Volume 30,Issue 4,2023 Table of Contents
2023, 30(4):1-20.
DOI: 10.13673/j.pgre.202209005
Abstract:
Affected by the subduction and closure of the Paleo-Asian Ocean and the collision between the northern margin of the North China Plate and the Siberian Plate，the Inner Mongolia Paleo-Uplift underwent important tectonic uplift during the CarboniferousPermian period，and it controls the formation，development，and filling evolution of the sedimentary basin in eastern North China and has become the provenance area of the basin. By studying sedimentology，petrology，mineralogy，and geochemistry of three field geological profiles and a large number of drilling cores in the basin area，detailed sedimentary system and tectonic evolution of provenance area during the Carboniferous-Permian period in eastern North China were analyzed in this article. The results show that the paleogeographic environment of the Carboniferous-Permian sedimentary basin in eastern North China has experienced the evolution process of the epicontinental sea，sea-land transition，and continental facies. Platform-barrier coast sedimentary system，delta sedimentary system，and fluvial sedimentary system have been developed from early to late，and sedimentary facies include carbonate platforms，tidal flat，lagoons，barrier islands，delta，meandering rivers，braided rivers，etc. The composition of detrital particles and geochemical characteristics of sandstone indicate that the provenance area has the characteristics of an active continental margin recycling orogenic belt and island arc. The parent rock assemblage is composed of early Paleozoic flint-rich banded carbonate rocks，early sedimentary cap rocks such as Meso-Neoproterozoic clastic rocks and epimetamorphic rocks，and Late Paleozoic island arc volcanic rocks，plutonic intrusive rocks，and basement metamorphic rocks. The sedimentation，filling rate，sedimentary evolution process，variation of clastic grain composition，and petrogeochemical characteristics of the Carboniferous-Permian basin in eastern North China fully respond to the tectonic evolution process of the provenance area with the orogenic belt. Specifically，the provenance area undergoes intracontinental uplift due to continuous ocean-continent subduction and the formation of an island arc in the continental margin during the sedimentary period of the Benxi and Taiyuan Formations. In the sedimentary period of the Shanxi Formation-Lower Shihezi Formation，the paleo-Asian ocean gradually closes，and the collision between plates makes the uplift of the provenance area intensified with fold and thrust. During the sedimentary period of the Upper Shihezi Formation，the provenance area experiences an intense collision between plates and comprehensive orogenesis.
Affected by the subduction and closure of the Paleo-Asian Ocean and the collision between the northern margin of the North China Plate and the Siberian Plate，the Inner Mongolia Paleo-Uplift underwent important tectonic uplift during the CarboniferousPermian period，and it controls the formation，development，and filling evolution of the sedimentary basin in eastern North China and has become the provenance area of the basin. By studying sedimentology，petrology，mineralogy，and geochemistry of three field geological profiles and a large number of drilling cores in the basin area，detailed sedimentary system and tectonic evolution of provenance area during the Carboniferous-Permian period in eastern North China were analyzed in this article. The results show that the paleogeographic environment of the Carboniferous-Permian sedimentary basin in eastern North China has experienced the evolution process of the epicontinental sea，sea-land transition，and continental facies. Platform-barrier coast sedimentary system，delta sedimentary system，and fluvial sedimentary system have been developed from early to late，and sedimentary facies include carbonate platforms，tidal flat，lagoons，barrier islands，delta，meandering rivers，braided rivers，etc. The composition of detrital particles and geochemical characteristics of sandstone indicate that the provenance area has the characteristics of an active continental margin recycling orogenic belt and island arc. The parent rock assemblage is composed of early Paleozoic flint-rich banded carbonate rocks，early sedimentary cap rocks such as Meso-Neoproterozoic clastic rocks and epimetamorphic rocks，and Late Paleozoic island arc volcanic rocks，plutonic intrusive rocks，and basement metamorphic rocks. The sedimentation，filling rate，sedimentary evolution process，variation of clastic grain composition，and petrogeochemical characteristics of the Carboniferous-Permian basin in eastern North China fully respond to the tectonic evolution process of the provenance area with the orogenic belt. Specifically，the provenance area undergoes intracontinental uplift due to continuous ocean-continent subduction and the formation of an island arc in the continental margin during the sedimentary period of the Benxi and Taiyuan Formations. In the sedimentary period of the Shanxi Formation-Lower Shihezi Formation，the paleo-Asian ocean gradually closes，and the collision between plates makes the uplift of the provenance area intensified with fold and thrust. During the sedimentary period of the Upper Shihezi Formation，the provenance area experiences an intense collision between plates and comprehensive orogenesis.
ZHAO Jian
,
WANG Yanqing
,
WANG Zhaobing
,
LI Haipeng
,
ZHANG Chengjuan
,
LI Yanan
,
TANG Li
,
ZHANG Boce
,
YING Min
,
ZHONG Shiguo
2023, 30(4):21-32.
DOI: 10.13673/j.pgre.202203012
Abstract:
Hydrocarbon breakthroughs have been made in the Paleogene clastic rocks of Wells Chai 10 and Atan 1 in the Altun piedmont of Qaidam Basin. It is necessary to conduct fine characterization of sedimentary sand bodies and study reservoir characteristics to expand the exploration and find new exploration zones. The heavy mineral，core，thin section，and physical property，logging，and seismic data，were employed to redefine sedimentary provenances and study the types and distribution of sand bodies and reservoir characteristics. In this way，the favorable exploration zones were proposed for subsequent work. The results show that there are eight provenances in the Altun piedmont，and the boundary and distribution of the eight provenances are carefully delineated. The clastic rocks and carbonate rocks are developed in the study area，where the clastic rocks include conglomerates，glutenites，pebbly sandstones，and sandstones，demonstrating alluvial fan facies，fan-delta facies，subaqueous fan facies，and shore-shallow lake beach bar microfacies. Reservoirs are classified as medium-poor，and the argillaceous matrix content is at the level of medium-high.Controlled by the sedimentary facies zone，the physical properties of reservoirs in the alluvial fan facies and fan-delta plain subfacies are poor，and those of reservoirs in fan-delta front sub-facies and subaqueous fan facies are good while those of reservoirs from the piedmont to the basin show the characteristic of“poor-good-poor”. Hydrocarbons migrate from the hydrocarbon generation center to the piedmont and tend to accumulate in the high-quality reservoirs of fan-delta front subfacies and subaqueous fan facies as they are blocked by the tight reservoirs of alluvial fan facies and fan-delta plain subfacies in the high structural position. It is concluded that the distribution areas of fan-delta front subfacies and subaqueous fan facies are the favorable zones for future oil and gas exploration. Accordingly，the risk well Atan 2 and the exploration well Hongbei 2 are deployed.
