Volume 28,Issue 2,2021 Table of Contents
2021, 28(2):1-9.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.001
Abstract:
In the past dozen years，microbial enhanced oil recovery（MEOR）technology has boomed mainly for two reasons.First，the application of 16S rRNA-based microbial ecological analysis technology，especially the application of highthroughput sequencing technology has realized the fast and accurate analysis of the microbial community structure and dynamic evolution laws in extreme environments of oil reservoirs. Second，the application of chemical flooding technology dominated by polymer flooding has crossed its peak period，and the number of oil reservoirs suitable for chemical flooding is decreasing. MEOR technology has drawn second attention due to the urgent demand for replacement technology. The development of MOR technology and production requirements have led to the rapid development of theoretical research and field trials of this technology，and its application process has also undergone tremendous changes compared with the previous one. With the expansion of the scale and time of field trials，the mechanism of MEOR technology has been further clarified，and a consensus has been formed with emulsification and gas production as the dominant mechanism. However，the advantages of this technology have not been fully utilized in field application，and the realization of large-scale industrial application still faces many problems，mainly the precise regulation of the microbial ecological function in oil reservoirs and further research and improvement on the supporting technology of microbial oil recovery.
In the past dozen years，microbial enhanced oil recovery（MEOR）technology has boomed mainly for two reasons.First，the application of 16S rRNA-based microbial ecological analysis technology，especially the application of highthroughput sequencing technology has realized the fast and accurate analysis of the microbial community structure and dynamic evolution laws in extreme environments of oil reservoirs. Second，the application of chemical flooding technology dominated by polymer flooding has crossed its peak period，and the number of oil reservoirs suitable for chemical flooding is decreasing. MEOR technology has drawn second attention due to the urgent demand for replacement technology. The development of MOR technology and production requirements have led to the rapid development of theoretical research and field trials of this technology，and its application process has also undergone tremendous changes compared with the previous one. With the expansion of the scale and time of field trials，the mechanism of MEOR technology has been further clarified，and a consensus has been formed with emulsification and gas production as the dominant mechanism. However，the advantages of this technology have not been fully utilized in field application，and the realization of large-scale industrial application still faces many problems，mainly the precise regulation of the microbial ecological function in oil reservoirs and further research and improvement on the supporting technology of microbial oil recovery.
2021, 28(2):10-17.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.002
Abstract:
The microbial oil enhanced recovery technology in Daqing Oilfield has been put into operation since the 1960s.More than 50 years of sustained efforts has witnessed encouraging progress in basic research and field applications. The study found that microorganisms actively migrated to crude oil，adhered to it，or produced surfactant to emulsify it. Besides，it was determined that the alkanes and aromatic hydrocarbons were degraded by experimental strains through oxidation. On the basis of laboratory research，field tests on exogenous microorganisms were carried out in extra-low permeability reservoirs，and 93 wells were subject to microbial huff-n-puff tests. Results demonstrate that the average oil increase per well was 149 t，and the cost of bacteria solution and activators per ton of oil increase was CNY 300. In addition，the microbial flooding tests in extra-low permeability reservoirs proved that the accumulative oil increase in Chaoyanggou Oilfield was 60 000 t，with the enhanced oil recovery of 4.95%，and the cost of bacteria solution and activators per ton of oil increase was CNY 557. In particular，it is clarified that the injection-production system was the main factor affecting the microbial flooding. The microbial community structure of typical reservoirs after water flooding，polymer flooding，and combined flooding in Daqing Oilfield were systematically studied to develop highly effective activators. Endogenous microorganism flooding tests with 1 injector and 4 producers in reservoirs after polymer flooding were carried out in Sanan Oilfield，which enhanced the oil recovery by 3.93%，and the activator cost per ton of oil increase was CNY 643.
The microbial oil enhanced recovery technology in Daqing Oilfield has been put into operation since the 1960s.More than 50 years of sustained efforts has witnessed encouraging progress in basic research and field applications. The study found that microorganisms actively migrated to crude oil，adhered to it，or produced surfactant to emulsify it. Besides，it was determined that the alkanes and aromatic hydrocarbons were degraded by experimental strains through oxidation. On the basis of laboratory research，field tests on exogenous microorganisms were carried out in extra-low permeability reservoirs，and 93 wells were subject to microbial huff-n-puff tests. Results demonstrate that the average oil increase per well was 149 t，and the cost of bacteria solution and activators per ton of oil increase was CNY 300. In addition，the microbial flooding tests in extra-low permeability reservoirs proved that the accumulative oil increase in Chaoyanggou Oilfield was 60 000 t，with the enhanced oil recovery of 4.95%，and the cost of bacteria solution and activators per ton of oil increase was CNY 557. In particular，it is clarified that the injection-production system was the main factor affecting the microbial flooding. The microbial community structure of typical reservoirs after water flooding，polymer flooding，and combined flooding in Daqing Oilfield were systematically studied to develop highly effective activators. Endogenous microorganism flooding tests with 1 injector and 4 producers in reservoirs after polymer flooding were carried out in Sanan Oilfield，which enhanced the oil recovery by 3.93%，and the activator cost per ton of oil increase was CNY 643.
