Volume 29,Issue 2,2022 Table of Contents
2022, 29(2):1-14.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.001
Abstract:
Huagang Formation sandstone has a great buried depth range in the north-central part of the central reversal structural belt in Xihu Sag，and different layers differ in reservoir quality. In virtue of the data such as mold thin sections，scanning electron microscopes（SEM），X-ray diffraction（XRD），and physical properties，this paper systematically analyzed the fundamental features and the diagenetic differential evolution of different layers of sandstone reservoirs by referring to the regional geological background and burial history. The study shows that the physical properties and pore types of Huagang Formation sandstone reservoirs are distinctly different above and below the vertical demarcation line with a buried depth of 4 100 m. The part above 4 100 m matches H3-H4 reservoirs，which are buried shallowly and relatively rich in volcanic rock debris. The weak compaction and pressure dissolution and the common chlorite coat jointly inhibit the secondary enlargement of quartz and effectively preserve the primary pores，providing conditions for later large-scale organic acid dissolution. As a result，both primary and secondary pores are well developed，and highly porous zones exist in the reservoirs.The part below 4 100 m mainly corresponds to H5-H6 reservoirs，which are buried deeply and rich in metamorphic rock debris. The poorly-developed chlorite coats fail to effectively inhibit the secondary enlargement of quartz. In addition，strong compaction and pressure dissolution result in the large loss of pores in the rapid burial stage，which is inconducive to the pore increasing by organic acid dissolution in the later stage. Exposed to the alkaline diagenetic environment for a long time，pores are filled by a large amount of authigenic mineral cement，which makes the reservoirs relatively dense.
Huagang Formation sandstone has a great buried depth range in the north-central part of the central reversal structural belt in Xihu Sag，and different layers differ in reservoir quality. In virtue of the data such as mold thin sections，scanning electron microscopes（SEM），X-ray diffraction（XRD），and physical properties，this paper systematically analyzed the fundamental features and the diagenetic differential evolution of different layers of sandstone reservoirs by referring to the regional geological background and burial history. The study shows that the physical properties and pore types of Huagang Formation sandstone reservoirs are distinctly different above and below the vertical demarcation line with a buried depth of 4 100 m. The part above 4 100 m matches H3-H4 reservoirs，which are buried shallowly and relatively rich in volcanic rock debris. The weak compaction and pressure dissolution and the common chlorite coat jointly inhibit the secondary enlargement of quartz and effectively preserve the primary pores，providing conditions for later large-scale organic acid dissolution. As a result，both primary and secondary pores are well developed，and highly porous zones exist in the reservoirs.The part below 4 100 m mainly corresponds to H5-H6 reservoirs，which are buried deeply and rich in metamorphic rock debris. The poorly-developed chlorite coats fail to effectively inhibit the secondary enlargement of quartz. In addition，strong compaction and pressure dissolution result in the large loss of pores in the rapid burial stage，which is inconducive to the pore increasing by organic acid dissolution in the later stage. Exposed to the alkaline diagenetic environment for a long time，pores are filled by a large amount of authigenic mineral cement，which makes the reservoirs relatively dense.
2022, 29(2):15-22.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.002
Abstract:
The buried-hill reservoir in Proterozoic bedrock is one of the important fields of oil and gas exploration in Mahaidong area，northern margin of Qaidam Basin，and the reservoir represents one of the main factors affecting oil and gas accumulation in bedrock. According to the data of the outcrop，core，thin section，scanning electron microscopy，imaging logging，etc.，the development and influencing factors of bedrock reservoirs were studied. The results demonstrate that the Proterozoic bedrock reservoirs in Mahaidong area developed 9 rock types in 4 categories，including schist，gneiss，eclogite，and amphibole，and 6 reservoir space types in 2 categories，including fractures and dissolution pores，and the reservoir petrophysical properties are dominated by low porosity and（extra-）low permeability. Moreover，the bedrock fracture is a key factor influencing the development of dissolution pores and dissolution fractures as well as the high yield of a reservoir. The development of fractures is mainly controlled by lithology and structure. Fractures of schist and gneiss with a high content of brittle minerals are highly developed，and more fractures are developed when they are closer to the fault at a higher grade and with a longer active time. In addition，the hanging wall and intersection of faults are the dominant development areas for reservoirs.