Hydrocarbon breakthroughs have been made in the Paleogene clastic rocks of Wells Chai 10 and Atan 1 in the Altun piedmont of Qaidam Basin. It is necessary to conduct fine characterization of sedimentary sand bodies and study reservoir characteristics to expand the exploration and find new exploration zones. The heavy mineral，core，thin section，and physical property，logging，and seismic data，were employed to redefine sedimentary provenances and study the types and distribution of sand bodies and reservoir characteristics. In this way，the favorable exploration zones were proposed for subsequent work. The results show that there are eight provenances in the Altun piedmont，and the boundary and distribution of the eight provenances are carefully delineated. The clastic rocks and carbonate rocks are developed in the study area，where the clastic rocks include conglomerates，glutenites，pebbly sandstones，and sandstones，demonstrating alluvial fan facies，fan-delta facies，subaqueous fan facies，and shore-shallow lake beach bar microfacies. Reservoirs are classified as medium-poor，and the argillaceous matrix content is at the level of medium-high.Controlled by the sedimentary facies zone，the physical properties of reservoirs in the alluvial fan facies and fan-delta plain subfacies are poor，and those of reservoirs in fan-delta front sub-facies and subaqueous fan facies are good while those of reservoirs from the piedmont to the basin show the characteristic of“poor-good-poor”. Hydrocarbons migrate from the hydrocarbon generation center to the piedmont and tend to accumulate in the high-quality reservoirs of fan-delta front subfacies and subaqueous fan facies as they are blocked by the tight reservoirs of alluvial fan facies and fan-delta plain subfacies in the high structural position. It is concluded that the distribution areas of fan-delta front subfacies and subaqueous fan facies are the favorable zones for future oil and gas exploration. Accordingly，the risk well Atan 2 and the exploration well Hongbei 2 are deployed.
2023, 30(4):33-45.
DOI: 10.13673/j.pgre.202207018
Abstract:
The late Carboniferous intermediate-acid volcanic rocks in Shixi uplift of Junggar Basin are important oil and gas reservoirs with excellent reservoir properties and active oil and gas display. The relationship between oil and water in volcanic reservoirs in this area is complex，and the understanding of the influencing factors of reservoir development is still unclear. The petrogenesis of the late Carboniferous volcanic reservoirs and the influencing factors of the reservoir development are deeply analyzed by means of core observation，casting thin section，element geochemistry，and logging data. The comprehensive study shows that the chemical index of alteration（CIA）of late Carboniferous volcanic rocks in Shixi uplift is greater than 0.55，which reflects the origin of continental eruption and accumulation. The magmatic properties affect the development of primary pores and fractures，as well as the secondary dissolution micropores in the reservoirs. The neutral amygdaloid porphyritic andesite，porphyritic andesite，and andesitic volcanic breccia have developed primary pores and fractures，as well as secondary dissolution micropores，which have excellent reservoir properties. The intervals with good oil and gas display mainly appear in the andesite at the early and late stages of eruption and overflow and the volcanic breccia at the middle and late stages of the explosion. The andesite has the best physical property，and its primary structural fractures and diagenetic fractures are relatively developed，followed by volcanic breccia，and dacite is the worst. The burial depth has an obvious influence on the porosity of andesite，but it slightly affects the porosities of the volcanic breccia and dacite，as well as the permeability of andesite，volcanic breccia，and dacite. The main fault can obviously control the development density and flow capacity of reservoir fractures. Within the radius of 1.5 km affected by the main fault，the reservoir fracture development density is relatively large，and the flow capacity is relatively positive. Weathering leaching and alteration mainly affect the physical properties of the reservoir. Basalt，andesite，dacite，and volcanic breccia that have undergone strong weathering leaching and alteration can all become favorable reservoirs.
The late Carboniferous intermediate-acid volcanic rocks in Shixi uplift of Junggar Basin are important oil and gas reservoirs with excellent reservoir properties and active oil and gas display. The relationship between oil and water in volcanic reservoirs in this area is complex，and the understanding of the influencing factors of reservoir development is still unclear. The petrogenesis of the late Carboniferous volcanic reservoirs and the influencing factors of the reservoir development are deeply analyzed by means of core observation，casting thin section，element geochemistry，and logging data. The comprehensive study shows that the chemical index of alteration（CIA）of late Carboniferous volcanic rocks in Shixi uplift is greater than 0.55，which reflects the origin of continental eruption and accumulation. The magmatic properties affect the development of primary pores and fractures，as well as the secondary dissolution micropores in the reservoirs. The neutral amygdaloid porphyritic andesite，porphyritic andesite，and andesitic volcanic breccia have developed primary pores and fractures，as well as secondary dissolution micropores，which have excellent reservoir properties. The intervals with good oil and gas display mainly appear in the andesite at the early and late stages of eruption and overflow and the volcanic breccia at the middle and late stages of the explosion. The andesite has the best physical property，and its primary structural fractures and diagenetic fractures are relatively developed，followed by volcanic breccia，and dacite is the worst. The burial depth has an obvious influence on the porosity of andesite，but it slightly affects the porosities of the volcanic breccia and dacite，as well as the permeability of andesite，volcanic breccia，and dacite. The main fault can obviously control the development density and flow capacity of reservoir fractures. Within the radius of 1.5 km affected by the main fault，the reservoir fracture development density is relatively large，and the flow capacity is relatively positive. Weathering leaching and alteration mainly affect the physical properties of the reservoir. Basalt，andesite，dacite，and volcanic breccia that have undergone strong weathering leaching and alteration can all become favorable reservoirs.
2023, 30(4):46-54.
DOI: 10.13673/j.pgre.202108045
Abstract:
The complex pore structures of shales lead to a variety of pore fluid types. Taking the shales of Chang 7 Member of Yanchang Formation in Ordos Basin as the research object，the low-field nuclear magnetic resonance（NMR）technology was adopted，and the T2 relaxation time limits of multiple types of pore fluid in three types of shales were identified by combining centrifugal test with heat treatment test. The full pore size distribution characteristics of the target shales were quantitatively characterized. The results show that the pore structures of the target shals can be divided into three types：Ⅰ，Ⅱ，and Ⅲ，and their corresponding average pore radii and fluid accumulations decrease successively. The cutoff values of movable fluid in the three types of shale are 1.1，1.24，and 1.92 ms，respectively，while those of non-recoverable fluid are 0.2，0.3，and 0.54 ms，respectively. The movable fluid in type Ⅰ shale occurs in medium and large pores with a diameter of larger than 24.8 nm，and the average saturation is 30.5%；the non-recoverable fluid occurs in micropores with a diameter of less than 4.5 nm，and the average saturation is 35.3%. The movable fluid in type Ⅱ shale occurs in large pores with a diameter of larger than 41.9 nm，and the average saturation is 26.6%；the non-recoverable fluid occurs in micro and small pores with a diameter of less than 10.3 nm，and the average saturation is 40.7%. The movable fluid in type Ⅲ shale occurs in large pores with a diameter of larger than 93.6 nm，and the average saturation is 17.2%；the nonrecoverable fluid occurs in medium and small pores with a diameter of less than 26.3 nm，and the average saturation reaches 50.1%.