2021, 28(2):18-26.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.003
Abstract:
More than 20 years of laboratory experiments and field trials have yielded in-depth understanding of the mechanism and a comprehensive system for the microbial enhanced oil recovery（MEOR）technology in Shengli Oilfield，and the technology has been applied to industrial production. The dominant EOR mechanisms，such as microbial interface tropism，hydrocarbon-philic emulsification，and interface wetting modification have been studied thoroughly and characterized quantitatively，pointing out a direction for the transformation and regulation of bacterial species（groups）. We have established a MEOR system integrating molecular biological analysis of flora structure in reservoirs，activation and regulation of functional bacteria for oil production，and three-dimensional physical simulation of oil displacement. The MEOR field trials develop from single well huff-n-puff to microbial flooding and from the single investigation of exogenous microorganisms to the comprehensive study of both endogenous and exogenous microorganisms. In recent years，the adaptability of this technology in reservoirs has been greatly improved through the combination of MEOR and other EOR technologies. At the moment，it has embarked on transformation from pilot tests to industrial applications. As of December 2019，MEOR was applied to the 10 zones in Shengli Oilfield，with a cumulative oil increase of 30×104 t. Besides the effective MEOR field trials in heavy oil reservoirs of Block Zhan3 which was used to be exploited by conventional water-flooding，the MEOR have been made breakthroughs in a high-temperature and high-salinity heavy oil reservoir of Block Xin68 and a heavy oil reservoir subject to inefficient thermal recovery of Block Cao13. For different types of heavy oil reservoirs，complex huff-n-puff technologies，such as those for microbial compound gas，have been developed，enabling a wider application of microbial single well huff-n-puff technology. As of December 2019，MEOR technology had been applied in more than 400 oil wells with single well huff-n-puff，with a cumulative oil increase of 8×104 t.
More than 20 years of laboratory experiments and field trials have yielded in-depth understanding of the mechanism and a comprehensive system for the microbial enhanced oil recovery（MEOR）technology in Shengli Oilfield，and the technology has been applied to industrial production. The dominant EOR mechanisms，such as microbial interface tropism，hydrocarbon-philic emulsification，and interface wetting modification have been studied thoroughly and characterized quantitatively，pointing out a direction for the transformation and regulation of bacterial species（groups）. We have established a MEOR system integrating molecular biological analysis of flora structure in reservoirs，activation and regulation of functional bacteria for oil production，and three-dimensional physical simulation of oil displacement. The MEOR field trials develop from single well huff-n-puff to microbial flooding and from the single investigation of exogenous microorganisms to the comprehensive study of both endogenous and exogenous microorganisms. In recent years，the adaptability of this technology in reservoirs has been greatly improved through the combination of MEOR and other EOR technologies. At the moment，it has embarked on transformation from pilot tests to industrial applications. As of December 2019，MEOR was applied to the 10 zones in Shengli Oilfield，with a cumulative oil increase of 30×104 t. Besides the effective MEOR field trials in heavy oil reservoirs of Block Zhan3 which was used to be exploited by conventional water-flooding，the MEOR have been made breakthroughs in a high-temperature and high-salinity heavy oil reservoir of Block Xin68 and a heavy oil reservoir subject to inefficient thermal recovery of Block Cao13. For different types of heavy oil reservoirs，complex huff-n-puff technologies，such as those for microbial compound gas，have been developed，enabling a wider application of microbial single well huff-n-puff technology. As of December 2019，MEOR technology had been applied in more than 400 oil wells with single well huff-n-puff，with a cumulative oil increase of 8×104 t.
LI Caifeng
,
SHU Qinglin
,
HAN Baofeng
,
CAO Yanbin
,
WANG Weidong
,
SONG Yongting
,
LI Fengbing
,
ZHANG Yong
2021, 28(2):27-33.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.004
Abstract:
The Geobacillus stearothermophilus SL-1（referred to as SL-1）is a hydrocarbonophilic emulsifying bacterium isolated from oil reservoir environment. It has strong emulsifying ability for hydrocarbons，with the suitable growth temperature at 65-70 ℃. The oil displacement mechanism and growth law of SL-1 bacteria in porous media were studied by a microscopic visual model and a core sand-packed model. Results demonstrate that in the high-temperature and high-pressure reservoir environment，the addition of SL-1 bacteria can change the wettability of the pore wall，emulsify film-like oil，and strip blind end oil，compared with single activator system for endogenous bacteria in the blank control group. Besides，residual oil displacement is significantly enhanced after the secondary water flooding. Physical simulations of oil displacement show that the combination of exogenous and endogenous bacteria can enhance oil recovery by up to 13.5%，followed by 8.8% with the only endogenous bacteria and 7.2% with the only exogenous bacteria. The number of microorganisms in the combined system of exogenous and endogenous bacteria is the highest，with the gene copy number of about 109 copies/mL，followed by that in the system with only endogenous bacteria about 107 copies/mL，and then that in the system with only exogenous bacteria about 102 copies/mL. Geobacillus has always been activated to be one of the dominant bacteria in the culture solution during four rounds of injection，and its concentration in the produced fluid is negatively correlated with the residual oil saturation of core. It reveals that the hydrocarbonophilic emulsifying bacteria have an important role in increasing the number of microorganisms and enhancing microbial oil displacement in the reservoir environment.