The buried-hill reservoir in Proterozoic bedrock is one of the important fields of oil and gas exploration in Mahaidong area，northern margin of Qaidam Basin，and the reservoir represents one of the main factors affecting oil and gas accumulation in bedrock. According to the data of the outcrop，core，thin section，scanning electron microscopy，imaging logging，etc.，the development and influencing factors of bedrock reservoirs were studied. The results demonstrate that the Proterozoic bedrock reservoirs in Mahaidong area developed 9 rock types in 4 categories，including schist，gneiss，eclogite，and amphibole，and 6 reservoir space types in 2 categories，including fractures and dissolution pores，and the reservoir petrophysical properties are dominated by low porosity and（extra-）low permeability. Moreover，the bedrock fracture is a key factor influencing the development of dissolution pores and dissolution fractures as well as the high yield of a reservoir. The development of fractures is mainly controlled by lithology and structure. Fractures of schist and gneiss with a high content of brittle minerals are highly developed，and more fractures are developed when they are closer to the fault at a higher grade and with a longer active time. In addition，the hanging wall and intersection of faults are the dominant development areas for reservoirs.
2022, 29(2):23-33.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.003
Abstract:
On the basis of the field sections’data and results of core observation，we established the identification standards of interlayers in the vertical direction for underwater distributary channel sandbodies and the division standards of the single sandbodies in the lateral direction with logging and performance data in the study area. Further，we identified the single sandbodies in underwater distributary channels in Chang812 of L158 Block，Huanjiang Oilfield，Ordos Basin，analyzed the spatial superposition types of the single sandbodies and calculated their proportions. At last，we studied the influence of these superposition relationship modes on the connectivity among the sandbodies and expounded the distribution characteristics of the remaining oil. The results show that the widths of single river channels of Chang812 in L158 Block，Huanjiang Oilfield are 230-450 m，and the thicknesses of the single sandbodies are 4-10 m. Seven superposition types are found from the single sandbodies, i.e.，three in the vertical direction (separated type，vertical contact type，and vertical cutting type) and four in the lateral direction (interdistributary contact type，embankment contact type，butt contact type，and side cutting contact type). There are 10 spatial combination modes，dominated by separated-side cutting and vertical contact-side cutting combinations. The remaining oil is enriched in the flanks of the upper single sandbodies and the tops of the lower single sandbodies of the two-way weakly connected sandbodies，and the flanks of the upper single sandbodies of the weakly connected sandbodies in the lateral direction，but it is not enriched in the lower single sandbodies of the weakly connected sandbodies in the lateral direction and the strongly connected sandbodies.
On the basis of the field sections’data and results of core observation，we established the identification standards of interlayers in the vertical direction for underwater distributary channel sandbodies and the division standards of the single sandbodies in the lateral direction with logging and performance data in the study area. Further，we identified the single sandbodies in underwater distributary channels in Chang812 of L158 Block，Huanjiang Oilfield，Ordos Basin，analyzed the spatial superposition types of the single sandbodies and calculated their proportions. At last，we studied the influence of these superposition relationship modes on the connectivity among the sandbodies and expounded the distribution characteristics of the remaining oil. The results show that the widths of single river channels of Chang812 in L158 Block，Huanjiang Oilfield are 230-450 m，and the thicknesses of the single sandbodies are 4-10 m. Seven superposition types are found from the single sandbodies, i.e.，three in the vertical direction (separated type，vertical contact type，and vertical cutting type) and four in the lateral direction (interdistributary contact type，embankment contact type，butt contact type，and side cutting contact type). There are 10 spatial combination modes，dominated by separated-side cutting and vertical contact-side cutting combinations. The remaining oil is enriched in the flanks of the upper single sandbodies and the tops of the lower single sandbodies of the two-way weakly connected sandbodies，and the flanks of the upper single sandbodies of the weakly connected sandbodies in the lateral direction，but it is not enriched in the lower single sandbodies of the weakly connected sandbodies in the lateral direction and the strongly connected sandbodies.