The complex pore structures of shales lead to a variety of pore fluid types. Taking the shales of Chang 7 Member of Yanchang Formation in Ordos Basin as the research object，the low-field nuclear magnetic resonance（NMR）technology was adopted，and the T2 relaxation time limits of multiple types of pore fluid in three types of shales were identified by combining centrifugal test with heat treatment test. The full pore size distribution characteristics of the target shales were quantitatively characterized. The results show that the pore structures of the target shals can be divided into three types：Ⅰ，Ⅱ，and Ⅲ，and their corresponding average pore radii and fluid accumulations decrease successively. The cutoff values of movable fluid in the three types of shale are 1.1，1.24，and 1.92 ms，respectively，while those of non-recoverable fluid are 0.2，0.3，and 0.54 ms，respectively. The movable fluid in type Ⅰ shale occurs in medium and large pores with a diameter of larger than 24.8 nm，and the average saturation is 30.5%；the non-recoverable fluid occurs in micropores with a diameter of less than 4.5 nm，and the average saturation is 35.3%. The movable fluid in type Ⅱ shale occurs in large pores with a diameter of larger than 41.9 nm，and the average saturation is 26.6%；the non-recoverable fluid occurs in micro and small pores with a diameter of less than 10.3 nm，and the average saturation is 40.7%. The movable fluid in type Ⅲ shale occurs in large pores with a diameter of larger than 93.6 nm，and the average saturation is 17.2%；the nonrecoverable fluid occurs in medium and small pores with a diameter of less than 26.3 nm，and the average saturation reaches 50.1%.
ZHANG Peixian
,
GAO Quanfang
,
HE Xipeng
,
GAO Yuqiao
,
LIU Ming
,
HE Guisong
,
ZHANG Zhiping
,
ZHOU Dina
2023, 30(4):55-65.
DOI: 10.13673/j.pgre.202208024
Abstract:
Nanchuan area is located in a complex tectonic area in the basin-margin transition zone of Sichuan Basin，and its Longmaxi Formation dominated by normal-pressure shale gas is endowed with favorable shale gas accumulation and enrichment conditions.However，the complex in-situ stress field and the large difference in single-well production become the key factors restricting the profitable development of the normal-pressure shale gas. Field profile survey，numerical finite-element stress field simulation，and special imaging logging were conducted，and the regional stress field was investigated. Moreover，lots of practices in shale-gas horizontal well fracturing were reviewed. The following three conclusions were thereby obtained：①In the Mid-Yanshanian，the maximum principal stress was in the east-west（EW）direction in the anticline area and in the northeast-east（NEE）direction in the southern monoclinal zone in Nanchuan area；Since the Himalayan period，the current horizontal in-situ stress field has been characterized by marked planar zoning，with local transition zones of in-situ stress direction and magnitude. In the vertical direction，the insitu stress has descended with the increase in depth under the influence of lithology. The in-situ stress in local silty sandstone and that in the local shell limestone in Guanyinqiao Member have increased substantially. ②The in-situ stresses in Longmaxi Formation were mainly affected by the intensity of tectonic reworking，tectonic style，burial depth，and fracture development，and they were high in the weak tectonic reworking，the deep burial depth，the core of anticline or syncline，or the few natural fractures areas. ③The in-situ stress field has a great influence on the production of shale gas wells. Specifically，the paleo-stress field controlled the development of natural fractures and affected the physical properties and gas-bearing properties of reservoirs. In contrast，the current in-situ stress field influenced the complexity of artificial fractures. A smaller angle between the horizontal well trajectory and the minimum horizontal principal stress，on the premise of moderate in-situ stress，corresponds to easier stimulation，which is more beneficial for creating complex fracture networks and further improving single-well production. This research can effectively guide shale gas exploration and development in Nanchuan area.
Nanchuan area is located in a complex tectonic area in the basin-margin transition zone of Sichuan Basin，and its Longmaxi Formation dominated by normal-pressure shale gas is endowed with favorable shale gas accumulation and enrichment conditions.However，the complex in-situ stress field and the large difference in single-well production become the key factors restricting the profitable development of the normal-pressure shale gas. Field profile survey，numerical finite-element stress field simulation，and special imaging logging were conducted，and the regional stress field was investigated. Moreover，lots of practices in shale-gas horizontal well fracturing were reviewed. The following three conclusions were thereby obtained：①In the Mid-Yanshanian，the maximum principal stress was in the east-west（EW）direction in the anticline area and in the northeast-east（NEE）direction in the southern monoclinal zone in Nanchuan area；Since the Himalayan period，the current horizontal in-situ stress field has been characterized by marked planar zoning，with local transition zones of in-situ stress direction and magnitude. In the vertical direction，the insitu stress has descended with the increase in depth under the influence of lithology. The in-situ stress in local silty sandstone and that in the local shell limestone in Guanyinqiao Member have increased substantially. ②The in-situ stresses in Longmaxi Formation were mainly affected by the intensity of tectonic reworking，tectonic style，burial depth，and fracture development，and they were high in the weak tectonic reworking，the deep burial depth，the core of anticline or syncline，or the few natural fractures areas. ③The in-situ stress field has a great influence on the production of shale gas wells. Specifically，the paleo-stress field controlled the development of natural fractures and affected the physical properties and gas-bearing properties of reservoirs. In contrast，the current in-situ stress field influenced the complexity of artificial fractures. A smaller angle between the horizontal well trajectory and the minimum horizontal principal stress，on the premise of moderate in-situ stress，corresponds to easier stimulation，which is more beneficial for creating complex fracture networks and further improving single-well production. This research can effectively guide shale gas exploration and development in Nanchuan area.
2023, 30(4):66-76.
DOI: 10.13673/j.cnki.cn37-1359/te.202211018
Abstract:
In the process of marine shale gas exploration，it is found that the gas contents of shales are related to the apparent resistivity，and the shale section with low resistivity generally shows poor gas content. In order to reveal the origins of the low resistivity of marine shales，the laser Raman，resistivity measurement by dried cores，charging effect observation by scanning electron microscopy（SEM），inclusion analysis，and organic geochemistry experimental analysis were carried out based on the well drilling，logging，and testing data from key wells in Southeast Sichuan area and its adjacent areas. In terms of organic matter carbonization and preservation conditions，the origins of the low resistivity of the shale reservoir were discussed in this paper，and the influence ranges were predicted. The results show that shales with low resistivity have three typical characteristics in terms of electrical，physical and gas-bearing properties. In high-quality shale sections，the shales have the resistivity with sudden or gradational changes，small pore diameters，low porosity and poor gas-bearing properties，and most wells are dry. For shales with a vitrinite reflectance（Ro）of over 3.5%，strong carbonization of organic matter is the main factor leading to low and extremely low resistivity. For shales with a Ro of less than 3.5%，the poor preservation condition is the main factor for the formation of low and extremely low resistivity，and weak carbonization has an important effect on the low resistivity. In the weak carbonization stage，the water content and water saturation of shales increase as the preservation conditions are damaged. Under the action of compaction，the pores and fractures collapse and close，and the matrix particles contact in inlay mode. So the electrical conductivity is enhanced，and the resistivity decreases significantly. As the abundance of organic matter gets higher，the resistivity becomes lower. The influence ranges of strong carbonization of organic matter are regional，and those of poor preservation conditions are relatively small.