The Geobacillus stearothermophilus SL-1（referred to as SL-1）is a hydrocarbonophilic emulsifying bacterium isolated from oil reservoir environment. It has strong emulsifying ability for hydrocarbons，with the suitable growth temperature at 65-70 ℃. The oil displacement mechanism and growth law of SL-1 bacteria in porous media were studied by a microscopic visual model and a core sand-packed model. Results demonstrate that in the high-temperature and high-pressure reservoir environment，the addition of SL-1 bacteria can change the wettability of the pore wall，emulsify film-like oil，and strip blind end oil，compared with single activator system for endogenous bacteria in the blank control group. Besides，residual oil displacement is significantly enhanced after the secondary water flooding. Physical simulations of oil displacement show that the combination of exogenous and endogenous bacteria can enhance oil recovery by up to 13.5%，followed by 8.8% with the only endogenous bacteria and 7.2% with the only exogenous bacteria. The number of microorganisms in the combined system of exogenous and endogenous bacteria is the highest，with the gene copy number of about 109 copies/mL，followed by that in the system with only endogenous bacteria about 107 copies/mL，and then that in the system with only exogenous bacteria about 102 copies/mL. Geobacillus has always been activated to be one of the dominant bacteria in the culture solution during four rounds of injection，and its concentration in the produced fluid is negatively correlated with the residual oil saturation of core. It reveals that the hydrocarbonophilic emulsifying bacteria have an important role in increasing the number of microorganisms and enhancing microbial oil displacement in the reservoir environment.
2021, 28(2):34-40.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.005
Abstract:
To improve the accuracy and stability of the calculation of numerical simulation software for microbial enhanced oil recovery，we introduced a new model equation for microbial migration that reflects the influence of inaccessible pore volume，adsorption，and screening effect on the distribution of microorganisms in the reservoirs based on the previous experimental results on the migration and retention of microorganisms. Then，a one-dimensional，two-phase（oil and gas），and three-component（microorganisms，nutrients，and metabolites）mathematical model for microbial enhanced oil recovery was constructed. Through programming，the process of microbial enhanced oil recovery was simulated for the sensitivity analysis of inaccessible pore volume，adsorption，and screening effect. Consequently，the model could simulate the process of microbial enhanced oil recovery which is sensitive to inaccessible pore volume，adsorption，and screening effect. These parameters could be introduced for the accurate prediction of microbial concentration distribution，water cut，and recovery，offering a numerical simulation method to the preparation of construction schemes for microbial enhanced oil recovery.
To improve the accuracy and stability of the calculation of numerical simulation software for microbial enhanced oil recovery，we introduced a new model equation for microbial migration that reflects the influence of inaccessible pore volume，adsorption，and screening effect on the distribution of microorganisms in the reservoirs based on the previous experimental results on the migration and retention of microorganisms. Then，a one-dimensional，two-phase（oil and gas），and three-component（microorganisms，nutrients，and metabolites）mathematical model for microbial enhanced oil recovery was constructed. Through programming，the process of microbial enhanced oil recovery was simulated for the sensitivity analysis of inaccessible pore volume，adsorption，and screening effect. Consequently，the model could simulate the process of microbial enhanced oil recovery which is sensitive to inaccessible pore volume，adsorption，and screening effect. These parameters could be introduced for the accurate prediction of microbial concentration distribution，water cut，and recovery，offering a numerical simulation method to the preparation of construction schemes for microbial enhanced oil recovery.
6 Effects of reservoir physical properties and recoveries on oil displacement of endogenous microbes
SUN Gangzheng
,
HU Jing
,
LIU Tao
,
GUO Liaoyuan
,
WANG Xiaofang
,
WU Xiaoling
,
CAO Gongze
,
WANG Weidong
2021, 28(2):41-48.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.006
Abstract:
Reservoir physical properties and recoveries have a significant impact on the implementation of the endogenous microbial oil displacement technology. However，systematic laboratory research has been lacking in this field，and this technology has been in need of scientific screening criteria of reservoirs. On the basis of Gudong Block 51-511 in Shengli Oilfield，the effects of permeability，surface crude oil viscosity，recovery and heterogeneity on the oil displacement of endogenous microbes were quantitatively studied by physical simulations. When permeability is 50-4 000 mD，the enhanced oil recovery first increases and then decreases. As permeability is 500 mD，the oil displacement effect is the best，and the enhanced oil recovery reaches 6.6%. When the surface crude oil viscosity is within 35-5 371 mPa·s，as the viscosity of crude oil grows，the enhanced oil recovery first rises and then declines. When the surface crude oil viscosity is 1 148 mPa·s，the enhanced oil recovery is the highest，reaching 8.8%. When the recovery is 10%-50%，as it increases，the enhanced oil recovery gradually drops（from 12% to 2%）. When the permeability difference is 2-20，the enhanced oil recovery will decline over time（from 7.3% to 3.2%）as the permeability difference rises. Then the screening criteria of reservoirs with endogenous microbial oil displacement technology are established，and the optimal ranges of key parameters are defined from reservoir，biological，and development indicators. This paper can serve as scientific theoretical reference for reservoir screening by endogenous microbial oil displacement and guide the field implementation.
Reservoir physical properties and recoveries have a significant impact on the implementation of the endogenous microbial oil displacement technology. However，systematic laboratory research has been lacking in this field，and this technology has been in need of scientific screening criteria of reservoirs. On the basis of Gudong Block 51-511 in Shengli Oilfield，the effects of permeability，surface crude oil viscosity，recovery and heterogeneity on the oil displacement of endogenous microbes were quantitatively studied by physical simulations. When permeability is 50-4 000 mD，the enhanced oil recovery first increases and then decreases. As permeability is 500 mD，the oil displacement effect is the best，and the enhanced oil recovery reaches 6.6%. When the surface crude oil viscosity is within 35-5 371 mPa·s，as the viscosity of crude oil grows，the enhanced oil recovery first rises and then declines. When the surface crude oil viscosity is 1 148 mPa·s，the enhanced oil recovery is the highest，reaching 8.8%. When the recovery is 10%-50%，as it increases，the enhanced oil recovery gradually drops（from 12% to 2%）. When the permeability difference is 2-20，the enhanced oil recovery will decline over time（from 7.3% to 3.2%）as the permeability difference rises. Then the screening criteria of reservoirs with endogenous microbial oil displacement technology are established，and the optimal ranges of key parameters are defined from reservoir，biological，and development indicators. This paper can serve as scientific theoretical reference for reservoir screening by endogenous microbial oil displacement and guide the field implementation.
