Volume 22,Issue 5,2015 Table of Contents
2015, 22(5):1-6.
Abstract:
For heavy oil reservoir，steam huff and puff and steam drive are two important stages of steam flooding recovery.The economically recoverable reserves and economic limit of steam-oil ratio are two important indexes to evaluate steam flooding recovery. Up till now，the injection-production relationship method of the national industry standard published in 1996 and 2010 are the main methods to evaluate recoverable reserves of heavy oil reservoir by steam flooding recovery. This method describes the semi-log linear relationship between the cumulative gas injection rate and the cumulative oil production rate and its effective application largely depends on the economic limit of oil-steam ratio（0.25 t/m3 for the steam huff and puff，and 0.15 t/m3 for the steam flooding recovery）. However，the economic limit of oil-steam ratio in the national industry standard is rather higher which leads to smaller technically recoverable reserves. The production decline method was firstly used to predict economically recoverable reserves accurately，and then the injection-production relationship method was applied to predict economic limit of steam-oil ratio. At the same time，the irrationality of the economic limit of oil-steam ratio，the unreliability of the technical recoverable reserves and the incorrectness of the total technically recoverable reserves of the national industry standard were researched and analyzed. The actual application of Block Qi40 in Liaohe oilfield indicates that the economically recoverable reserves predicted by the method in this paper are 1 573×104 t，and the economic limit of steam-oil ratio is 20 m3/t and its corresponding economic limit of oil-steam ratio is 0.05 t/m3. However，the technically recoverable reserves predicted by the economic limit of oil-steam ratio according to the national industry standard is 1 110×104 t，which equals to the cumulative oil production rate of 1 144×104 t in 2005.
For heavy oil reservoir，steam huff and puff and steam drive are two important stages of steam flooding recovery.The economically recoverable reserves and economic limit of steam-oil ratio are two important indexes to evaluate steam flooding recovery. Up till now，the injection-production relationship method of the national industry standard published in 1996 and 2010 are the main methods to evaluate recoverable reserves of heavy oil reservoir by steam flooding recovery. This method describes the semi-log linear relationship between the cumulative gas injection rate and the cumulative oil production rate and its effective application largely depends on the economic limit of oil-steam ratio（0.25 t/m3 for the steam huff and puff，and 0.15 t/m3 for the steam flooding recovery）. However，the economic limit of oil-steam ratio in the national industry standard is rather higher which leads to smaller technically recoverable reserves. The production decline method was firstly used to predict economically recoverable reserves accurately，and then the injection-production relationship method was applied to predict economic limit of steam-oil ratio. At the same time，the irrationality of the economic limit of oil-steam ratio，the unreliability of the technical recoverable reserves and the incorrectness of the total technically recoverable reserves of the national industry standard were researched and analyzed. The actual application of Block Qi40 in Liaohe oilfield indicates that the economically recoverable reserves predicted by the method in this paper are 1 573×104 t，and the economic limit of steam-oil ratio is 20 m3/t and its corresponding economic limit of oil-steam ratio is 0.05 t/m3. However，the technically recoverable reserves predicted by the economic limit of oil-steam ratio according to the national industry standard is 1 110×104 t，which equals to the cumulative oil production rate of 1 144×104 t in 2005.
2015, 22(5):7-14.
Abstract:
The deep fan diagenetic trap developed widely in the northern steep slope zone of the Dongying sag and the differences in sedimentary fabric and diagenesis play important role in the reservoir forming. How to evaluate the trap effectiveness is the key to exploration. By analyzing geological characteristics of root-fan and oil reservoir，the object of trap evaluation，the root-fan sealing mechanism and evaluation principle were determined to predict oil-bearing properties of diagenesis trap effectively. Based on this，according to different data at different exploration stages，the trap effectiveness evaluation methods suitable for different exploration stages were established. The results show that the root-fan developed high clay heterobase and strong compaction and heterobase recrystallization so the root-fan could be a lateral sealing seal or a local seal. The main seal mechanism of diagenetic trap was capillary sealing，the difference of displacement pressure between root-fan and mid-fan determined oil column height. Mercury injection data should be corrected by experimental data of oil displacing water in whole diameter core，and the method of calculating breakthrough radius of oil displacing water using NMR data or routine physical data were established，by which the breakthrough pressure difference under oil reservoir condition can be obtained to evaluate the trap effectiveness. The analysis of the applied result shows that this evaluation method can be used to guide exploration.
The deep fan diagenetic trap developed widely in the northern steep slope zone of the Dongying sag and the differences in sedimentary fabric and diagenesis play important role in the reservoir forming. How to evaluate the trap effectiveness is the key to exploration. By analyzing geological characteristics of root-fan and oil reservoir，the object of trap evaluation，the root-fan sealing mechanism and evaluation principle were determined to predict oil-bearing properties of diagenesis trap effectively. Based on this，according to different data at different exploration stages，the trap effectiveness evaluation methods suitable for different exploration stages were established. The results show that the root-fan developed high clay heterobase and strong compaction and heterobase recrystallization so the root-fan could be a lateral sealing seal or a local seal. The main seal mechanism of diagenetic trap was capillary sealing，the difference of displacement pressure between root-fan and mid-fan determined oil column height. Mercury injection data should be corrected by experimental data of oil displacing water in whole diameter core，and the method of calculating breakthrough radius of oil displacing water using NMR data or routine physical data were established，by which the breakthrough pressure difference under oil reservoir condition can be obtained to evaluate the trap effectiveness. The analysis of the applied result shows that this evaluation method can be used to guide exploration.
Zhu Deshun
,
Wang Yong
,
Zhu Deyan
,
Ning Fangxing
,
Yang Wanqin
,
Zong Miao
,
Yin Yan
,
Ding Juhong
2015, 22(5):15-20.
Abstract:
Limestone interlayers with different thickness develop in thick shale formation of Es1 in Bonan subsag. Learning from the national standard of shale gas and SINOPEC standard of shale oil，the thickness of interlayer that produces oil was determined. The criteria，the thickness of single interlayer is less than two meters and the cumulative thickness of interlayer is less than 20% of that of the formation，were regarded as the recognition standard for interlayer shale oil in Bonan subsag.The interlayer at the lower part of Es1 mainly consists of dolomite and its log response is characterized by obvious high resistivity. The water cut is gradually increased in the process of oil and gas output，which supports the point that the shale oil from interlayer mainly exists in free state. By analyzing the correlation between production capacity and enrichment factors of interlayer shale oil，it is found that whether interlayer shale oil can effectively accumulate is mainly controlled by four factors including generation and discharge condition of hydrocarbon，thickness of interlayer，physical conditions of interlayer and formation pressure and oil properties.