In the process of marine shale gas exploration，it is found that the gas contents of shales are related to the apparent resistivity，and the shale section with low resistivity generally shows poor gas content. In order to reveal the origins of the low resistivity of marine shales，the laser Raman，resistivity measurement by dried cores，charging effect observation by scanning electron microscopy（SEM），inclusion analysis，and organic geochemistry experimental analysis were carried out based on the well drilling，logging，and testing data from key wells in Southeast Sichuan area and its adjacent areas. In terms of organic matter carbonization and preservation conditions，the origins of the low resistivity of the shale reservoir were discussed in this paper，and the influence ranges were predicted. The results show that shales with low resistivity have three typical characteristics in terms of electrical，physical and gas-bearing properties. In high-quality shale sections，the shales have the resistivity with sudden or gradational changes，small pore diameters，low porosity and poor gas-bearing properties，and most wells are dry. For shales with a vitrinite reflectance（Ro）of over 3.5%，strong carbonization of organic matter is the main factor leading to low and extremely low resistivity. For shales with a Ro of less than 3.5%，the poor preservation condition is the main factor for the formation of low and extremely low resistivity，and weak carbonization has an important effect on the low resistivity. In the weak carbonization stage，the water content and water saturation of shales increase as the preservation conditions are damaged. Under the action of compaction，the pores and fractures collapse and close，and the matrix particles contact in inlay mode. So the electrical conductivity is enhanced，and the resistivity decreases significantly. As the abundance of organic matter gets higher，the resistivity becomes lower. The influence ranges of strong carbonization of organic matter are regional，and those of poor preservation conditions are relatively small.
2023, 30(4):77-85.
DOI: 10.13673/j.pgre.202204034
Abstract:
Comprehensive evaluation on exploration effectiveness is important in exploration management and decision-making analysis.However，the commonly used evaluation indicators and methods are dull and cannot fully reflect the actual exploration effectiveness.Thus，it is essential to find out the key indicators affecting the comprehensive evaluation，build a reasonable evaluation model，and provide some effective methods to comprehensively evaluate exploration effectiveness. In this study，the key factors affecting exploration effectiveness were analyzed，and a comprehensive evaluation system for hydrocarbon exploration effectiveness was established，containing five categories and nine sub-indicators. A comprehensive evaluation model based on the entropy weight method and improved radar chart method was hereby put forward. Moreover，the combination of the indicator system and the evaluation model constituted a quantitative approach to evaluating the hydrocarbon exploration effectiveness with the improved radar chart method as the core. This method can be used to evaluate the effectiveness at various exploration periods，in different exploration domains，as well as of different types of gas reservoirs in a comprehensive manner. The results show that①the exploration effectiveness becomes higher as time goes on；②for gas reservoir types，the exploration effectiveness of compound reservoirs is superior while that of pure lithological and structural reservoirs is poor；③for exploration domains，the exploration effectiveness in the Sinian Lower Paleozoic registers the best，whereas it is relatively poor in Leikoupo and Jialingjiang Formations and the Carboniferous. In general，the evaluated results are consistent with the actual exploration，which means the proposed method can make an objective evaluation of the comprehensive exploration effectiveness.
Comprehensive evaluation on exploration effectiveness is important in exploration management and decision-making analysis.However，the commonly used evaluation indicators and methods are dull and cannot fully reflect the actual exploration effectiveness.Thus，it is essential to find out the key indicators affecting the comprehensive evaluation，build a reasonable evaluation model，and provide some effective methods to comprehensively evaluate exploration effectiveness. In this study，the key factors affecting exploration effectiveness were analyzed，and a comprehensive evaluation system for hydrocarbon exploration effectiveness was established，containing five categories and nine sub-indicators. A comprehensive evaluation model based on the entropy weight method and improved radar chart method was hereby put forward. Moreover，the combination of the indicator system and the evaluation model constituted a quantitative approach to evaluating the hydrocarbon exploration effectiveness with the improved radar chart method as the core. This method can be used to evaluate the effectiveness at various exploration periods，in different exploration domains，as well as of different types of gas reservoirs in a comprehensive manner. The results show that①the exploration effectiveness becomes higher as time goes on；②for gas reservoir types，the exploration effectiveness of compound reservoirs is superior while that of pure lithological and structural reservoirs is poor；③for exploration domains，the exploration effectiveness in the Sinian Lower Paleozoic registers the best，whereas it is relatively poor in Leikoupo and Jialingjiang Formations and the Carboniferous. In general，the evaluated results are consistent with the actual exploration，which means the proposed method can make an objective evaluation of the comprehensive exploration effectiveness.
2023, 30(4):86-97.
DOI: 10.13673/j.pgre.202304038
Abstract:
The Rayleigh wave exploration method is a commonly used near-surface exploration technique，and dispersion curve inversion is one of the key steps in the data processing of Rayleigh wave exploration. As a typical multi-parameter，multi-extreme，and highly nonlinear geophysical optimization problem，accurate and efficient inversion of dispersion curves is of great significance for calculating near-surface S-wave velocity fields and obtaining stratigraphic structure information. We propose a method for the Rayleigh wave dispersion curve inversion based on improved dung beetle optimizer（DBO）algorithm. The method uses Halton sequence to initialize the position of the population，so as to better control the spatial distribution of the initialized population，and it adopts different search strategies for different sub-populations by population division，so as to avoid the inversion search falling into the local optimum and realize the fast convergence of the algorithm. In this paper，three theoretical geological models and a set of practical data are used to verify the effectiveness of the improved DBO algorithm applied to the inversion of dispersion curves to obtain the subsurface S-wave velocity distribution. The results show that the new method is more effective and stable than the current mainstream improved adaptive genetic algorithm for dispersion curve inversion and can converge to the optimal solution quickly.