2022, 29(2):34-45.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.004
Abstract:
The research on the in-situ stress of Dabei12 gas reservoir in Kelasu structural belt of Kuqa Depression was carried out to clarify the distribution of in-situ stress in deep reservoirs and explore the heterogeneous distribution mechanism of the in-situ stress. In addition，suggestions were put forward for well placement against a complex geological background.The results demonstrate that the reservoir at more than 4 500 m in Kelasu structural belt follows a strike-slip in-situ stress mechanism. The maximum horizontal principal stress in Dabei12 gas reservoir ranges from 125 to 160 MPa，and the minimum horizontal principal stress is 118-130 MPa. The in-situ stress shows strong heterogeneity and the difference between wells is evident. Complex geological boundary conditions and interbedded lithology of the reservoir lead to the extremely heterogeneous in-situ stress distribution. Favorable and unfavorable areas of in-situ stress are alternately distributed，and the unfavorable area may also be drilled in the structural high. Therefore，the plan of“occupying the high point along the long axis”cannot be simply implemented for well placement. Moreover，a directional well crosses a wide favorable area，with a high probability of penetration of fractures as well as a safe and stable well trajectory，and it can avoid obstacles and risks. Accordingly，it is a preferable well type against a complex geological background. It is suggested that the well trajectory should be designed in the direction with low stress，well-developed fracture，and high borehole wall stability，and a reasonable reservoir simulation mode should be selected according to in-situ stress.
The research on the in-situ stress of Dabei12 gas reservoir in Kelasu structural belt of Kuqa Depression was carried out to clarify the distribution of in-situ stress in deep reservoirs and explore the heterogeneous distribution mechanism of the in-situ stress. In addition，suggestions were put forward for well placement against a complex geological background.The results demonstrate that the reservoir at more than 4 500 m in Kelasu structural belt follows a strike-slip in-situ stress mechanism. The maximum horizontal principal stress in Dabei12 gas reservoir ranges from 125 to 160 MPa，and the minimum horizontal principal stress is 118-130 MPa. The in-situ stress shows strong heterogeneity and the difference between wells is evident. Complex geological boundary conditions and interbedded lithology of the reservoir lead to the extremely heterogeneous in-situ stress distribution. Favorable and unfavorable areas of in-situ stress are alternately distributed，and the unfavorable area may also be drilled in the structural high. Therefore，the plan of“occupying the high point along the long axis”cannot be simply implemented for well placement. Moreover，a directional well crosses a wide favorable area，with a high probability of penetration of fractures as well as a safe and stable well trajectory，and it can avoid obstacles and risks. Accordingly，it is a preferable well type against a complex geological background. It is suggested that the well trajectory should be designed in the direction with low stress，well-developed fracture，and high borehole wall stability，and a reasonable reservoir simulation mode should be selected according to in-situ stress.
2022, 29(2):46-52.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.005
Abstract:
Systematic errors are encountered in the interpretation of pressure data from different instruments in the eastern South China Sea；as a result，the correlation between mobility and core permeability is poor，and the matching between the permeability from pressure measurement and DST is low. Aiming at the Paleogene low permeability reservoirs in the eastern South China Sea，this paper improved the quantitative evaluation standard of pressure data quality and unified the method for mobility calculation. Reservoir pollution was analyzed to build a mobility correction model，and the discriminant function of pollution was established by the Bayesian discriminant method for pollution discrimination and correction. In addition，given the dynamic permeability from wireline formation testing and the static permeability from core analysis，the upscaling permeability conversion model was constructed considering logging permeability. The results demonstrate that the permeability corrected by pressure measurement and the logging permeability calibrated by core permeability are in good agreement，and the upscaling permeability is obtained by conversion and close to DST permeability. This study significantly improves the permeability evaluation accuracy of pressure data.
Systematic errors are encountered in the interpretation of pressure data from different instruments in the eastern South China Sea；as a result，the correlation between mobility and core permeability is poor，and the matching between the permeability from pressure measurement and DST is low. Aiming at the Paleogene low permeability reservoirs in the eastern South China Sea，this paper improved the quantitative evaluation standard of pressure data quality and unified the method for mobility calculation. Reservoir pollution was analyzed to build a mobility correction model，and the discriminant function of pollution was established by the Bayesian discriminant method for pollution discrimination and correction. In addition，given the dynamic permeability from wireline formation testing and the static permeability from core analysis，the upscaling permeability conversion model was constructed considering logging permeability. The results demonstrate that the permeability corrected by pressure measurement and the logging permeability calibrated by core permeability are in good agreement，and the upscaling permeability is obtained by conversion and close to DST permeability. This study significantly improves the permeability evaluation accuracy of pressure data.