Limestone interlayers with different thickness develop in thick shale formation of Es1 in Bonan subsag. Learning from the national standard of shale gas and SINOPEC standard of shale oil，the thickness of interlayer that produces oil was determined. The criteria，the thickness of single interlayer is less than two meters and the cumulative thickness of interlayer is less than 20% of that of the formation，were regarded as the recognition standard for interlayer shale oil in Bonan subsag.The interlayer at the lower part of Es1 mainly consists of dolomite and its log response is characterized by obvious high resistivity. The water cut is gradually increased in the process of oil and gas output，which supports the point that the shale oil from interlayer mainly exists in free state. By analyzing the correlation between production capacity and enrichment factors of interlayer shale oil，it is found that whether interlayer shale oil can effectively accumulate is mainly controlled by four factors including generation and discharge condition of hydrocarbon，thickness of interlayer，physical conditions of interlayer and formation pressure and oil properties.
2015, 22(5):21-27.
Abstract:
Based on statistic data of fullness degree of Neogene lithologic reservoir in the Shijiutuo uplift，the size，distribution and controlling factors on fullness degree of trap were analyzed. The results show that there is a great variation in fullness degree of the lower Minghuazhen Formation. The vertical fullness degree of trap（ratio of oil column height to trap closure height）is between 16.1% and 87.5% with an average of 47.5%，while the areal fullness degree of trap（ratio of oilbearing area to trap closure area）is between 6.1% and 98.3% with an average of 52.6%. Sand bodies with vertical and areal fullness degree over 50% account for more than 1/2 of the whole sand bodies. The fullness degree of trap is unbalanced in the plane and different in the vertical and oil layer Ⅰ has the highest fullness degree of trap. The fullness degree of lithologic reservoir is mainly controlled by structural shape，sand body geometry，fault activity and fault-sand body contact length.The planar distribution of fullness degree of trap is controlled by structural shape. There is a negative correlation between sand body geometry amplitude，area，length-width ratio and fullness degree of trap. For sand body characterized by structural amplitude of less than 45 m，area of less than 4.5 km2 and length-width ratio of less than 4，more than 40% of its whole area is commonly filled by oil. For sand body whose contact length with fault is less than 4.5 km，more than 40% of its whole area is commonly filled by oil.
Based on statistic data of fullness degree of Neogene lithologic reservoir in the Shijiutuo uplift，the size，distribution and controlling factors on fullness degree of trap were analyzed. The results show that there is a great variation in fullness degree of the lower Minghuazhen Formation. The vertical fullness degree of trap（ratio of oil column height to trap closure height）is between 16.1% and 87.5% with an average of 47.5%，while the areal fullness degree of trap（ratio of oilbearing area to trap closure area）is between 6.1% and 98.3% with an average of 52.6%. Sand bodies with vertical and areal fullness degree over 50% account for more than 1/2 of the whole sand bodies. The fullness degree of trap is unbalanced in the plane and different in the vertical and oil layer Ⅰ has the highest fullness degree of trap. The fullness degree of lithologic reservoir is mainly controlled by structural shape，sand body geometry，fault activity and fault-sand body contact length.The planar distribution of fullness degree of trap is controlled by structural shape. There is a negative correlation between sand body geometry amplitude，area，length-width ratio and fullness degree of trap. For sand body characterized by structural amplitude of less than 45 m，area of less than 4.5 km2 and length-width ratio of less than 4，more than 40% of its whole area is commonly filled by oil. For sand body whose contact length with fault is less than 4.5 km，more than 40% of its whole area is commonly filled by oil.
2015, 22(5):28-33.
Abstract:
Zhanhua sag has the characteristics of“multi-sub-sag with multi-hydrocarbon-source，multi-stage hydrocarbon charging and accumulation and mixed sources of multi-sub-sag”. In accordance with the above characteristics，based on the division of sub-structural units，from source rocks to petroleum reservoirs，oil-source correlation techniques was applied to analyze and determine the hydrocarbon supplying range of source rocks of different sub-sags，the pathways and processes of hydrocarbon-migrating and the exploration potential of different structural belts. On the basis of the analyses，a composite petroleum accumulation belt with similar sources and migration pathways and reservoir-forming characteristics was defined as a multi-source-supply reservoir-forming unit，and four classifications and seven units were classified and divided totally. The types are single sub-sag with single hydrocarbon source，multi-sub-sag with multi-ydrocarbonsource，single sub-sag with multiple hydrocarbon sources，multi-sub-sag with single hydrocarbon-source，and the units are the Yidong-Chengnan unit with single sub-sag and multiple hydrocarbon sources，the Changdi-north Gudong-Kendong uplift unit with multi-sub-sag and multi-hydrocarbon-source，the Chenjiazhuang-Kenxi unit with single sub-sag and multiple hydrocarbon sources，the Shaojia-Bonnan-Gubei unit with single sub-sag and single hydrocarbon source，the Gunan-Fulin unit with single sub-sag and single hydrocarbon source，the Gudao unit with multi-sub-sag and multi-hydrocarbon-source，the south Gudong-west Kendong unit with single sub-sag and multiple hydrocarbon sources. It also indicates that the type and characteristics of different units are determined by multi-migration pathways and petroleum sources of the sub-sags. The research on multi-source supply reservoir-forming units has great exploration significance. On one hand，the remaining resource potential is clear by applying oil-source correlation techniques；on the other hand，the petroleum exploration potential area can be predicted based on the integrated study of migration pathways and directions and trap development laws.
Zhanhua sag has the characteristics of“multi-sub-sag with multi-hydrocarbon-source，multi-stage hydrocarbon charging and accumulation and mixed sources of multi-sub-sag”. In accordance with the above characteristics，based on the division of sub-structural units，from source rocks to petroleum reservoirs，oil-source correlation techniques was applied to analyze and determine the hydrocarbon supplying range of source rocks of different sub-sags，the pathways and processes of hydrocarbon-migrating and the exploration potential of different structural belts. On the basis of the analyses，a composite petroleum accumulation belt with similar sources and migration pathways and reservoir-forming characteristics was defined as a multi-source-supply reservoir-forming unit，and four classifications and seven units were classified and divided totally. The types are single sub-sag with single hydrocarbon source，multi-sub-sag with multi-ydrocarbonsource，single sub-sag with multiple hydrocarbon sources，multi-sub-sag with single hydrocarbon-source，and the units are the Yidong-Chengnan unit with single sub-sag and multiple hydrocarbon sources，the Changdi-north Gudong-Kendong uplift unit with multi-sub-sag and multi-hydrocarbon-source，the Chenjiazhuang-Kenxi unit with single sub-sag and multiple hydrocarbon sources，the Shaojia-Bonnan-Gubei unit with single sub-sag and single hydrocarbon source，the Gunan-Fulin unit with single sub-sag and single hydrocarbon source，the Gudao unit with multi-sub-sag and multi-hydrocarbon-source，the south Gudong-west Kendong unit with single sub-sag and multiple hydrocarbon sources. It also indicates that the type and characteristics of different units are determined by multi-migration pathways and petroleum sources of the sub-sags. The research on multi-source supply reservoir-forming units has great exploration significance. On one hand，the remaining resource potential is clear by applying oil-source correlation techniques；on the other hand，the petroleum exploration potential area can be predicted based on the integrated study of migration pathways and directions and trap development laws.