2021, 28(2):49-59.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.007
Abstract:
To reveal the influence of overpressure on hydrocarbon migration and accumulation in Linnan Subsag and clarify its control on hydrocarbon enrichment，we restored the dynamic evolution of the paleo-pressure field based on the static pressure field tracking geological blocks and analyzed the relationship of overpressure with hydrocarbon migration and accumulation. The results reveal that the pressure field of Linnan Subsag presents as atmospheric pressure，weak overpressure，and overpressure in the zones of uplift，slope，and subsag，respectively. The overpressure of Es3 is evident，followed by that of Es4. The overpressure evolves in a cycle of early low amplitude pressurization（the depositional periods of Es1-Ed），uplift pressure relief（the depositional periods of Ed）and late rapid pressurization（the depositional periods of Ng-Q）. Now it is in the most distinct stage of overpressure，and the overpressure center is located in the sedimentary center of subsag. A comprehensive analysis of hydrocarbon migration and accumulation clarifies that the abnormal high pressure in the Es3 in Linnan subsag contains the generation and migration of oil and gas. During the deposition period from Guantao Formation to Minghuazhen Formation，the rapid increase in oil potential dominates the migration directions and favorable accumulation positions of oil and gas.
To reveal the influence of overpressure on hydrocarbon migration and accumulation in Linnan Subsag and clarify its control on hydrocarbon enrichment，we restored the dynamic evolution of the paleo-pressure field based on the static pressure field tracking geological blocks and analyzed the relationship of overpressure with hydrocarbon migration and accumulation. The results reveal that the pressure field of Linnan Subsag presents as atmospheric pressure，weak overpressure，and overpressure in the zones of uplift，slope，and subsag，respectively. The overpressure of Es3 is evident，followed by that of Es4. The overpressure evolves in a cycle of early low amplitude pressurization（the depositional periods of Es1-Ed），uplift pressure relief（the depositional periods of Ed）and late rapid pressurization（the depositional periods of Ng-Q）. Now it is in the most distinct stage of overpressure，and the overpressure center is located in the sedimentary center of subsag. A comprehensive analysis of hydrocarbon migration and accumulation clarifies that the abnormal high pressure in the Es3 in Linnan subsag contains the generation and migration of oil and gas. During the deposition period from Guantao Formation to Minghuazhen Formation，the rapid increase in oil potential dominates the migration directions and favorable accumulation positions of oil and gas.
2021, 28(2):60-67.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.008
Abstract:
The formation mechanism and hydrocarbon accumulation control of the transtensional structure in the study area are studied comprehensively with geologic and geophysical and numerical simulation methods with qualitative analysis and quantitative evaluation to improve the understanding of the development and evolution mechanism of the transtensional structure and its effect on the controlling factors of hydrocarbon accumulation in Linnan area. Results demonstrate that the Linnan area first stretches obliquely due to extensional force，and then a typical transtensional structure is formed because the reactivated basement fault strike is oblique to the extension direction of the area. Considering horizontal extension，vertical block faulting and lateral strike-slip movement，a quantitative characterization method of the transtensional structure are established. The average intensity of transtensional activity is about 0.4. The reservoir development is obviously controlled by the extensional structure. Three sand control modes of gentle slopes with stable subsidence，continuous migration and subsidence and slopes with synsedimentary faults affect the formation of different traps. The accumulation modes of dynamic equilibrium in the transtensional fault zone，lateral migration in the slope zone and self-generation and self-storage in the sag zone are established according to the four structures of fault zones，namely ternary，binary，unitary and unstructured modes.
The formation mechanism and hydrocarbon accumulation control of the transtensional structure in the study area are studied comprehensively with geologic and geophysical and numerical simulation methods with qualitative analysis and quantitative evaluation to improve the understanding of the development and evolution mechanism of the transtensional structure and its effect on the controlling factors of hydrocarbon accumulation in Linnan area. Results demonstrate that the Linnan area first stretches obliquely due to extensional force，and then a typical transtensional structure is formed because the reactivated basement fault strike is oblique to the extension direction of the area. Considering horizontal extension，vertical block faulting and lateral strike-slip movement，a quantitative characterization method of the transtensional structure are established. The average intensity of transtensional activity is about 0.4. The reservoir development is obviously controlled by the extensional structure. Three sand control modes of gentle slopes with stable subsidence，continuous migration and subsidence and slopes with synsedimentary faults affect the formation of different traps. The accumulation modes of dynamic equilibrium in the transtensional fault zone，lateral migration in the slope zone and self-generation and self-storage in the sag zone are established according to the four structures of fault zones，namely ternary，binary，unitary and unstructured modes.