2022, 29(2):53-60.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.006
Abstract:
The Ruman buried hill in the Melut Basin has experienced multi-stage tectonic evolution，resulting in complex hydrocarbon accumulation modes in this area. To reveal the role of the tectonic evolution of the Ruman buried hill in controlling hydrocarbon accumulation and further explore the exploration potential in this area，this paper combined seismic，drilling，and regional tectonic data for structural evolution analysis based on the balanced cross-section technique. Moreover，based on the hydrocarbon generation and expulsion history of source rocks，the dynamic accumulation process of reservoirs around the Ruman buried hill was analyzed. The results show that the Ruman buried hill has experienced two largescale tilting uplift activities since the Cretaceous. The tilting uplift in the late Cretaceous was beneficial to the stratigraphiclithologic traps around the buried hill，and those in the late Paleogene led to the exposure of buried hills，which destroyed the primary reservoirs that formed earlier，leading to secondary heavy oil reservoirs. In addition，the tectonic activity has been weak since the Neogene. It results in the stratigraphic-lithologic heavy oil reservoirs of the Cretaceous Galhak Formation and the structural-lithologic heavy oil reservoirs of the Neogene Jimidi Formation in the late accumulation around the Ruman buried hill，and both the reservoirs show great exploration potential.
The Ruman buried hill in the Melut Basin has experienced multi-stage tectonic evolution，resulting in complex hydrocarbon accumulation modes in this area. To reveal the role of the tectonic evolution of the Ruman buried hill in controlling hydrocarbon accumulation and further explore the exploration potential in this area，this paper combined seismic，drilling，and regional tectonic data for structural evolution analysis based on the balanced cross-section technique. Moreover，based on the hydrocarbon generation and expulsion history of source rocks，the dynamic accumulation process of reservoirs around the Ruman buried hill was analyzed. The results show that the Ruman buried hill has experienced two largescale tilting uplift activities since the Cretaceous. The tilting uplift in the late Cretaceous was beneficial to the stratigraphiclithologic traps around the buried hill，and those in the late Paleogene led to the exposure of buried hills，which destroyed the primary reservoirs that formed earlier，leading to secondary heavy oil reservoirs. In addition，the tectonic activity has been weak since the Neogene. It results in the stratigraphic-lithologic heavy oil reservoirs of the Cretaceous Galhak Formation and the structural-lithologic heavy oil reservoirs of the Neogene Jimidi Formation in the late accumulation around the Ruman buried hill，and both the reservoirs show great exploration potential.
2022, 29(2):61-68.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.007
Abstract:
The Doseo Basin，located in the center of the Central African Shear Zone（CASZ），is a strike-slip pull-apart basin with a low exploration degree and has not been discovered commercially. However，the adjacent Doba Basin with similar geological backgrounds has seen successive oil and gas discovery. Therefore，with the existing drilling，logging，and seismic data，this paper carried out a preliminary but systematic study on the development characteristics of source rocks in the Doseo Basin. The results show that the Aptian（Early Cretaceous）middle-deep lacustrine and argillaceous source rocks with oil potential are well developed in the Doseo Basin，featuring great thickness，wide distribution of effective source rocks，and huge hydrocarbon generation-expulsion potential. The eastern hydrocarbon generation kitchen is a hydrocarbonrich sag with its source-rock thickness，plane distribution scale，geochemical indexes，and hydrocarbon generation-expulsion intensity and amount much better than those in the western hydrocarbon generation kitchen. The hydrocarbon generation-expulsion history matches well with the formation time of traps and the development time of vertical migration channels and faults. Three exploration suggestions are put forward：①pay close attention to the Doseo Basin and increase explo?ration efforts，②collect 3D seismic data and carry out in-depth research on basic geology and petroleum geology，and ③se?lect favorable exploration zones to obtain high-quality blocks and large oil and gas discovery in the basin as soon as possi?ble.