2015, 22(5):34-39.
Abstract:
Based on the ascertainment of deep traps，the deep gas accumulation conditions of Eboliang-Ⅲstructure in Qaidam Basin was analyzed comprehensively by researching on the gas sources of deep zones，the configuration of the caprock condition and hydrocarbon accumulation. The results show that the Yibei sag is the main gas source for the Eboliang-Ⅲ structure and the properties of the Lower Jurassic hydrocarbon source rocks are medium-good. The Lower Jurassic hydrocarbon source rock suffered high degree of thermal evolution，and mainly generated nature gas. The Lower Jurassic hydrocarbon source rock can supply enough natural gas for the Eboliang-Ⅲstructure deep zones. Both the upper Ganchaigou group and the lower Ganchaigou group are mainly shore-shallow lacustrine deposits and delta deposits，in which clastic res? ervoir rocks developed widely with low porosity and permeability. However，these clastic reservoir rocks have good conditions for deep gas accumulation. Because the deep traps are rounded and have extensional lacustrine deposits from the upper Ganchaigou group to the Youshashan group，the Eboliang -Ⅲdeep zones have good isolated intervals and preservation conditions. The Eboliang -Ⅲdeep zones are good for hydrocarbon accumulation where traps were formed in the lower and trapped hydrocarbons in the upper. There is one of the most important reservoir forming periods from the lower Youshashan group depositional stage to the last Shizigou group depositional stage，which matches the time of structure forming. The deep zones have the feature of late hydrocarbon accumulation. The Eboliang-Ⅲstructure is a favorable target for deep gas prospecting in the north of Qaidam Basin.
Based on the ascertainment of deep traps，the deep gas accumulation conditions of Eboliang-Ⅲstructure in Qaidam Basin was analyzed comprehensively by researching on the gas sources of deep zones，the configuration of the caprock condition and hydrocarbon accumulation. The results show that the Yibei sag is the main gas source for the Eboliang-Ⅲ structure and the properties of the Lower Jurassic hydrocarbon source rocks are medium-good. The Lower Jurassic hydrocarbon source rock suffered high degree of thermal evolution，and mainly generated nature gas. The Lower Jurassic hydrocarbon source rock can supply enough natural gas for the Eboliang-Ⅲstructure deep zones. Both the upper Ganchaigou group and the lower Ganchaigou group are mainly shore-shallow lacustrine deposits and delta deposits，in which clastic res? ervoir rocks developed widely with low porosity and permeability. However，these clastic reservoir rocks have good conditions for deep gas accumulation. Because the deep traps are rounded and have extensional lacustrine deposits from the upper Ganchaigou group to the Youshashan group，the Eboliang -Ⅲdeep zones have good isolated intervals and preservation conditions. The Eboliang -Ⅲdeep zones are good for hydrocarbon accumulation where traps were formed in the lower and trapped hydrocarbons in the upper. There is one of the most important reservoir forming periods from the lower Youshashan group depositional stage to the last Shizigou group depositional stage，which matches the time of structure forming. The deep zones have the feature of late hydrocarbon accumulation. The Eboliang-Ⅲstructure is a favorable target for deep gas prospecting in the north of Qaidam Basin.
2015, 22(5):40-46.
Abstract:
Paleogeomorphology is an important controlling factor on deposition of beach-bar sand bodies. It determines the size and characteristics of beach-bars. In order to analyze its controlling effect on beach-bar deposits，we restored the paleogeomorphology of the LST of SQ2 in the fourth member of Shahejie Formation in Shubei area of Liaohe Western Sag using sequence stratigraphic analysis and impression method by five steps：residual thickness obtaining，true thickness correction，compaction restoration, determination on denudation area of buried hill and paleo-water depth reconstruction. In general，the paleogeomorphology in the study area is high in the west and low in the east. The slope is in the west and the sag is in the east，and the paleo-uplift is in the middle of the slope zone. According to the paleogeomorphology，the Shubei area was divided into five units：coastal zone，buried hill zone，north slope，south slope and sag area. Beach-bars developed mainly along the coastal zone and at the margins of the paleo-uplift. The paleogeomorphology controls the water distribution range and its relative depth，hydrodynamic intensity，sedimentation topography，provenance transport channel and unloading places，all of which affect the deposit of beach-bar sand bodies and further control the development of beach-bar sand bodies.
Paleogeomorphology is an important controlling factor on deposition of beach-bar sand bodies. It determines the size and characteristics of beach-bars. In order to analyze its controlling effect on beach-bar deposits，we restored the paleogeomorphology of the LST of SQ2 in the fourth member of Shahejie Formation in Shubei area of Liaohe Western Sag using sequence stratigraphic analysis and impression method by five steps：residual thickness obtaining，true thickness correction，compaction restoration, determination on denudation area of buried hill and paleo-water depth reconstruction. In general，the paleogeomorphology in the study area is high in the west and low in the east. The slope is in the west and the sag is in the east，and the paleo-uplift is in the middle of the slope zone. According to the paleogeomorphology，the Shubei area was divided into five units：coastal zone，buried hill zone，north slope，south slope and sag area. Beach-bars developed mainly along the coastal zone and at the margins of the paleo-uplift. The paleogeomorphology controls the water distribution range and its relative depth，hydrodynamic intensity，sedimentation topography，provenance transport channel and unloading places，all of which affect the deposit of beach-bar sand bodies and further control the development of beach-bar sand bodies.
2015, 22(5):47-51.
Abstract:
Following the study of braided river reservoir architecture，the flow unit distribution controlled by reservoir architecture becomes more and more important. Taking the braided river reservoir in the Guantao Formation in Dagang A Oilfield for example，the thesis focuses on the method of classifying braided river flow units and their distribution law based on reservoir architecture analysis. Firstly，based on the seepage barrier identification，the connected volume division and seepage variation analysis，as well as considering the reservoir heterogeneity，four parameters including shale index，porosity，FZI（flow zone index）and K/μ were selected to divide the reservoirs into five types ofⅠ，Ⅱ，Ⅲ，ⅣandⅤby using the method of cluster analysis. Secondly，every single well was interpreted and the type of flow unit was identified according to the standard. And the distribution both in plane and on section was studied under the guidance of reservoir architecture and flow unit model using interactive analysis between horizontal and sectional characteristics of flow unit. The results can be concluded as follows：①Horizontally，the core part of channel bar and sand-filling river course are generally served as the well reservoir flow unit. ②Vertically，the flow units in the bottom are generally better reservoirs than those in the upper part，and the type of flow units above and below the interlayers inside of the channel bar does not always remain the same.