2021, 28(2):68-75.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.009
Abstract:
It is difficult to establish a geothermal field for geothermal energy development in the central uplift belt of a graben basin. In this paper，the geothermal field is established through wellbore thermometry as well as SiO2，K-Mg，and NaK geothermometers to identify the controlling factors of its distribution and clarify its development model. The results show that Es2-Q in the central uplift belt of Dongying Sag can be divided into the surface variable temperature zone，the first thermal warming and thermal insulation zone，the second thermal warming and thermal insulation zone，the third thermal warming and thermal insulation zone. Geotemperature is calculated with SiO2，K-Mg，and Na-K geothermometers. Based on the geological research in stratigraphic correlation，structure，reservoirs and well logging in the study area，six sand formations are divided vertically and the geological model of the temperature field is established with the temperature measurements and laboratory data. It is found that the geothermal gradient is dominated by the plastic materials at the bottom of the central uplift belt，the patterns of main faults，lithology，stratigraphic horizon and thickness ratios of sand/mud. A geothermal system development model of the central uplift belt that consist with a thermal expansion zone，a high temperature fracture zone，a high temperature compact zone，a medium temperature compact zone，a medium temperature hot-water zone，a low temperature hot-water zone and a seal zone is introduced according to the geothermal genesis and development characteristics，temperature，and water yield.Besides，the genesis of geothermal system is analyzed from heat sources，cap rocks，thermal reservoirs，heat flow channels，and sealing.
It is difficult to establish a geothermal field for geothermal energy development in the central uplift belt of a graben basin. In this paper，the geothermal field is established through wellbore thermometry as well as SiO2，K-Mg，and NaK geothermometers to identify the controlling factors of its distribution and clarify its development model. The results show that Es2-Q in the central uplift belt of Dongying Sag can be divided into the surface variable temperature zone，the first thermal warming and thermal insulation zone，the second thermal warming and thermal insulation zone，the third thermal warming and thermal insulation zone. Geotemperature is calculated with SiO2，K-Mg，and Na-K geothermometers. Based on the geological research in stratigraphic correlation，structure，reservoirs and well logging in the study area，six sand formations are divided vertically and the geological model of the temperature field is established with the temperature measurements and laboratory data. It is found that the geothermal gradient is dominated by the plastic materials at the bottom of the central uplift belt，the patterns of main faults，lithology，stratigraphic horizon and thickness ratios of sand/mud. A geothermal system development model of the central uplift belt that consist with a thermal expansion zone，a high temperature fracture zone，a high temperature compact zone，a medium temperature compact zone，a medium temperature hot-water zone，a low temperature hot-water zone and a seal zone is introduced according to the geothermal genesis and development characteristics，temperature，and water yield.Besides，the genesis of geothermal system is analyzed from heat sources，cap rocks，thermal reservoirs，heat flow channels，and sealing.
2021, 28(2):76-84.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.010
Abstract:
T-R sequence framework of Meishan Formation in Ledong Sag，Qiongdongnan Basin was established and its evolution process of submarine fan deposits was discussed in detail according to the comprehensive analysis of 3D seismic and drilling data，combined with the rising and falling characteristics of regional sea level. Results reveal that five large-scale transgression-regressive cycle events happened in the study area during the middle Miocene，and the source of main clastic materials in Ledong Sag migrated from Hainan Uplift in the early stage to Vietnam in the late stage. During this process，three stages of large submarine fan deposits with different distribution directions and scales were formed in Ledong Sag.Combined with the controlling factors of regional oil and gas accumulation，it is believed that the submarine fan sandstone of Meishan Formation was cut by the central Canyon of Huangliu Formation in the late period；the composite lithologic traps of Meishan Formation submarine fan-Huangliu Formation channel sandstone were formed under the overall mud-sand sedimentary background，which communicated with deep source rocks of Yancheng Formation through diapirs and fractures，forming“lower generation and upper reservoir”type lithologic reservoirs.Under the guidance of this understanding，the composite lithologic traps of Meishan Formation submarine fan-Huangliu Formation channel sandstone have been successfully drilled，with proved natural gas reserves of nearly 100×108 m3.
T-R sequence framework of Meishan Formation in Ledong Sag，Qiongdongnan Basin was established and its evolution process of submarine fan deposits was discussed in detail according to the comprehensive analysis of 3D seismic and drilling data，combined with the rising and falling characteristics of regional sea level. Results reveal that five large-scale transgression-regressive cycle events happened in the study area during the middle Miocene，and the source of main clastic materials in Ledong Sag migrated from Hainan Uplift in the early stage to Vietnam in the late stage. During this process，three stages of large submarine fan deposits with different distribution directions and scales were formed in Ledong Sag.Combined with the controlling factors of regional oil and gas accumulation，it is believed that the submarine fan sandstone of Meishan Formation was cut by the central Canyon of Huangliu Formation in the late period；the composite lithologic traps of Meishan Formation submarine fan-Huangliu Formation channel sandstone were formed under the overall mud-sand sedimentary background，which communicated with deep source rocks of Yancheng Formation through diapirs and fractures，forming“lower generation and upper reservoir”type lithologic reservoirs.Under the guidance of this understanding，the composite lithologic traps of Meishan Formation submarine fan-Huangliu Formation channel sandstone have been successfully drilled，with proved natural gas reserves of nearly 100×108 m3.
2021, 28(2):85-90.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.011
Abstract:
Conventional edge detection technology can recognize boundaries of faults，fractures and sand bodies，but it is difficult to meet the demands of description of the boundary response of the geological bodies in different scales. To this end，an integrated multi-scale edge detection technology is proposed to precisely identify small faults and fracture zones，which combines three-parameter wavelet transform with a structure-oriented gradient operator，with dip volume and azimuth volume as constraints. The faulted-block reservoirs and Carboniferous weathering crust fractured reservoirs are dominant in Block Well P691 of Chepaizi area，western margin of Junggar Basin. However，limited by the poor seismic data，conventional methods cannot accurately identify faults and predict fracture development. Application results demonstrate that the designed technology can recognize small faults and predict fracture zones on the basis of accurate location of edges and multi-scale detection. Large and small faults and fracture zones can be clearly identified on the large-scale，mesoscale and small-scale edge detection maps，proving the effectiveness of this technique.