The Doseo Basin，located in the center of the Central African Shear Zone（CASZ），is a strike-slip pull-apart basin with a low exploration degree and has not been discovered commercially. However，the adjacent Doba Basin with similar geological backgrounds has seen successive oil and gas discovery. Therefore，with the existing drilling，logging，and seismic data，this paper carried out a preliminary but systematic study on the development characteristics of source rocks in the Doseo Basin. The results show that the Aptian（Early Cretaceous）middle-deep lacustrine and argillaceous source rocks with oil potential are well developed in the Doseo Basin，featuring great thickness，wide distribution of effective source rocks，and huge hydrocarbon generation-expulsion potential. The eastern hydrocarbon generation kitchen is a hydrocarbonrich sag with its source-rock thickness，plane distribution scale，geochemical indexes，and hydrocarbon generation-expulsion intensity and amount much better than those in the western hydrocarbon generation kitchen. The hydrocarbon generation-expulsion history matches well with the formation time of traps and the development time of vertical migration channels and faults. Three exploration suggestions are put forward：①pay close attention to the Doseo Basin and increase explo?ration efforts，②collect 3D seismic data and carry out in-depth research on basic geology and petroleum geology，and ③se?lect favorable exploration zones to obtain high-quality blocks and large oil and gas discovery in the basin as soon as possi?ble.
8 Calculation of two-phase relative permeability curves based on a low-velocity non-Darcy flow model
2022, 29(2):69-76.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.008
Abstract:
The fluid flow in ultra-low permeability-tight oil reservoirs does not conform to Darcy’s law，which cannot be determined by the conventional Johnson，Bossler，and Naumann（JBN）method for calculating two-phase relative permeability curves. Considering the pseudo threshold pressure gradient of two-phase flow，the empirical relation was obtained through statistics for processing the experimental data of low-velocity non-Darcy flow and acquiring more accurate relative permeability curves. This empirical relation was employed to calculate the pseudo threshold pressure gradient at any water cut of rock samples with different air permeability. According to the experimental results of two-phase steady flow in low-permeability rock samples，a hypothesis was proposed，in which the pseudo threshold pressure gradients of different phases in the two-phase flow were equal，and a two-phase low-velocity non-Darcy flow model was constructed. Based on this model，a method was developed to obtain the relative permeability curves of two-phase non-Darcy flow. The proposed method were compared with the JBN method by using the experimental data of the rock samples from Daqing Oilfield. The results demonstrate that the relative permeability of the oil phase and the water phase changes significantly after considering the influence from the pseudo threshold pressure gradient of the two-phase flow.
The fluid flow in ultra-low permeability-tight oil reservoirs does not conform to Darcy’s law，which cannot be determined by the conventional Johnson，Bossler，and Naumann（JBN）method for calculating two-phase relative permeability curves. Considering the pseudo threshold pressure gradient of two-phase flow，the empirical relation was obtained through statistics for processing the experimental data of low-velocity non-Darcy flow and acquiring more accurate relative permeability curves. This empirical relation was employed to calculate the pseudo threshold pressure gradient at any water cut of rock samples with different air permeability. According to the experimental results of two-phase steady flow in low-permeability rock samples，a hypothesis was proposed，in which the pseudo threshold pressure gradients of different phases in the two-phase flow were equal，and a two-phase low-velocity non-Darcy flow model was constructed. Based on this model，a method was developed to obtain the relative permeability curves of two-phase non-Darcy flow. The proposed method were compared with the JBN method by using the experimental data of the rock samples from Daqing Oilfield. The results demonstrate that the relative permeability of the oil phase and the water phase changes significantly after considering the influence from the pseudo threshold pressure gradient of the two-phase flow.