Following the study of braided river reservoir architecture，the flow unit distribution controlled by reservoir architecture becomes more and more important. Taking the braided river reservoir in the Guantao Formation in Dagang A Oilfield for example，the thesis focuses on the method of classifying braided river flow units and their distribution law based on reservoir architecture analysis. Firstly，based on the seepage barrier identification，the connected volume division and seepage variation analysis，as well as considering the reservoir heterogeneity，four parameters including shale index，porosity，FZI（flow zone index）and K/μ were selected to divide the reservoirs into five types ofⅠ，Ⅱ，Ⅲ，ⅣandⅤby using the method of cluster analysis. Secondly，every single well was interpreted and the type of flow unit was identified according to the standard. And the distribution both in plane and on section was studied under the guidance of reservoir architecture and flow unit model using interactive analysis between horizontal and sectional characteristics of flow unit. The results can be concluded as follows：①Horizontally，the core part of channel bar and sand-filling river course are generally served as the well reservoir flow unit. ②Vertically，the flow units in the bottom are generally better reservoirs than those in the upper part，and the type of flow units above and below the interlayers inside of the channel bar does not always remain the same.
2015, 22(5):52-57.
Abstract:
Sandstone reservoirs mainly develop in the second member of Shahejie Formation（Es2）in Zhenglizhuang oilfield of Boxing subsag，Dongying sag. Now the reservoir evolution is not clear because of its large vertical change. To solve this problem，core and thin section observation，data from vitrinite reflectance，and grain size of the study area were semi-quantitatively analyzed to determine the impact of reservoir diagenesis on porosity evolution. The study result indicates that the reservoir space of the target stratum is mainly composed of primary intergranular pore and intragranular dissolved pore.And the reservoir porosity evolution is mainly influenced by mechanical compaction，cementation and dissolution，among which the mechanical compaction and cementation reduce the porosity seriously. Compaction decreased the original porosity by 19.8% averagely and cementation decreased the original porosity by 14.1% averagely，which suggests that the original porosity is reduced more seriously by compaction than by cementation，and that compaction plays an important role in the whole process of porosity evolution. Dissolution is an important diagenesis process that improves reservoir pore space and mainly occurred in middle diagenetic stage A. Eventually，dissolution increased the porosity by 2.6%.
Sandstone reservoirs mainly develop in the second member of Shahejie Formation（Es2）in Zhenglizhuang oilfield of Boxing subsag，Dongying sag. Now the reservoir evolution is not clear because of its large vertical change. To solve this problem，core and thin section observation，data from vitrinite reflectance，and grain size of the study area were semi-quantitatively analyzed to determine the impact of reservoir diagenesis on porosity evolution. The study result indicates that the reservoir space of the target stratum is mainly composed of primary intergranular pore and intragranular dissolved pore.And the reservoir porosity evolution is mainly influenced by mechanical compaction，cementation and dissolution，among which the mechanical compaction and cementation reduce the porosity seriously. Compaction decreased the original porosity by 19.8% averagely and cementation decreased the original porosity by 14.1% averagely，which suggests that the original porosity is reduced more seriously by compaction than by cementation，and that compaction plays an important role in the whole process of porosity evolution. Dissolution is an important diagenesis process that improves reservoir pore space and mainly occurred in middle diagenetic stage A. Eventually，dissolution increased the porosity by 2.6%.
2015, 22(5):58-63.
Abstract:
The reform and opening-up of China contributed to rapid economy growth and a significant increase in national power demands. As a consequence of on-going industrialization，China’s energy consumption keeps increasing，forcing China to become more and more dependent on energy imports. This phenomenon gives rise to China’s energy security problem，which revolves around the security of Chinese oil company’s investments abroad，as well as the security of international energy import routes. Both security concerns involve interactions between China and various other nations，making energy security a vital issue for China’s diplomacy. However，the old behavior pattern of China’s diplomatic theories emphasizes the respect of sovereignty and adopts a non-intervention attitude towards the internal affairs of other nations，which，if strictly adhered to，would prohibit China from taking the necessary actions required to protect its own energy interest whenever conflicts or wars break out in regions related to China’s energy security concerns. This article therefore looks into the transition of China’s diplomatic behavior in the Sudan Darfur Humanitarian Crisis and the later civil war in South Sudan. A signal of China’s modification of former behavior pattern can be revealed in these two issues，which implies that China should play a more active and constructive role in protecting its own energy interest.
The reform and opening-up of China contributed to rapid economy growth and a significant increase in national power demands. As a consequence of on-going industrialization，China’s energy consumption keeps increasing，forcing China to become more and more dependent on energy imports. This phenomenon gives rise to China’s energy security problem，which revolves around the security of Chinese oil company’s investments abroad，as well as the security of international energy import routes. Both security concerns involve interactions between China and various other nations，making energy security a vital issue for China’s diplomacy. However，the old behavior pattern of China’s diplomatic theories emphasizes the respect of sovereignty and adopts a non-intervention attitude towards the internal affairs of other nations，which，if strictly adhered to，would prohibit China from taking the necessary actions required to protect its own energy interest whenever conflicts or wars break out in regions related to China’s energy security concerns. This article therefore looks into the transition of China’s diplomatic behavior in the Sudan Darfur Humanitarian Crisis and the later civil war in South Sudan. A signal of China’s modification of former behavior pattern can be revealed in these two issues，which implies that China should play a more active and constructive role in protecting its own energy interest.
2015, 22(5):64-68.
Abstract:
Formation energy in the carbonate fractured-vuggy reservoir becomes less along with the exploitation. Nitrogen flooding can effectively complement the formation energy，and enhance the capacity of production. Only appropriate injection rate，injection timing and injection mode can achieve the best displacement effect of the nitrogen flooding. A visualized physical simulation model of the fractured-vuggy reservoir was designed based on geological structure data and dynamic production data. Influencing factors on nitrogen injection including injection rate，injection timing and injection mode were analyzed when bottom water energy is not enough in laboratory. The results show that the injection rate has great influence on sweep efficiency and gas channeling and the ultimate recovery efficiency would be low under inappropriate injection rate.Injection timing has influence on water flooding and recovery efficiency. If the opportunity of nitrogen injection is too early，water flooding effects will be poor；and if the opportunity of nitrogen injection is too late，nitrogen flooding effects will be poor. Under the condition of recovery efficiency of 20% by water drive，continuous nitrogen injection can improve the recovery efficiency to 47.09%，while alternating injection of water and nitrogen can improve the recovery efficiency to 60.08%，and alternating injection of surfactant water and nitrogen can improve the recovery efficiency to 61.45%.