The Rayleigh wave exploration method is a commonly used near-surface exploration technique，and dispersion curve inversion is one of the key steps in the data processing of Rayleigh wave exploration. As a typical multi-parameter，multi-extreme，and highly nonlinear geophysical optimization problem，accurate and efficient inversion of dispersion curves is of great significance for calculating near-surface S-wave velocity fields and obtaining stratigraphic structure information. We propose a method for the Rayleigh wave dispersion curve inversion based on improved dung beetle optimizer（DBO）algorithm. The method uses Halton sequence to initialize the position of the population，so as to better control the spatial distribution of the initialized population，and it adopts different search strategies for different sub-populations by population division，so as to avoid the inversion search falling into the local optimum and realize the fast convergence of the algorithm. In this paper，three theoretical geological models and a set of practical data are used to verify the effectiveness of the improved DBO algorithm applied to the inversion of dispersion curves to obtain the subsurface S-wave velocity distribution. The results show that the new method is more effective and stable than the current mainstream improved adaptive genetic algorithm for dispersion curve inversion and can converge to the optimal solution quickly.
2023, 30(4):98-105.
DOI: 10.13673/j.pgre.202305025
Abstract:
For the fine identification of micro-structures of less than 10 m，conventional mapping and analysis methods are limited by the quality of seismic data and interpretation accuracy，and it is difficult to effectively highlight the details of micro-structures and improve the identification efficiency. This paper studies micro-structure in Block X of Ecuador，South America and explores the method of wavelet structure decomposition to achieve rapid and effective fine identification of micro-structure of about 3 m in the target layer. The target layer is affected by the weak compression of the Andean orogenic movement，and most of the micro-structures are less than 5 m. In this paper，the wavelet structure decomposition method is used to sample the depth or T0 structure data at equal intervals，and the scale-frequency wavelet function with scale changing with frequency is established，which is used to decompose the micro-structure fluctuation characteristics on multiple scales. The threshold function is used to control and optimize the signals of low-frequency，medium-frequency，and high-frequency structural fluctuations. According to the corresponding wavelet coefficients，the low-frequency，medium-frequency，and high-frequency components are reconstructed at multiple scales to improve the recognition weight of the corresponding high-frequency components to the micro-structure，thereby reducing the shielding effect of the low-frequency components on the micro-structure identification. The identification method of micro-structure based on wavelet transform can effectively identify the micro-structure of less than 3 m，which greatly improves the prediction accuracy and analysis efficiency of small-scale micro-structure reservoirs in the slope area. A series of evaluation wells have been successfully deployed and drilled，and good oil and gas shows have been achieved.
For the fine identification of micro-structures of less than 10 m，conventional mapping and analysis methods are limited by the quality of seismic data and interpretation accuracy，and it is difficult to effectively highlight the details of micro-structures and improve the identification efficiency. This paper studies micro-structure in Block X of Ecuador，South America and explores the method of wavelet structure decomposition to achieve rapid and effective fine identification of micro-structure of about 3 m in the target layer. The target layer is affected by the weak compression of the Andean orogenic movement，and most of the micro-structures are less than 5 m. In this paper，the wavelet structure decomposition method is used to sample the depth or T0 structure data at equal intervals，and the scale-frequency wavelet function with scale changing with frequency is established，which is used to decompose the micro-structure fluctuation characteristics on multiple scales. The threshold function is used to control and optimize the signals of low-frequency，medium-frequency，and high-frequency structural fluctuations. According to the corresponding wavelet coefficients，the low-frequency，medium-frequency，and high-frequency components are reconstructed at multiple scales to improve the recognition weight of the corresponding high-frequency components to the micro-structure，thereby reducing the shielding effect of the low-frequency components on the micro-structure identification. The identification method of micro-structure based on wavelet transform can effectively identify the micro-structure of less than 3 m，which greatly improves the prediction accuracy and analysis efficiency of small-scale micro-structure reservoirs in the slope area. A series of evaluation wells have been successfully deployed and drilled，and good oil and gas shows have been achieved.
2023, 30(4):106-115.
DOI: 10.13673/j.pgre.202205037
Abstract:
Microbial-induced carbonate precipitation（MICP）takes advantage of the metabolic activities of microorganisms to induce carbonate deposition and cement loose materials. The technology has been widely used due to its controllable reaction rate，high permeability，and environmental friendliness，having a good application prospect. In this paper，the principle of MICP technology，applied bacteria，mineralization and cementation mechanism，and the application of MICP technology in oil and gas field development are systematically reviewed. MICP can be achieved through urea hydrolysis，denitrification，sulfate reduction，or methane oxidation. The microorganisms inducing carbonate precipitation are mainly divided into extracellular polymer producing bacteria，urease producing bacteria，denitrifying bacteria，sulfate reducing bacteria and methane oxidizing bacteria. The MICP technology can induce carbonate precipitation by mineralization and act as a bridge to cement loose materials so that they can form a unified whole. Thus，MICP can be used to plug pores and fractures to prevent sand production in oil and gas wells and also improve the effectiveness of water flooding to enhance oil and gas recovery.
Microbial-induced carbonate precipitation（MICP）takes advantage of the metabolic activities of microorganisms to induce carbonate deposition and cement loose materials. The technology has been widely used due to its controllable reaction rate，high permeability，and environmental friendliness，having a good application prospect. In this paper，the principle of MICP technology，applied bacteria，mineralization and cementation mechanism，and the application of MICP technology in oil and gas field development are systematically reviewed. MICP can be achieved through urea hydrolysis，denitrification，sulfate reduction，or methane oxidation. The microorganisms inducing carbonate precipitation are mainly divided into extracellular polymer producing bacteria，urease producing bacteria，denitrifying bacteria，sulfate reducing bacteria and methane oxidizing bacteria. The MICP technology can induce carbonate precipitation by mineralization and act as a bridge to cement loose materials so that they can form a unified whole. Thus，MICP can be used to plug pores and fractures to prevent sand production in oil and gas wells and also improve the effectiveness of water flooding to enhance oil and gas recovery.
2023, 30(4):116-122.
DOI: 10.13673/j.pgre.202212033
Abstract:
The nanoparticles of calcium carbonate were synthesized from solid mixed salts to tackle the problems of difficult treatment of solid mixed salts and high preparation costs of nanoparticles，which were applied in nano-fluid flooding as the tertiary oil recovery technique to enhance oil recovery. Under the foam atmosphere system，calcium carbonate and magnesium carbonate mixed nanoparticles were synthesized from the solid mixed salts rich in Ca2+ and Mg2+ provided by the oil and gas mine water treatment plant in southwest Sichuan. The nanoparticles were dispersed in the polyacrylamide solution to form a nano-fluid flooding system，and the oil displacement effect was studied. The results show that the synthetic particles have an average particle size of 120.9 nm，a peak particle size of 111.7 nm，and a particle size distribution range of 28.87-638.78 nm. The particle surface adsorbs the side chain of alkyl sulfate，and the contact angle is 93.570°. When 1 g of synthetic nanoparticles are dispersed in the polyacrylamide solution，the nano-fluids can maintain stability for more than 24 h. In addition，displacement experiments show that when the nano-fluids are injected at a water cut of 80%，the nano-fluid flooding can form a stable displacement pressure difference of about 3 MPa. The oil recovery under the nano-fluid flooding increases to 88.66% from 46.67% under water flooding，with an increase of 41.99%，which indicates that the nano-fluid system has good oil displacement performance.