Conventional edge detection technology can recognize boundaries of faults，fractures and sand bodies，but it is difficult to meet the demands of description of the boundary response of the geological bodies in different scales. To this end，an integrated multi-scale edge detection technology is proposed to precisely identify small faults and fracture zones，which combines three-parameter wavelet transform with a structure-oriented gradient operator，with dip volume and azimuth volume as constraints. The faulted-block reservoirs and Carboniferous weathering crust fractured reservoirs are dominant in Block Well P691 of Chepaizi area，western margin of Junggar Basin. However，limited by the poor seismic data，conventional methods cannot accurately identify faults and predict fracture development. Application results demonstrate that the designed technology can recognize small faults and predict fracture zones on the basis of accurate location of edges and multi-scale detection. Large and small faults and fracture zones can be clearly identified on the large-scale，mesoscale and small-scale edge detection maps，proving the effectiveness of this technique.
2021, 28(2):91-99.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.012
Abstract:
The difference in oil-water flow and the dispersion and enrichment of remaining oil in water drive reservoirs at an ultra-high water cut stage are becoming increasingly serious. To formulate an efficient dynamic development strategy for reservoir on a large scale，we propose a dynamic tracking model of flow field boundaries based on the idea of interface reconstruction，and predict the evolution laws of the interfaces with differences in velocity and saturation of two-dimensional and three-dimensional flow fields. Also，we conduct a test for the quantitative characterization of the high-velocity and high water-cut flow field boundaries in reservoir blocks at an ultra-high water-cut stage，and verify the feasibility of its engineering application with development strategies. With the classic black-oil model and the dynamic flow-line tracking equation，we introduce the idea of interface reconstruction to the multiphase interface tracking method，devising a set of quantitative characterization methods for flow field boundaries considering dynamic and static factors. Combining the interfaces with differences in flow velocity and water saturation of two-dimensional flow fields and those with differences in flow velocity and oil saturation of three-dimensional flow fields，we divide reservoir flow fields into a high-velocity oil displacement area，a high-velocity water consumption area，a low-velocity water-rich area，and a low-velocity oil-rich area. This model can track the dynamic process of flow field boundaries from birth to development，and then to stabilization，and its feasibility is verified by the test on the application of the development strategy.
The difference in oil-water flow and the dispersion and enrichment of remaining oil in water drive reservoirs at an ultra-high water cut stage are becoming increasingly serious. To formulate an efficient dynamic development strategy for reservoir on a large scale，we propose a dynamic tracking model of flow field boundaries based on the idea of interface reconstruction，and predict the evolution laws of the interfaces with differences in velocity and saturation of two-dimensional and three-dimensional flow fields. Also，we conduct a test for the quantitative characterization of the high-velocity and high water-cut flow field boundaries in reservoir blocks at an ultra-high water-cut stage，and verify the feasibility of its engineering application with development strategies. With the classic black-oil model and the dynamic flow-line tracking equation，we introduce the idea of interface reconstruction to the multiphase interface tracking method，devising a set of quantitative characterization methods for flow field boundaries considering dynamic and static factors. Combining the interfaces with differences in flow velocity and water saturation of two-dimensional flow fields and those with differences in flow velocity and oil saturation of three-dimensional flow fields，we divide reservoir flow fields into a high-velocity oil displacement area，a high-velocity water consumption area，a low-velocity water-rich area，and a low-velocity oil-rich area. This model can track the dynamic process of flow field boundaries from birth to development，and then to stabilization，and its feasibility is verified by the test on the application of the development strategy.
2021, 28(2):100-108.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.013
Abstract:
Some low permeability reservoirs in China have been effectively developed by water flooding，but with insufficient sweep. Thus，it is urgent to study the evaluation method of water-flooding plane sweep. The flow tube model is a good method for rapid evaluation of water-flooding plane sweep coefficient. An improved flow tube model that considers the threshold pressure gradient，anisotropy，artificial fracture，non-piston displacement，and irregular well pattern was developed. A fast calculation module for the water-flooding plane sweep of low permeability reservoirs was created，based on the modified flow tube model，to study the influence of well patterns，well array ratios，and anisotropy on the water-flooding plane sweep coefficient. Consequently，unsuccessful water injection into injectors and oil production from producers can be attributable mainly to poor physical properties of low permeability reservoirs and threshold pressure gradient. An optimal well array ratio can be found under different anisotropies，and the optimization chart in different well array ratios in low permeability reservoirs is proposed. During the production process，attention should be paid to the perfection of the well pattern and the in-time filling of holes to improve the injection-production correspondence.
Some low permeability reservoirs in China have been effectively developed by water flooding，but with insufficient sweep. Thus，it is urgent to study the evaluation method of water-flooding plane sweep. The flow tube model is a good method for rapid evaluation of water-flooding plane sweep coefficient. An improved flow tube model that considers the threshold pressure gradient，anisotropy，artificial fracture，non-piston displacement，and irregular well pattern was developed. A fast calculation module for the water-flooding plane sweep of low permeability reservoirs was created，based on the modified flow tube model，to study the influence of well patterns，well array ratios，and anisotropy on the water-flooding plane sweep coefficient. Consequently，unsuccessful water injection into injectors and oil production from producers can be attributable mainly to poor physical properties of low permeability reservoirs and threshold pressure gradient. An optimal well array ratio can be found under different anisotropies，and the optimization chart in different well array ratios in low permeability reservoirs is proposed. During the production process，attention should be paid to the perfection of the well pattern and the in-time filling of holes to improve the injection-production correspondence.
