of evaluating the effect of fracturing. The effect of the numbers of the proppant diameter，proppant slug，the concentration and existing ways of fiber was studied in laboratory through the experiment of flow conductivity. The importance of parameters on the flow conductivity was analyzed based on orthogonal experimental design and grey relational analysis. The results show that：flow conductivity increases with the proppant diameter；the larger the number of the proppant slug，the less the increasing range of the flow conductivity；when the closure pressure is less than 41 MPa，the more the proppant slugs，the greater magnitude the flow conductivity changing with the closure pressure；the flow conductivity will decrease with the increasing of the fiber concentration，and fiber wrap proppant has the largest impact on the proppant conductivity；parameters that affect flow conductivity are listed in a descending order：closure pressure，the number of proppant slug，the fiber concentration，the exiting way of fiber in the fracture，the diameter of the proppant.
Flow conductivity of the proppant fracture system is one of the important parameters of evaluating the effect of fracturing. The effect of the numbers of the proppant diameter，proppant slug，the concentration and existing ways of fiber was studied in laboratory through the experiment of flow conductivity. The importance of parameters on the flow conductivity was analyzed based on orthogonal experimental design and grey relational analysis. The results show that：flow conductivity increases with the proppant diameter；the larger the number of the proppant slug，the less the increasing range of the flow conductivity；when the closure pressure is less than 41 MPa，the more the proppant slugs，the greater magnitude the flow conductivity changing with the closure pressure；the flow conductivity will decrease with the increasing of the fiber concentration，and fiber wrap proppant has the largest impact on the proppant conductivity；parameters that affect flow conductivity are listed in a descending order：closure pressure，the number of proppant slug，the fiber concentration，the exiting way of fiber in the fracture，the diameter of the proppant.
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