2022, 29(2):77-84.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.009
Abstract:
To address the low CO2 sweep efficiency and gas channeling in low-permeability reservoirs，this paper synthesized the CO2/N2 responsive nano-SiO2 to control gas channeling and fingering and increase the swept range of CO2 flooding.The synthesized responsive nano-SiO2 was characterized by infrared spectroscopy，thermogravimetric analysis，and other methods. Systematic research was conducted on its particle size，responsiveness，adsorption capacity，and dispersion stability under dispersion conditions. Moreover，a core flow device was employed for the simulation experiment of oil displacement in the presence of the CO2/N2 responsive nano-dispersion system. The results show that the CO2/N2 responsive nanoSiO2 meets the expected design. Under the dispersion conditions，the average particle size of the responsive nano-SiO2 is 58.8 nm，which is responsive to CO2/N2. The CO2 adsorption capacity reaches 196.8 mmol/g，which indicates dispersion stability. The 3 PV nano-dispersion system has a blocking rate of 89.38% in a core with permeability of 5.8 mD and realizes enhanced oil recovery（EOR）of 15.15% and ultimate recovery of 53.44%. In the simulated core experiment，the gas channeling channel in the formation is blocked owing to particle agglomeration of the responsive nano-SiO2 dispersion system at the deprotonation state，and thereby the oil displacement effect of the low-permeability channel is increased. In short，the developed CO2/N2 responsive nano-SiO2 dispersion system is capable of both effectively blocking gas channeling channels in formations and enhancing the sweep efficiency of CO2 flooding.
To address the low CO2 sweep efficiency and gas channeling in low-permeability reservoirs，this paper synthesized the CO2/N2 responsive nano-SiO2 to control gas channeling and fingering and increase the swept range of CO2 flooding.The synthesized responsive nano-SiO2 was characterized by infrared spectroscopy，thermogravimetric analysis，and other methods. Systematic research was conducted on its particle size，responsiveness，adsorption capacity，and dispersion stability under dispersion conditions. Moreover，a core flow device was employed for the simulation experiment of oil displacement in the presence of the CO2/N2 responsive nano-dispersion system. The results show that the CO2/N2 responsive nanoSiO2 meets the expected design. Under the dispersion conditions，the average particle size of the responsive nano-SiO2 is 58.8 nm，which is responsive to CO2/N2. The CO2 adsorption capacity reaches 196.8 mmol/g，which indicates dispersion stability. The 3 PV nano-dispersion system has a blocking rate of 89.38% in a core with permeability of 5.8 mD and realizes enhanced oil recovery（EOR）of 15.15% and ultimate recovery of 53.44%. In the simulated core experiment，the gas channeling channel in the formation is blocked owing to particle agglomeration of the responsive nano-SiO2 dispersion system at the deprotonation state，and thereby the oil displacement effect of the low-permeability channel is increased. In short，the developed CO2/N2 responsive nano-SiO2 dispersion system is capable of both effectively blocking gas channeling channels in formations and enhancing the sweep efficiency of CO2 flooding.
2022, 29(2):85-93.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.010
Abstract:
To quantify the producer development effect in high water-cut reservoirs，we constructed characteristic indexes from numerical simulation and machine learning. The backward flight time of the producer control area was obtained by numerical simulation. The flow heterogeneity of producers was evaluated based on the Lorentz coefficient. The potential index was proposed to describe the potential and displacement capacity of producers in the control area. The copious development performance data of oilfield were collected to establish the time series model. The vector autoregression（VAR）algorithm was used to fit the production history of producers；the production capacity of producers was evaluated through impulse response analysis. The comprehensive evaluation scores of producer were given with the entropy weight method. As a result，the two methods with different assumptions led to similar trends in producer scores. The final score could objectively reflect the development effect of producer with the consideration of the influence of numerical simulation and development performance data. The evaluation method was applied to Y Block of G Oilfield in China to score producers. Eventually，four efficiently developed producers were identified.
To quantify the producer development effect in high water-cut reservoirs，we constructed characteristic indexes from numerical simulation and machine learning. The backward flight time of the producer control area was obtained by numerical simulation. The flow heterogeneity of producers was evaluated based on the Lorentz coefficient. The potential index was proposed to describe the potential and displacement capacity of producers in the control area. The copious development performance data of oilfield were collected to establish the time series model. The vector autoregression（VAR）algorithm was used to fit the production history of producers；the production capacity of producers was evaluated through impulse response analysis. The comprehensive evaluation scores of producer were given with the entropy weight method. As a result，the two methods with different assumptions led to similar trends in producer scores. The final score could objectively reflect the development effect of producer with the consideration of the influence of numerical simulation and development performance data. The evaluation method was applied to Y Block of G Oilfield in China to score producers. Eventually，four efficiently developed producers were identified.