Formation energy in the carbonate fractured-vuggy reservoir becomes less along with the exploitation. Nitrogen flooding can effectively complement the formation energy，and enhance the capacity of production. Only appropriate injection rate，injection timing and injection mode can achieve the best displacement effect of the nitrogen flooding. A visualized physical simulation model of the fractured-vuggy reservoir was designed based on geological structure data and dynamic production data. Influencing factors on nitrogen injection including injection rate，injection timing and injection mode were analyzed when bottom water energy is not enough in laboratory. The results show that the injection rate has great influence on sweep efficiency and gas channeling and the ultimate recovery efficiency would be low under inappropriate injection rate.Injection timing has influence on water flooding and recovery efficiency. If the opportunity of nitrogen injection is too early，water flooding effects will be poor；and if the opportunity of nitrogen injection is too late，nitrogen flooding effects will be poor. Under the condition of recovery efficiency of 20% by water drive，continuous nitrogen injection can improve the recovery efficiency to 47.09%，while alternating injection of water and nitrogen can improve the recovery efficiency to 60.08%，and alternating injection of surfactant water and nitrogen can improve the recovery efficiency to 61.45%.
2015, 22(5):69-73.
Abstract:
After long-term waterflooding development erosion，large-scale channel is easy to form in the high permeability layers of the unconsolidated sandstone formations in offshore oil reservoirs and the heterogeneity of the layers would be stronger. In this case，foam flooding process alone will lead to the rushing of the foam in the channel，which results in invalid displacement. So it is necessary to take profile control before foam flooding. Through laboratory research，a three-layer heterogeneous core was applied to simulate oil reservoir of high permeability and strong heterogeneity. Foam flooding alone and foam flooding after profile control were implemented. The experimental results show that the ultimate recovery efficiency of the foam flooding after profile control is 18 percent higher than that of the foam flooding alone，and it can reach above 50 percent. More injection volume of the foam slug is better for enhancing oil recovery，and the best injection volume is 0.4 times of the pore volume；for the interlayer heterogeneous core，high strength modified starch gel will plug the high permeability formations，forcing subsequent foam slug to enter the middle-low permeability formations，thus the suction profile will be improved effectively and the recovery efficiency will be greatly improved. The final recovery degree could be increased by 36 percent compared with that after the first time water flooding.
After long-term waterflooding development erosion，large-scale channel is easy to form in the high permeability layers of the unconsolidated sandstone formations in offshore oil reservoirs and the heterogeneity of the layers would be stronger. In this case，foam flooding process alone will lead to the rushing of the foam in the channel，which results in invalid displacement. So it is necessary to take profile control before foam flooding. Through laboratory research，a three-layer heterogeneous core was applied to simulate oil reservoir of high permeability and strong heterogeneity. Foam flooding alone and foam flooding after profile control were implemented. The experimental results show that the ultimate recovery efficiency of the foam flooding after profile control is 18 percent higher than that of the foam flooding alone，and it can reach above 50 percent. More injection volume of the foam slug is better for enhancing oil recovery，and the best injection volume is 0.4 times of the pore volume；for the interlayer heterogeneous core，high strength modified starch gel will plug the high permeability formations，forcing subsequent foam slug to enter the middle-low permeability formations，thus the suction profile will be improved effectively and the recovery efficiency will be greatly improved. The final recovery degree could be increased by 36 percent compared with that after the first time water flooding.
2015, 22(5):74-78.
Abstract:
The favorable synergistic effect of oil displacing agent in alkali-surfactant-polymer（ASP）flooding system can greatly reduce the interfacial tension between oil and water，thus can greatly enhance oil recovery. But the chromatographic separation of ASP flooding system will do great damage to its synergistic effect，which can destroy its integrity. It is important to reveal the chromatographic separation and its influencing factors for improving the oil displacement effect of ASP flooding. Chromatographic separation and its influencing factors of strong-base ASP flooding system were researched in a technical way of chemical analysis and physical simulation guided by reservoir engineering and analytical chemistry theory.The research focuses on geological characteristics and fluid properties of the typical blocks in Daqing. The results show that the sweep volume can be effectively enlarged after using high concentration polymer pre-slug. But the dimensionless dis? tance at the same concentration between surfactant and alkali/polymer is increased，which can make the chromatographic separation phenomenon aggravated. The difference in properties of oil and water of different blocks in Daqing oilfield may have influence on chromatographic separation phenomenon. Because part of heavy alkyl-benzene mahogany acid gets into oil phase，which can influence the concentration measurement value of water phase. In ASP flooding with strong base system，the chromatographic separation degree between surfactant and alkali/polymer is more serious，and that between alkali and polymer is weaker.
The favorable synergistic effect of oil displacing agent in alkali-surfactant-polymer（ASP）flooding system can greatly reduce the interfacial tension between oil and water，thus can greatly enhance oil recovery. But the chromatographic separation of ASP flooding system will do great damage to its synergistic effect，which can destroy its integrity. It is important to reveal the chromatographic separation and its influencing factors for improving the oil displacement effect of ASP flooding. Chromatographic separation and its influencing factors of strong-base ASP flooding system were researched in a technical way of chemical analysis and physical simulation guided by reservoir engineering and analytical chemistry theory.The research focuses on geological characteristics and fluid properties of the typical blocks in Daqing. The results show that the sweep volume can be effectively enlarged after using high concentration polymer pre-slug. But the dimensionless dis? tance at the same concentration between surfactant and alkali/polymer is increased，which can make the chromatographic separation phenomenon aggravated. The difference in properties of oil and water of different blocks in Daqing oilfield may have influence on chromatographic separation phenomenon. Because part of heavy alkyl-benzene mahogany acid gets into oil phase，which can influence the concentration measurement value of water phase. In ASP flooding with strong base system，the chromatographic separation degree between surfactant and alkali/polymer is more serious，and that between alkali and polymer is weaker.
2015, 22(5):79-83.