The nanoparticles of calcium carbonate were synthesized from solid mixed salts to tackle the problems of difficult treatment of solid mixed salts and high preparation costs of nanoparticles，which were applied in nano-fluid flooding as the tertiary oil recovery technique to enhance oil recovery. Under the foam atmosphere system，calcium carbonate and magnesium carbonate mixed nanoparticles were synthesized from the solid mixed salts rich in Ca2+ and Mg2+ provided by the oil and gas mine water treatment plant in southwest Sichuan. The nanoparticles were dispersed in the polyacrylamide solution to form a nano-fluid flooding system，and the oil displacement effect was studied. The results show that the synthetic particles have an average particle size of 120.9 nm，a peak particle size of 111.7 nm，and a particle size distribution range of 28.87-638.78 nm. The particle surface adsorbs the side chain of alkyl sulfate，and the contact angle is 93.570°. When 1 g of synthetic nanoparticles are dispersed in the polyacrylamide solution，the nano-fluids can maintain stability for more than 24 h. In addition，displacement experiments show that when the nano-fluids are injected at a water cut of 80%，the nano-fluid flooding can form a stable displacement pressure difference of about 3 MPa. The oil recovery under the nano-fluid flooding increases to 88.66% from 46.67% under water flooding，with an increase of 41.99%，which indicates that the nano-fluid system has good oil displacement performance.
YANG Haozhe
,
YANG Guo
,
ZHOU Xiaoyi
,
MA Xiaomei
,
CHEN Chao
,
LIU Tingting
,
LI Hui
,
YANG Fengzhi
2023, 30(4):123-129.
DOI: 10.13673/j.pgre.202212008
Abstract:
In view of the common problems in the middle and later stages of steam-assisted gravity drainage（SAGD）development with dual-horizontal wells，such as insufficient formation energy，low oil discharge capacity and oil-steam ratio，and serious heat loss，the technology of multi-media enhancement to improve development effects was put forward. The key mechanism was revealed，and the main injection parameters were optimized by combining laboratory experiments and numerical simulation. The results show that the injection of multi-media can reduce the viscosity，improve the shapes of steam chambers，increase the gravity oil discharge capacity，alleviate the heat loss，and save the steam in the middle and later stages of SAGD development. The solvents are easier to dissolve and reduce viscosity when the steam chambers extend to the tops of the reservoirs，and stopping the injection of solvents can improve the recovery rates when the steam chambers stop the lateral expansion；injection timings，methods，and amounts of non-condensate methane have a significant influence on the final oil-steam ratio. Compared with that of pure SAGD，the average daily oil production of SAGD enhanced by multiple media increases by 3.9 t/d. The oil-steam ratio increases by 0.093，and the daily steam injection decreases by 6.7 t/d. The technology has been implemented for three months，and the input-output ratio is 1∶4.
In view of the common problems in the middle and later stages of steam-assisted gravity drainage（SAGD）development with dual-horizontal wells，such as insufficient formation energy，low oil discharge capacity and oil-steam ratio，and serious heat loss，the technology of multi-media enhancement to improve development effects was put forward. The key mechanism was revealed，and the main injection parameters were optimized by combining laboratory experiments and numerical simulation. The results show that the injection of multi-media can reduce the viscosity，improve the shapes of steam chambers，increase the gravity oil discharge capacity，alleviate the heat loss，and save the steam in the middle and later stages of SAGD development. The solvents are easier to dissolve and reduce viscosity when the steam chambers extend to the tops of the reservoirs，and stopping the injection of solvents can improve the recovery rates when the steam chambers stop the lateral expansion；injection timings，methods，and amounts of non-condensate methane have a significant influence on the final oil-steam ratio. Compared with that of pure SAGD，the average daily oil production of SAGD enhanced by multiple media increases by 3.9 t/d. The oil-steam ratio increases by 0.093，and the daily steam injection decreases by 6.7 t/d. The technology has been implemented for three months，and the input-output ratio is 1∶4.
2023, 30(4):130-136.
DOI: 10.13673/j.pgre.202208033
Abstract:
The dynamic response of interwell injection-production in injection and production wells is an important parameter in the process of reservoir development. The correct evaluation of the dynamic response of interwell injection-production can provide a theoretical basis for optimizing process measures of flow field control in the later stage of reservoir development. Injection-production well pattern can be equivalent to a graph structure，and there is a strong correlation between well points. Therefore，the dynamic response of interwell injection-production is studied based on the graph neural network.The fluid production of producing wells is predicted，and backpropagation learning is carried out，so as to quantitatively characterize the dynamic response relationship of interwell injection-production at different times based on the graph attention network，the variation amount of water injection per unit time in injection wells，the variation amount of liquid production per unit time in producing wells at multiple time nodes，and the parameters such as bottom hole pressure and well location data in the information of physical flow process. The results show that the new method is suitable for the actual reservoir with a large number of wells and frequent well opening and shutting operations. The method has the advantages of low cost and has combined dynamic and static parameters，so it can be widely applied.
The dynamic response of interwell injection-production in injection and production wells is an important parameter in the process of reservoir development. The correct evaluation of the dynamic response of interwell injection-production can provide a theoretical basis for optimizing process measures of flow field control in the later stage of reservoir development. Injection-production well pattern can be equivalent to a graph structure，and there is a strong correlation between well points. Therefore，the dynamic response of interwell injection-production is studied based on the graph neural network.The fluid production of producing wells is predicted，and backpropagation learning is carried out，so as to quantitatively characterize the dynamic response relationship of interwell injection-production at different times based on the graph attention network，the variation amount of water injection per unit time in injection wells，the variation amount of liquid production per unit time in producing wells at multiple time nodes，and the parameters such as bottom hole pressure and well location data in the information of physical flow process. The results show that the new method is suitable for the actual reservoir with a large number of wells and frequent well opening and shutting operations. The method has the advantages of low cost and has combined dynamic and static parameters，so it can be widely applied.
2023, 30(4):137-146.