2021, 28(2):109-118.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.014
Abstract:
Foam flooding，as an effective way to improve oil recovery，has been widely used in major oil fields in China. It is found from numerous field applications that suitable injection parameters can give the fluidity control ability of foam flooding to full play. APG-10 was selected as foaming agent，DG as foam stabilizer，and natural gas as gas phase to prepare natural gas foam. Orthogonal experiments with regards to mass concentration of foaming agent，mass concentration of foam stabilizer，injection flow rate of natural gas foam，volume fraction of natural gas foam，and oil saturation were designed to determine the optimal formula of natural gas foam system and the best injection parameters. The influence of different factors on the fluidity control ability was analyzed. The standard deviation was introduced to describe the fluctuation range of the resistance coefficient during the displacement. Further，the adaptability of optimal injection parameters in formations with different permeability was explored. In the porous media with a permeability of 100 mD，the optimal injection parameters were 6 000 mg/L APG-10+400 mg/L DG. When the volume fraction of natural gas foam was 70% and the injection flow rate of natural gas foam was 4 mL/min，the fluidity control ability of natural gas foam was the strongest and the resistance coefficient was 57.04. In the study of permeability adaptability，when the permeability of porous media was within 3 000 mD，the fluidity control ability of natural gas foam grows as the permeability increases.
Foam flooding，as an effective way to improve oil recovery，has been widely used in major oil fields in China. It is found from numerous field applications that suitable injection parameters can give the fluidity control ability of foam flooding to full play. APG-10 was selected as foaming agent，DG as foam stabilizer，and natural gas as gas phase to prepare natural gas foam. Orthogonal experiments with regards to mass concentration of foaming agent，mass concentration of foam stabilizer，injection flow rate of natural gas foam，volume fraction of natural gas foam，and oil saturation were designed to determine the optimal formula of natural gas foam system and the best injection parameters. The influence of different factors on the fluidity control ability was analyzed. The standard deviation was introduced to describe the fluctuation range of the resistance coefficient during the displacement. Further，the adaptability of optimal injection parameters in formations with different permeability was explored. In the porous media with a permeability of 100 mD，the optimal injection parameters were 6 000 mg/L APG-10+400 mg/L DG. When the volume fraction of natural gas foam was 70% and the injection flow rate of natural gas foam was 4 mL/min，the fluidity control ability of natural gas foam was the strongest and the resistance coefficient was 57.04. In the study of permeability adaptability，when the permeability of porous media was within 3 000 mD，the fluidity control ability of natural gas foam grows as the permeability increases.
2021, 28(2):119-126.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.015
Abstract:
In recent years，intelligent separate injection-production techniques have been playing a very important role in improving the water-flooding development effect of reservoirs. For the evaluation of the improvement in water-flooding development effect，a set of quantitative comprehensive evaluation method is established considering the influencing factors such as physical properties of reservoirs，fluid properties，recovery，and development performance. Firstly，common evaluation indexes are classified and the selection principle is determined to sort out nine typical evaluation indexes according to the logical analysis method. Then，the comprehensive weights of evaluation indexes are determined through grey relational analysis and analytic hierarchy process with recovery factor taken as the objective function. On this basis，according to the existing industry standards for the grading of oilfield development levels，the grading scoring standards at different crudeoil viscosity and water-cut stages are established. The comprehensive score and score difference before and after the application of the intelligent separate injection-production technique in the target oilfield are calculated. The score difference represents the improvement in water-flooding development effect. A greater score difference means a better improvement in water-flooding development effect and a higher producing degree of the remaining oil. The results of numerical simulation also show that there is a positive correlation between score difference and increased oil production.
In recent years，intelligent separate injection-production techniques have been playing a very important role in improving the water-flooding development effect of reservoirs. For the evaluation of the improvement in water-flooding development effect，a set of quantitative comprehensive evaluation method is established considering the influencing factors such as physical properties of reservoirs，fluid properties，recovery，and development performance. Firstly，common evaluation indexes are classified and the selection principle is determined to sort out nine typical evaluation indexes according to the logical analysis method. Then，the comprehensive weights of evaluation indexes are determined through grey relational analysis and analytic hierarchy process with recovery factor taken as the objective function. On this basis，according to the existing industry standards for the grading of oilfield development levels，the grading scoring standards at different crudeoil viscosity and water-cut stages are established. The comprehensive score and score difference before and after the application of the intelligent separate injection-production technique in the target oilfield are calculated. The score difference represents the improvement in water-flooding development effect. A greater score difference means a better improvement in water-flooding development effect and a higher producing degree of the remaining oil. The results of numerical simulation also show that there is a positive correlation between score difference and increased oil production.