Abstract:
To seek appropriate technical methods for EOR in offshore deep extra-heavy oil reservoirs，a large-scale model of high temperature and high pressure sand packing was constructed according to the similarity theory and the geological characteristics of LD16-1 oilfield in the Bohai Sea. The physical simulation experiments of steam-assisted gravity drainage （SAGD）and multi-component thermal fluid-assisted gravity drainage（MAGD）were conducted in this sand packed model.Research results show that：MAGD has characters of high production capacity in early stages and fast decline in later production compared with SAGD. The ultimate recovery degree of reserves and cumulative oil-steam ratio has increased by 4.7% and 0.445 respectively. Amounts of injected non-condensate gas（CO2 and N2）may play the role of energy supplement，viscosity reduction，elastic energy increase and interfacial tension reduction. For MAGD technique，the injection temperature is the main controlling factor of the production performance. There is a reasonable gas water ratio since too much gas water ratio brings poorer recovery effect. Increasing injection rate and the proportions of CO2 in the non-condensate gas can improve the recovery effect. In addition，numerical simulation results have 93.19% fitting precision of the physical simulation results in a scaled numerical model.
To seek appropriate technical methods for EOR in offshore deep extra-heavy oil reservoirs，a large-scale model of high temperature and high pressure sand packing was constructed according to the similarity theory and the geological characteristics of LD16-1 oilfield in the Bohai Sea. The physical simulation experiments of steam-assisted gravity drainage （SAGD）and multi-component thermal fluid-assisted gravity drainage（MAGD）were conducted in this sand packed model.Research results show that：MAGD has characters of high production capacity in early stages and fast decline in later production compared with SAGD. The ultimate recovery degree of reserves and cumulative oil-steam ratio has increased by 4.7% and 0.445 respectively. Amounts of injected non-condensate gas（CO2 and N2）may play the role of energy supplement，viscosity reduction，elastic energy increase and interfacial tension reduction. For MAGD technique，the injection temperature is the main controlling factor of the production performance. There is a reasonable gas water ratio since too much gas water ratio brings poorer recovery effect. Increasing injection rate and the proportions of CO2 in the non-condensate gas can improve the recovery effect. In addition，numerical simulation results have 93.19% fitting precision of the physical simulation results in a scaled numerical model.
2015, 22(5):84-88.
Abstract:
ASP flooding technology is being used in the second class reservoirs of Saertu oilfield in Daqing to improve the oil recovery after water flooding. In order to know the mechanism of ASP system driving remaining oil after water flooding，microscopic simulated model was built according to the real pore throat of casting body slice of the natural core and experiment of ASP flooding using this model was performed. The results show that，the main types of remaining oil after water flooding are the cluster type，the film type and the island type. There are also a little blind end type and the throat type. The ultra-low interfacial tension（IFT）and high viscoelasticity enable the ASP system to emulsify oil，drag the oil droplets into oil thread，peel oil film and sweep out the blind end oil，and therefore most of the cluster and the film type oil reduced while the island type oil increased，which improves the oil displacement efficiency. The quantitative analyses of oil displacement effect show that the water displacement efficiency is 50%，while the ASP displacement efficiency is 38.68%. The highest ultimate oil displacement efficiency of the microscopic models is 88.68%. The ultimate oil displacement efficiencies of the four ASP compound systems are all above 77%.
ASP flooding technology is being used in the second class reservoirs of Saertu oilfield in Daqing to improve the oil recovery after water flooding. In order to know the mechanism of ASP system driving remaining oil after water flooding，microscopic simulated model was built according to the real pore throat of casting body slice of the natural core and experiment of ASP flooding using this model was performed. The results show that，the main types of remaining oil after water flooding are the cluster type，the film type and the island type. There are also a little blind end type and the throat type. The ultra-low interfacial tension（IFT）and high viscoelasticity enable the ASP system to emulsify oil，drag the oil droplets into oil thread，peel oil film and sweep out the blind end oil，and therefore most of the cluster and the film type oil reduced while the island type oil increased，which improves the oil displacement efficiency. The quantitative analyses of oil displacement effect show that the water displacement efficiency is 50%，while the ASP displacement efficiency is 38.68%. The highest ultimate oil displacement efficiency of the microscopic models is 88.68%. The ultimate oil displacement efficiencies of the four ASP compound systems are all above 77%.
2015, 22(5):89-93.
Abstract:
Dynamic simulation experiments were operated so as to evaluate the recovery efficiency of the two types of simultaneous water and gas injection（SWAG）systems：the nitrogen-water system and the nitrogen-active water system. Their enhanced oil recovery mechanism and permeability adaptability were probed as well. The result suggests that the mobility reduction factor（MRF）of the nitrogen-water system reduces as permeability rises when it ranges from 5×10-3 to 100×10-3 μm2. The nitrogen-water system can enlarge swept volume and improve recovery efficiency by 35.1%-16.8% after water flooding in the scope of 5×10-3 to 40×10-3 μm2. MRF can be used as a criterion to evaluate the sweep efficiency enlarging ability of SWAG for it matches well with recovery degree. When permeability ranges from 30×10-3 to 500×10-3 μm2，the nitrogen-active water system can improve percolation resistance effectively and enhance recovery degree by 22.6%-19.4% after water flooding. Therefore，the nitrogen-water system can be adapted to the formation with permeability under 40×10-3 μm2，whereas the nitrogen-active water system may be applied to the formation with the permeability between 30×10-3 and 500×10-3 μm2.
Dynamic simulation experiments were operated so as to evaluate the recovery efficiency of the two types of simultaneous water and gas injection（SWAG）systems：the nitrogen-water system and the nitrogen-active water system. Their enhanced oil recovery mechanism and permeability adaptability were probed as well. The result suggests that the mobility reduction factor（MRF）of the nitrogen-water system reduces as permeability rises when it ranges from 5×10-3 to 100×10-3 μm2. The nitrogen-water system can enlarge swept volume and improve recovery efficiency by 35.1%-16.8% after water flooding in the scope of 5×10-3 to 40×10-3 μm2. MRF can be used as a criterion to evaluate the sweep efficiency enlarging ability of SWAG for it matches well with recovery degree. When permeability ranges from 30×10-3 to 500×10-3 μm2，the nitrogen-active water system can improve percolation resistance effectively and enhance recovery degree by 22.6%-19.4% after water flooding. Therefore，the nitrogen-water system can be adapted to the formation with permeability under 40×10-3 μm2，whereas the nitrogen-active water system may be applied to the formation with the permeability between 30×10-3 and 500×10-3 μm2.
2015, 22(5):94-98.
Abstract:
Conventional methods have poor prediction accuracy and can not provide probability distribution characteristics of predicted results for great fluctuation and uncertainty of development indices in later period of oilfield development. A novel prediction method for development indices based on uncertainty research is put forward. This method firstly determines the probability distributions of the influencing factors of index through analyzing the historical production data.Then，a large number of samples for each factor can be produced by random algorithm based on the obtained probability distribution. Finally，the probability distribution of target index is predicted through establishing the quantitative relation between the index and its influencing factors. The injection-production ratio was predicted for H oil production plant by using this novel method. The prediction result for the first six months in 2013 shows that this method has higher prediction precision（the average error is 0.53%）compared to polynomial regression method（the average error is 3.33%）and support vector machine model（the average error is 1.46%）. The range of possible injection-production ratio in January 2013 is from 0.77 to 0.93，and the value of 0.834 3 is the most likely to occur. The novel method for development indices prediction based on uncertainty research provides more reliable basis for oil development decision-making，thus greatly lowers decision-making risk.