DOI: 10.13673/j.pgre.202210017
Abstract:
The unconsolidated sandstone gas reservoirs are characterized by shallow burial depth，loose reservoir rock，and complex gas-water distribution，and the formation is prone to the problems of edge and bottom water invasion，particle migration，and mud & sand plugging during the production process，resulting in water and sand production in the wellbore，which affects the normal production of the gas field. In this study，the unconsolidated sandstone gas reservoirs of Sebei Gas Field in Qaidam Basin were selected as the research target to study the main influencing factors of water production，sand production，and formation mud & sand plugging based on the analysis of production engineering factors and the theoretical study of plugging mechanism. The simulation experiments of the mud & sand plugging mechanism under different compaction conditions were carried out，and the plugging mechanism of mud & sand particles and its influence degree on the flow capacity of unconsolidated sandstones were studied by means of mercury injection capillary pressure curve，particle size test analysis，and X-ray diffraction analysis. The results reveal that the main factors influencing sand production in gas wells are production pressure difference，formation pressure，and edge-bottom water invasion. The faster decaying formation pressure and the stronger compaction result in increased formation water when the production pressure difference increases. The permeability of the core decreases rapidly due to the effect of water invasion and compaction when the invasion of edge and bottom water occurs in the reservoirs，and the maximum permeability loss rate reaches 77.40%. The hydration dispersion of the core leads to the smaller size of the mud & sand particles，and the released non-expansive particles such as quartz and feldspar will migrate in the formation. There is a bridge blinding rule of 3df < Dp< 10df between the grain size（Dp）and pore throat diameter（df）of the transported mud and sand particles，which causes mud & sand plugging in the reservoir.When the confining pressure reaches 12 MPa，there is a matching relationship of df >1/3DP between the grain size and pore throat diameter of the transported mud & sand particles，and the mud & sand particles are directly plugged in the pore throat. Therefore，it is not recommended to adopt too high production pressure difference during the production process. For the reservoirs with reduced formation pressures，it is advisable to adopt pressurized development to replenish the energy of the formation.
The unconsolidated sandstone gas reservoirs are characterized by shallow burial depth，loose reservoir rock，and complex gas-water distribution，and the formation is prone to the problems of edge and bottom water invasion，particle migration，and mud & sand plugging during the production process，resulting in water and sand production in the wellbore，which affects the normal production of the gas field. In this study，the unconsolidated sandstone gas reservoirs of Sebei Gas Field in Qaidam Basin were selected as the research target to study the main influencing factors of water production，sand production，and formation mud & sand plugging based on the analysis of production engineering factors and the theoretical study of plugging mechanism. The simulation experiments of the mud & sand plugging mechanism under different compaction conditions were carried out，and the plugging mechanism of mud & sand particles and its influence degree on the flow capacity of unconsolidated sandstones were studied by means of mercury injection capillary pressure curve，particle size test analysis，and X-ray diffraction analysis. The results reveal that the main factors influencing sand production in gas wells are production pressure difference，formation pressure，and edge-bottom water invasion. The faster decaying formation pressure and the stronger compaction result in increased formation water when the production pressure difference increases. The permeability of the core decreases rapidly due to the effect of water invasion and compaction when the invasion of edge and bottom water occurs in the reservoirs，and the maximum permeability loss rate reaches 77.40%. The hydration dispersion of the core leads to the smaller size of the mud & sand particles，and the released non-expansive particles such as quartz and feldspar will migrate in the formation. There is a bridge blinding rule of 3df < Dp< 10df between the grain size（Dp）and pore throat diameter（df）of the transported mud and sand particles，which causes mud & sand plugging in the reservoir.When the confining pressure reaches 12 MPa，there is a matching relationship of df >1/3DP between the grain size and pore throat diameter of the transported mud & sand particles，and the mud & sand particles are directly plugged in the pore throat. Therefore，it is not recommended to adopt too high production pressure difference during the production process. For the reservoirs with reduced formation pressures，it is advisable to adopt pressurized development to replenish the energy of the formation.
2023, 30(4):147-155.
DOI: 10.13673/j.pgre.202211034
Abstract:
The development of tight oil reservoirs with volume-fractured horizontal wells under natural depletion faces the problems of rapid production decline and low primary oil recovery. Because the remaining oil potential in each fractured section of horizontal wells is unclear，the production performance of the horizontal wells after refracturing shows a significant difference. Determining the remaining oil potential of each fractured section in horizontal wells is of great significance to the design of the refracturing scheme and the improvement of the horizontal well production performance. Therefore，Block FX in Ordos Basin was taken as an example，and 12 factors were selected as input parameters of the back propagation（BP）neural network by analyzing the influencing factors of hydraulic fracturing-stimulated reservoir volume. As a result，the BP neural network prediction model for fracture length and fracture zone width was established. The prediction errors of seven test samples were 4.91% and 2.42%，respectively，which were relatively small，indicating that the prediction results of this model were accurate and reliable. On this basis，the remaining oil in fractured sections was quantitatively studied by using the volumetric method and the equivalent fractured well diameter model. The method was applied to the horizontal wells in the study area. According to the remaining oil potential evaluation results of each fractured section，the targeted refracturing measure was designed，and the field test was carried out，which achieved positive results and further verified the reliability of the method.
The development of tight oil reservoirs with volume-fractured horizontal wells under natural depletion faces the problems of rapid production decline and low primary oil recovery. Because the remaining oil potential in each fractured section of horizontal wells is unclear，the production performance of the horizontal wells after refracturing shows a significant difference. Determining the remaining oil potential of each fractured section in horizontal wells is of great significance to the design of the refracturing scheme and the improvement of the horizontal well production performance. Therefore，Block FX in Ordos Basin was taken as an example，and 12 factors were selected as input parameters of the back propagation（BP）neural network by analyzing the influencing factors of hydraulic fracturing-stimulated reservoir volume. As a result，the BP neural network prediction model for fracture length and fracture zone width was established. The prediction errors of seven test samples were 4.91% and 2.42%，respectively，which were relatively small，indicating that the prediction results of this model were accurate and reliable. On this basis，the remaining oil in fractured sections was quantitatively studied by using the volumetric method and the equivalent fractured well diameter model. The method was applied to the horizontal wells in the study area. According to the remaining oil potential evaluation results of each fractured section，the targeted refracturing measure was designed，and the field test was carried out，which achieved positive results and further verified the reliability of the method.
16 Research progress on fracture propagation patterns of hydraulic fracturing in heterogeneous shale
2023, 30(4):156-166.
DOI: 10.13673/j.pgre.202306005
Abstract:
Hydraulic fracturing techniques have been widely used in China to create complex fracture networks in shale reservoirs，while shale reservoirs exhibit high heterogeneity due to the difference in mineral compositions and the widespread presence of discontinuous interfaces（beddings and natural fractures），which directly affects and constrains the hydraulic fracturing effects in reservoirs.Based on the heterogeneity of microscopic mineral composition and macroscopic structure of shale，the research progress of fracture propagation patterns of hydraulic fracturing is systematically described. Firstly，the impact of brittle degree caused by mineral composition differences on the fracture propagation patterns of hydraulic fracturing is analyzed. Secondly，the key geological and engineering factors affecting the interaction modes between fractures by hydraulic fracturing and natural fractures are summarized，and the interaction mechanisms between fractures by hydraulic fracturing and natural fractures are discussed. Finally，the influence mechanisms of shale bedding on the fracture propagation of hydraulic fracturing is studied，and the influence law of key parameters such as bedding plane inclination，cementation strength，and density on the bedding plane cracking and fracture penetration and propagation patterns of hydraulic fracturing is expounded. This paper reviews the existing problems and development trends in the research on hydraulic fracturing of heterogeneous shale and provides an important theoretical basis for the optimization of fracture design.