2021, 28(2):127-134.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.016
Abstract:
Natural fractures are developed in deep tight sandstone gas reservoirs in Kuche Depression of Tarim Basin，which are in the enclosed environment with high temperature，high pressure，and high crustal stress. Formation water has high salinity and local ultra-low water saturation. Some gas wells often encounter sand production to different extents，which seriously disturbs the normal production of gas wells. A sample of deep tight sandstone gas reservoir in Tarim Basin was selected in our experiment，in which the dry-wet alternation of the rising and falling of water saturation was simulated and the changes in dynamic mechanical parameters and stress sensitivity coefficient of rock were monitored. The results show that for the rock samples of deep tight sandstone gas reservoirs，the dynamic Young’s modulus and Poisson’s ratio take a dive after dry-wet alternation. The stress sensitivity coefficients of base rock samples and fractured rock samples are respectively 0.50-0.89 and 0.43-0.45，indicating their moderately weak-strong and moderately weak stress sensitivity. According to analysis，in gas drilling（drying），the release of formation pore pressure could change near-well stress，and the crystal stress caused by salting-out and fracture surface of gas washout could reduce rock strength and induce sand production. In well completion after gas-liquid conversion（dry-wet alternation），the water absorption and dehydration of clay minerals caused by dry-wet alternation，acid denudation，frictional sliding of fracture surface and change in water saturation as well as the spalling of sand grains from fracture surface by spheroidal weathering could reduce rock strength. Sand grains falling off the fracture surface will support the fracture and reduce its stress sensitivity. In the development of deep tight sandstone gas reservoirs，dry-wet alternation rounds and liquid intrusion should be reduced. The inevitable liquid should be drained back in time to prevent it from reducing rock strength. Fiber should be added in fracturing to avoid proppant reflux. At the same time，sand production should be controlled with reasonable sand production measures and sand control technology of wire-wrapped screens.
Natural fractures are developed in deep tight sandstone gas reservoirs in Kuche Depression of Tarim Basin，which are in the enclosed environment with high temperature，high pressure，and high crustal stress. Formation water has high salinity and local ultra-low water saturation. Some gas wells often encounter sand production to different extents，which seriously disturbs the normal production of gas wells. A sample of deep tight sandstone gas reservoir in Tarim Basin was selected in our experiment，in which the dry-wet alternation of the rising and falling of water saturation was simulated and the changes in dynamic mechanical parameters and stress sensitivity coefficient of rock were monitored. The results show that for the rock samples of deep tight sandstone gas reservoirs，the dynamic Young’s modulus and Poisson’s ratio take a dive after dry-wet alternation. The stress sensitivity coefficients of base rock samples and fractured rock samples are respectively 0.50-0.89 and 0.43-0.45，indicating their moderately weak-strong and moderately weak stress sensitivity. According to analysis，in gas drilling（drying），the release of formation pore pressure could change near-well stress，and the crystal stress caused by salting-out and fracture surface of gas washout could reduce rock strength and induce sand production. In well completion after gas-liquid conversion（dry-wet alternation），the water absorption and dehydration of clay minerals caused by dry-wet alternation，acid denudation，frictional sliding of fracture surface and change in water saturation as well as the spalling of sand grains from fracture surface by spheroidal weathering could reduce rock strength. Sand grains falling off the fracture surface will support the fracture and reduce its stress sensitivity. In the development of deep tight sandstone gas reservoirs，dry-wet alternation rounds and liquid intrusion should be reduced. The inevitable liquid should be drained back in time to prevent it from reducing rock strength. Fiber should be added in fracturing to avoid proppant reflux. At the same time，sand production should be controlled with reasonable sand production measures and sand control technology of wire-wrapped screens.
2021, 28(2):135-142.
DOI: 10.13673/j.cnki.cn37-1359/te.2021.02.017
Abstract:
The EBANO Oilfield in Mexico is dominated by the fracture-pore limestone reservoir，and the fracture is an important factor affecting oil well productivity and the water-cut rising mode. The development mechanism，influencing factors and connectivity between fractures in the thin interbeds of argillaceous limestone and calcareous mudstone in the EBANO Oilfield are studied by analyzing core and imaging logging data，drilling data，PLT test data and seismic coherence technology to improve the understanding of fracture connectivity between Ksf and Kan layers. Results indicate that this oilfield is controlled by high-angle structural fractures with the density of generally 1-2 fractures/m and 12 fractures/m to the highest，and fracture development is affected by lithology，faults，lithological association and reservoir heterogeneity. Besides，the lithology of EBANO Oilfield can be divided into three modes of association. The interbeds of argillaceous limestone with a single layer thickness of 2-4 m and calcareous mudstone with a single layer thickness of less than 1 m are favorable conditions for emerging fractures，and the fracture connectivity between Ksf and Kan layers can be divided into three types.The research results provide guidance for the development of different fractures in the oilfield. From 2013 to 2014，the drilling success rate increased from 92% to 97%. In 2020，the single well initial production of new wells will be enhanced to 167%.
The EBANO Oilfield in Mexico is dominated by the fracture-pore limestone reservoir，and the fracture is an important factor affecting oil well productivity and the water-cut rising mode. The development mechanism，influencing factors and connectivity between fractures in the thin interbeds of argillaceous limestone and calcareous mudstone in the EBANO Oilfield are studied by analyzing core and imaging logging data，drilling data，PLT test data and seismic coherence technology to improve the understanding of fracture connectivity between Ksf and Kan layers. Results indicate that this oilfield is controlled by high-angle structural fractures with the density of generally 1-2 fractures/m and 12 fractures/m to the highest，and fracture development is affected by lithology，faults，lithological association and reservoir heterogeneity. Besides，the lithology of EBANO Oilfield can be divided into three modes of association. The interbeds of argillaceous limestone with a single layer thickness of 2-4 m and calcareous mudstone with a single layer thickness of less than 1 m are favorable conditions for emerging fractures，and the fracture connectivity between Ksf and Kan layers can be divided into three types.The research results provide guidance for the development of different fractures in the oilfield. From 2013 to 2014，the drilling success rate increased from 92% to 97%. In 2020，the single well initial production of new wells will be enhanced to 167%.
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