Conventional methods have poor prediction accuracy and can not provide probability distribution characteristics of predicted results for great fluctuation and uncertainty of development indices in later period of oilfield development. A novel prediction method for development indices based on uncertainty research is put forward. This method firstly determines the probability distributions of the influencing factors of index through analyzing the historical production data.Then，a large number of samples for each factor can be produced by random algorithm based on the obtained probability distribution. Finally，the probability distribution of target index is predicted through establishing the quantitative relation between the index and its influencing factors. The injection-production ratio was predicted for H oil production plant by using this novel method. The prediction result for the first six months in 2013 shows that this method has higher prediction precision（the average error is 0.53%）compared to polynomial regression method（the average error is 3.33%）and support vector machine model（the average error is 1.46%）. The range of possible injection-production ratio in January 2013 is from 0.77 to 0.93，and the value of 0.834 3 is the most likely to occur. The novel method for development indices prediction based on uncertainty research provides more reliable basis for oil development decision-making，thus greatly lowers decision-making risk.
2015, 22(5):99-102.
Abstract:
Polymer flooding is a tertiary oil recovery technique for EOR after water flooding，which has been applied in different types of oil reservoirs achieving good results. The polymer flooding effect would be affected a lot due to plane heterogeneity in the development. Three kinds of heterogeneous models including permeability，thickness and geometry form were proposed based on the distribution characteristics of the sedimentary micro-facie of certain reservoir. Three types of theoretical reservoir simulation models were built by applying the method of reservoir numerical simulation. The polymer flooding effect of different injection-production patterns was studied under the production conditions of each model. The research result shows that cumulative oil production and initial daily oil production were different at distinct injection-production pattern at the same working system. For the thickness heterogeneity reservoir，the reservoir with injector located in thicker layer and producer located in thinner layer has a better development effect than the contrary pattern. For the permeability heterogeneity reservoir，the reservoir with injector located in higher permeability and producer located in lower permeability has a better development effect than the contrary pattern. For the geometry form heterogeneity reservoir，the reservoir with injector located in narrow zone and producer located in wide zone has a better development effect than the contrary pattern.Injection-production pattern should be optimized to improve development effect of the polymer flooding.
Polymer flooding is a tertiary oil recovery technique for EOR after water flooding，which has been applied in different types of oil reservoirs achieving good results. The polymer flooding effect would be affected a lot due to plane heterogeneity in the development. Three kinds of heterogeneous models including permeability，thickness and geometry form were proposed based on the distribution characteristics of the sedimentary micro-facie of certain reservoir. Three types of theoretical reservoir simulation models were built by applying the method of reservoir numerical simulation. The polymer flooding effect of different injection-production patterns was studied under the production conditions of each model. The research result shows that cumulative oil production and initial daily oil production were different at distinct injection-production pattern at the same working system. For the thickness heterogeneity reservoir，the reservoir with injector located in thicker layer and producer located in thinner layer has a better development effect than the contrary pattern. For the permeability heterogeneity reservoir，the reservoir with injector located in higher permeability and producer located in lower permeability has a better development effect than the contrary pattern. For the geometry form heterogeneity reservoir，the reservoir with injector located in narrow zone and producer located in wide zone has a better development effect than the contrary pattern.Injection-production pattern should be optimized to improve development effect of the polymer flooding.
2015, 22(5):103-106.
Abstract:
Water drive characteristic curve is widely used in the middle-high water cut development stage. However，when oilfield entered extra high water cut period，the water drive characteristic curve will slope upward and an inflection point will occur. Focusing on this phenomenon and according to124 water flooding experiments with high multiple injection （1 000 pore volume），it was found that the fundamental reason for the upward water drive characteristic curve is due to the sharp increase in water permeability，and it was pointed out that the inflection point is an objective existence for the water drive characteristic curve. At the same time，affected by the cumulative effect of water drive characteristic curve，the inflection point can only be found after its appearance，resulting in a delayed estimation on its occurring time. In order to eliminate the influence of the cumulative effect of water flooding characteristic curve on the inflection point estimation，a lgfo-Np formula was derived starting from the first water drive characteristic curve. The cumulative impact of water drive characteristic curve can be overcome by application of this formula to estimate the accurate occurring time of the inflection point.The new method can help to make technical development strategies in time，which lay the foundation for the field to improve the development effect of oilfield production and to guide the practice better.
Water drive characteristic curve is widely used in the middle-high water cut development stage. However，when oilfield entered extra high water cut period，the water drive characteristic curve will slope upward and an inflection point will occur. Focusing on this phenomenon and according to124 water flooding experiments with high multiple injection （1 000 pore volume），it was found that the fundamental reason for the upward water drive characteristic curve is due to the sharp increase in water permeability，and it was pointed out that the inflection point is an objective existence for the water drive characteristic curve. At the same time，affected by the cumulative effect of water drive characteristic curve，the inflection point can only be found after its appearance，resulting in a delayed estimation on its occurring time. In order to eliminate the influence of the cumulative effect of water flooding characteristic curve on the inflection point estimation，a lgfo-Np formula was derived starting from the first water drive characteristic curve. The cumulative impact of water drive characteristic curve can be overcome by application of this formula to estimate the accurate occurring time of the inflection point.The new method can help to make technical development strategies in time，which lay the foundation for the field to improve the development effect of oilfield production and to guide the practice better.
2015, 22(5):107-112.
Abstract:
Single-core plugging and heterogeneous parallel-dual-core flooding tests were carried out to investigate the plugging performance and profile control ability of viscoelastic branched-preformed particle gel（B-PPG）. The results show that B-PPG migrates in the core in a manner of plugging-alternating-pass by deforming and restoring its particles shape alternately. The high permeability channels in the core can be blocked effectively by B-PPG and a high resistance factor and plugging efficiency（higher than 97%）can be achieved. Both the resistance factor and plugging efficiency increase with the increase of the core permeability，B-PPG concentration，and brine salinity；however，both factors decrease with the increase of injection rate and temperature. The water injection profile in the heterogeneous parallel cores can be significantly improved because B-PPG can selectively block high permeability core and divert the displacement to the low permeability core. B-PPG exhibits a good performance in profile control when the high to low permeability ratio of the two parallel cores is smaller than 7.1 and the injected B-PPG slug is between 0.25 to 1.0 PV.