2022, 29(2):94-99.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.011
Abstract:
In this paper，two kinds of synthetic cores with a wettability index（WI）in the range of?0.7-0.7 are comparatively used to explore the main difference in the influence of wettability on waterflooding characteristics of ultra-low permeability and medium-high permeability cores. The results reveal that for the homogeneous cores with ultra-low and medium-high permeability，the influence trend of wettability on waterflooding characteristics is similar. Specifically，stronger lipophilicity and hydrophilicity of cores（more deviated from the medium wettability）are accompanied by the faster breakthrough of waterflooding front，a higher rising rate of average water cut，a higher waterflooding equilibrium pressure gradient，and lower water-free oil displacement efficiency and ultimate oil displacement efficiency. The difference is reflected in the magnitude of the influence of the characteristic parameter values. Compared with the medium-high permeability cores，the ultra-low permeability cores are much more susceptible to the influence of the wettability index on aspects including the rising rate of average water cut，equilibrium pressure gradient，and ultimate oil displacement efficiency. The waterflooding characteristics of ultra-low permeability reservoirs are more sensitive to wettability compared with those of medium-high permeability reservoirs. The transition of wettability from oil-wet to medium-wet in ultra-low permeability reservoirs has much greater technical potential for improving oil displacement efficiency than that in medium-high permeability reservoirs.
In this paper，two kinds of synthetic cores with a wettability index（WI）in the range of?0.7-0.7 are comparatively used to explore the main difference in the influence of wettability on waterflooding characteristics of ultra-low permeability and medium-high permeability cores. The results reveal that for the homogeneous cores with ultra-low and medium-high permeability，the influence trend of wettability on waterflooding characteristics is similar. Specifically，stronger lipophilicity and hydrophilicity of cores（more deviated from the medium wettability）are accompanied by the faster breakthrough of waterflooding front，a higher rising rate of average water cut，a higher waterflooding equilibrium pressure gradient，and lower water-free oil displacement efficiency and ultimate oil displacement efficiency. The difference is reflected in the magnitude of the influence of the characteristic parameter values. Compared with the medium-high permeability cores，the ultra-low permeability cores are much more susceptible to the influence of the wettability index on aspects including the rising rate of average water cut，equilibrium pressure gradient，and ultimate oil displacement efficiency. The waterflooding characteristics of ultra-low permeability reservoirs are more sensitive to wettability compared with those of medium-high permeability reservoirs. The transition of wettability from oil-wet to medium-wet in ultra-low permeability reservoirs has much greater technical potential for improving oil displacement efficiency than that in medium-high permeability reservoirs.
2022, 29(2):100-108.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.012
Abstract:
The injection-production coupling technologies are an effective method proposed in recent years to enhance oil recovery of the water flooding，of which the dynamic injection-production coupling is the simplest and most common one.At present，there is no clear definition of and targeted systematic research on it. In light of the development characteristics and types of injection-production coupling，this paper clarifies its technical characteristics and proposes its definition，which deepens the understanding of the mechanism underlying the dynamic injection-production coupling to enhance oil recovery. Taking the typical dynamic injection-production coupling unit in Shengli Oilfield as an example，the paper systematically analyzes development characteristics and the development applicabilities of dynamic injection-production coupling in complex fault-block reservoirs. On this basis，the sensitivity of the main controlling factors is evaluated，and the influence of process design parameters（such as intervention timing，water injection parameters of injection wells and production parameters of production wells）on the development effect is analyzed. As a result，the technical policy boundaries of dynamic injection-production coupling design are clarified. The results show that the dynamic injection-production coupling presents two methods：short injection followed by long production and intermittent injection after production. The former is suitable for multiple rounds of development，while the latter is not. The intervention timing and periodic injection volume are sensitive factors，while water injection rate and fluid production rate are insensitive factors. The intervention timing is better when the water cut is lower，and the expansion coefficient of periodic injection volume is greater than 1. The development effect of the first round of dynamic injection-production coupling is the most critical.