Hydraulic fracturing techniques have been widely used in China to create complex fracture networks in shale reservoirs，while shale reservoirs exhibit high heterogeneity due to the difference in mineral compositions and the widespread presence of discontinuous interfaces（beddings and natural fractures），which directly affects and constrains the hydraulic fracturing effects in reservoirs.Based on the heterogeneity of microscopic mineral composition and macroscopic structure of shale，the research progress of fracture propagation patterns of hydraulic fracturing is systematically described. Firstly，the impact of brittle degree caused by mineral composition differences on the fracture propagation patterns of hydraulic fracturing is analyzed. Secondly，the key geological and engineering factors affecting the interaction modes between fractures by hydraulic fracturing and natural fractures are summarized，and the interaction mechanisms between fractures by hydraulic fracturing and natural fractures are discussed. Finally，the influence mechanisms of shale bedding on the fracture propagation of hydraulic fracturing is studied，and the influence law of key parameters such as bedding plane inclination，cementation strength，and density on the bedding plane cracking and fracture penetration and propagation patterns of hydraulic fracturing is expounded. This paper reviews the existing problems and development trends in the research on hydraulic fracturing of heterogeneous shale and provides an important theoretical basis for the optimization of fracture design.
2023, 30(4):167-172.
DOI: 10.13673/j.pgre.202204019
Abstract:
Experiments on the conductivity of propped fracture in tight dolomite reservoirs were conducted to analyze the effects of different factors on the conductivity of propped fractures and thus explore the adaptability of proppant fracturing technology to dolomite reservoir stimulation. The experimental results showed that the factors affecting the conductivity of propped fractures in dolomite reservoirs are as follows：the particle sizes of proppants，proppant concentrations，proppant injection modes，proppant laying methods，and proppant strength. Compared with a single proppant，the mixed proppant can obtain better conductivity，and a larger particle size is accompanied by a higher proportion of proppants and better conductivity. In addition，the conductivity of fractures registers significant fluctuations under the pulsed proppant injection mode，but it can satisfy the stimulation requirement of dolomite reservoirs. Considering the fracturing effect and cost，the on-site sand fracturing needs in the dolomite reservoir can be met with the proppant strength of 69 MPa and an average proppant concentration of 1.8 kg/m2. The dolomite reservoir has a small fracture width because of the large Young’s modulus and high closure stress. Hence，the risk of proppant plugs in proppant fracturing can be reduced to a certain extent by the pulsed proppant injection mode.
Experiments on the conductivity of propped fracture in tight dolomite reservoirs were conducted to analyze the effects of different factors on the conductivity of propped fractures and thus explore the adaptability of proppant fracturing technology to dolomite reservoir stimulation. The experimental results showed that the factors affecting the conductivity of propped fractures in dolomite reservoirs are as follows：the particle sizes of proppants，proppant concentrations，proppant injection modes，proppant laying methods，and proppant strength. Compared with a single proppant，the mixed proppant can obtain better conductivity，and a larger particle size is accompanied by a higher proportion of proppants and better conductivity. In addition，the conductivity of fractures registers significant fluctuations under the pulsed proppant injection mode，but it can satisfy the stimulation requirement of dolomite reservoirs. Considering the fracturing effect and cost，the on-site sand fracturing needs in the dolomite reservoir can be met with the proppant strength of 69 MPa and an average proppant concentration of 1.8 kg/m2. The dolomite reservoir has a small fracture width because of the large Young’s modulus and high closure stress. Hence，the risk of proppant plugs in proppant fracturing can be reduced to a certain extent by the pulsed proppant injection mode.
2023, 30(4):173-182.
DOI: 10.13673/j.pgre.202208037
Abstract:
In order to enhance oil recovery in fracturing sections with a small fracturing scale，low fracture network permeability，and abundant reserves，the temporary plugging enhancing water injection huff and puff technology is proposed. The technology expands the swept area of injected water by injecting temporary plugging agents during water injection huff and puff，thus improving the water injection huff and puff development effect of horizontal wells after several cycles. In this paper，core samples with different fracture apertures are connected in parallel to comparatively analyze the producing ratio of the crude oil in the core samples with different fracture apertures during water injection huff and puff and temporary plugging enhancing water injection huff and puff.Then，experiments are carried out to explore the plugging characteristics of filter cake of the temporary plugging agents，and a mathematical model of temporary plugging and diversion for horizontal wells is established by considering the variable mass flow in the wellbore，so as to study the influence of temporary plugging agents’mass concentration and injection rate on diversion efficiency.Results show that temporary plugging enhancing water injection huff and puff can enhance oil recovery of the core samples with a large fracture aperture and a small fracture aperture by 3.46% and 1.71%，respectively，thus improving the development effect of the water injection huff and puff.According to the relationship between the pressure drop through the filter cake of the temporary plugging agents and the injection time，the drag coefficient of the filter cake is determined to be 1.13×108 m?2. In addition，higher temporary plugging agents’mass concentration and injection rate indicate higher diversion efficiency.
In order to enhance oil recovery in fracturing sections with a small fracturing scale，low fracture network permeability，and abundant reserves，the temporary plugging enhancing water injection huff and puff technology is proposed. The technology expands the swept area of injected water by injecting temporary plugging agents during water injection huff and puff，thus improving the water injection huff and puff development effect of horizontal wells after several cycles. In this paper，core samples with different fracture apertures are connected in parallel to comparatively analyze the producing ratio of the crude oil in the core samples with different fracture apertures during water injection huff and puff and temporary plugging enhancing water injection huff and puff.Then，experiments are carried out to explore the plugging characteristics of filter cake of the temporary plugging agents，and a mathematical model of temporary plugging and diversion for horizontal wells is established by considering the variable mass flow in the wellbore，so as to study the influence of temporary plugging agents’mass concentration and injection rate on diversion efficiency.Results show that temporary plugging enhancing water injection huff and puff can enhance oil recovery of the core samples with a large fracture aperture and a small fracture aperture by 3.46% and 1.71%，respectively，thus improving the development effect of the water injection huff and puff.According to the relationship between the pressure drop through the filter cake of the temporary plugging agents and the injection time，the drag coefficient of the filter cake is determined to be 1.13×108 m?2. In addition，higher temporary plugging agents’mass concentration and injection rate indicate higher diversion efficiency.
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