Single-core plugging and heterogeneous parallel-dual-core flooding tests were carried out to investigate the plugging performance and profile control ability of viscoelastic branched-preformed particle gel（B-PPG）. The results show that B-PPG migrates in the core in a manner of plugging-alternating-pass by deforming and restoring its particles shape alternately. The high permeability channels in the core can be blocked effectively by B-PPG and a high resistance factor and plugging efficiency（higher than 97%）can be achieved. Both the resistance factor and plugging efficiency increase with the increase of the core permeability，B-PPG concentration，and brine salinity；however，both factors decrease with the increase of injection rate and temperature. The water injection profile in the heterogeneous parallel cores can be significantly improved because B-PPG can selectively block high permeability core and divert the displacement to the low permeability core. B-PPG exhibits a good performance in profile control when the high to low permeability ratio of the two parallel cores is smaller than 7.1 and the injected B-PPG slug is between 0.25 to 1.0 PV.
2015, 22(5):113-116.
Abstract:
In order to determine the technical and economic boundaries of well pattern adjustment，technical and economic boundaries of well spacing，longitudinal permeability variation coefficient，and thickness and span of layer series combination were studied through dynamic analysis，theoretical calculation，numerical simulation and economic evaluation. The variation waterflood controlling level with well spacing was studied through dynamic analysis. Relationship between recovery efficiency and well spacing was studied using numerical simulation to determine rational well spacing. Limit of permeability variation coefficient was obtained by conceptual model. Rational combination thickness of layer series with different well spacings and oil prices was calculated based on profit and loss balance principle using economic evaluation method.Combination series span was determined through theoretical calculation based on well spacing and combination thickness of layer series. Initial oil rate and water cut after adjustment was calculated using numerical simulation and economic evaluation. Reasonable well spacing of Lazhong block is 150 m，and reasonable combination thickness is 7.5 m. The combination span is 50 m，and the longitudinal permeability variation coefficient is 0.7.
In order to determine the technical and economic boundaries of well pattern adjustment，technical and economic boundaries of well spacing，longitudinal permeability variation coefficient，and thickness and span of layer series combination were studied through dynamic analysis，theoretical calculation，numerical simulation and economic evaluation. The variation waterflood controlling level with well spacing was studied through dynamic analysis. Relationship between recovery efficiency and well spacing was studied using numerical simulation to determine rational well spacing. Limit of permeability variation coefficient was obtained by conceptual model. Rational combination thickness of layer series with different well spacings and oil prices was calculated based on profit and loss balance principle using economic evaluation method.Combination series span was determined through theoretical calculation based on well spacing and combination thickness of layer series. Initial oil rate and water cut after adjustment was calculated using numerical simulation and economic evaluation. Reasonable well spacing of Lazhong block is 150 m，and reasonable combination thickness is 7.5 m. The combination span is 50 m，and the longitudinal permeability variation coefficient is 0.7.
2015, 22(5):117-122.
Abstract:
The importance of shale reservoir microstructure on field appraisal and flow mechanism has become increasingly prominent. But microscopic flow of shale reservoir cannot be studied effectively by conventional laboratory experiments and approaches for the unique characteristics of extra-low permeability，low porosity，serious anisotropy and heterogeneity. Digital core technology has become an important method in studying reservoir microstructure. Reconstruction methods have the accuracy and reliability. Shale core has been reconstructed by using traditional simulated annealing method based on the real shale SEM 2D images and data extracted by software. In order to solve the problem in reconstruction，an approach based on dual-region strategy and very fast simulated annealing（VFSA）algorithm is proposed in this paper. Using the new algorithm makes a significant improvement of computing efficiency. The shale is reconstructed in dual-region due to the pore distribution characteristics of shale. The results show that real pore distribution features are characterized better by this new approach.
The importance of shale reservoir microstructure on field appraisal and flow mechanism has become increasingly prominent. But microscopic flow of shale reservoir cannot be studied effectively by conventional laboratory experiments and approaches for the unique characteristics of extra-low permeability，low porosity，serious anisotropy and heterogeneity. Digital core technology has become an important method in studying reservoir microstructure. Reconstruction methods have the accuracy and reliability. Shale core has been reconstructed by using traditional simulated annealing method based on the real shale SEM 2D images and data extracted by software. In order to solve the problem in reconstruction，an approach based on dual-region strategy and very fast simulated annealing（VFSA）algorithm is proposed in this paper. Using the new algorithm makes a significant improvement of computing efficiency. The shale is reconstructed in dual-region due to the pore distribution characteristics of shale. The results show that real pore distribution features are characterized better by this new approach.
2015, 22(5):123-126.
Abstract:
The screen in open hole，a commonly used new horizontal well completion method，is easy to be polluted and sealed by drilling mud. Foamed acid washing is often used in the cleaning process with a cup-type packer and nitrogen-enriched mixed gas emission，which has the disadvantage of washing unthoroughly and easily falling off the rubber on the cuptype packer. The jet can be produced at high energy pulse through the throttling pipe string for the foam acid washing technology by high pressure water jet. It can effectively remove mud cake and mud pollution in the whole screen section and the flow condition near wellbore can be thoroughly improved. This technology has been applied in16 wells of Gudao oilfield. By the end of June 2015，two to three times of mud and formation pollutants were drained compared to those by traditional acid washing and mixed gas emission. For the steam injection thermal recovery wells，the steam injection pressure decreased more than 1 MPa. The incremental oil of single well was more than 2 tons. The technology has significant production effect.At the same time，the technology can achieve sand control effect by filling outside tube when the conventional well-flushing is used. It can effectively protect the screen in the open hole and the formation outside the tube.
The screen in open hole，a commonly used new horizontal well completion method，is easy to be polluted and sealed by drilling mud. Foamed acid washing is often used in the cleaning process with a cup-type packer and nitrogen-enriched mixed gas emission，which has the disadvantage of washing unthoroughly and easily falling off the rubber on the cuptype packer. The jet can be produced at high energy pulse through the throttling pipe string for the foam acid washing technology by high pressure water jet. It can effectively remove mud cake and mud pollution in the whole screen section and the flow condition near wellbore can be thoroughly improved. This technology has been applied in16 wells of Gudao oilfield. By the end of June 2015，two to three times of mud and formation pollutants were drained compared to those by traditional acid washing and mixed gas emission. For the steam injection thermal recovery wells，the steam injection pressure decreased more than 1 MPa. The incremental oil of single well was more than 2 tons. The technology has significant production effect.At the same time，the technology can achieve sand control effect by filling outside tube when the conventional well-flushing is used. It can effectively protect the screen in the open hole and the formation outside the tube.
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