The injection-production coupling technologies are an effective method proposed in recent years to enhance oil recovery of the water flooding，of which the dynamic injection-production coupling is the simplest and most common one.At present，there is no clear definition of and targeted systematic research on it. In light of the development characteristics and types of injection-production coupling，this paper clarifies its technical characteristics and proposes its definition，which deepens the understanding of the mechanism underlying the dynamic injection-production coupling to enhance oil recovery. Taking the typical dynamic injection-production coupling unit in Shengli Oilfield as an example，the paper systematically analyzes development characteristics and the development applicabilities of dynamic injection-production coupling in complex fault-block reservoirs. On this basis，the sensitivity of the main controlling factors is evaluated，and the influence of process design parameters（such as intervention timing，water injection parameters of injection wells and production parameters of production wells）on the development effect is analyzed. As a result，the technical policy boundaries of dynamic injection-production coupling design are clarified. The results show that the dynamic injection-production coupling presents two methods：short injection followed by long production and intermittent injection after production. The former is suitable for multiple rounds of development，while the latter is not. The intervention timing and periodic injection volume are sensitive factors，while water injection rate and fluid production rate are insensitive factors. The intervention timing is better when the water cut is lower，and the expansion coefficient of periodic injection volume is greater than 1. The development effect of the first round of dynamic injection-production coupling is the most critical.
2022, 29(2):109-116.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.013
Abstract:
This paper studied the plugging capability of controllable self-aggregating（CSA）colloidal particles to channeling paths in an ultra-low permeability heterogeneous oil reservoir as well as the influence of different injection volumes of CSA colloidal particles on reservoir development effects. Specifically，the synthetic homogeneous columnar cores and heterogeneous plate cores were used to perform a percolation experiment of plugging control and water displacement as well as simulation experiment of plugging control and production by natural energy. On the basis of the independently developed experimental devices for oil reservoirs that have an edge and bottom water and are produced by natural energy，the similari? ty simulation of the practical production characteristics of a target reservoir was achieved in the laboratory. Moreover，we clarified the effect of the injection volume of CSA colloidal particles on controlling water channeling，the increasing oil production，maintaining reservoir pressure，enhanced oil recovery，and matrix remaining oil activation. The results show that the CSA colloidal particles with an average particle diameter of 0.5 μm have both good injectability and high plugging capa?bility under the target reservoir conditions. The increase in the injection volume of CSA colloidal particles is conducive to controlling water channeling，improving sweep efficiency of the low-permeability matrix，increasing the oil production rate， and reducing the releasing rate of reservoir pressure. Moreover，it has a profound effect on prolonging the stable production period of an oil well and enhancing reservoir recovery. However，when the injection volume exceeds a certain critical value，the continuous injection does not significantly improve the reservoir production performance. For the target reservoir，the laboratory results reveal that the appropriate injection volume is 0.3 PVc（PVc represents the pore volume of the channeling path），and at this injection volume，the recovery can reach 32.43%. Therefore，an effective plugging control technology for an ultra-low permeability heterogeneous reservoir should provide both suitable plugging agents and an appropriate injection volume.
This paper studied the plugging capability of controllable self-aggregating（CSA）colloidal particles to channeling paths in an ultra-low permeability heterogeneous oil reservoir as well as the influence of different injection volumes of CSA colloidal particles on reservoir development effects. Specifically，the synthetic homogeneous columnar cores and heterogeneous plate cores were used to perform a percolation experiment of plugging control and water displacement as well as simulation experiment of plugging control and production by natural energy. On the basis of the independently developed experimental devices for oil reservoirs that have an edge and bottom water and are produced by natural energy，the similari? ty simulation of the practical production characteristics of a target reservoir was achieved in the laboratory. Moreover，we clarified the effect of the injection volume of CSA colloidal particles on controlling water channeling，the increasing oil production，maintaining reservoir pressure，enhanced oil recovery，and matrix remaining oil activation. The results show that the CSA colloidal particles with an average particle diameter of 0.5 μm have both good injectability and high plugging capa?bility under the target reservoir conditions. The increase in the injection volume of CSA colloidal particles is conducive to controlling water channeling，improving sweep efficiency of the low-permeability matrix，increasing the oil production rate， and reducing the releasing rate of reservoir pressure. Moreover，it has a profound effect on prolonging the stable production period of an oil well and enhancing reservoir recovery. However，when the injection volume exceeds a certain critical value，the continuous injection does not significantly improve the reservoir production performance. For the target reservoir，the laboratory results reveal that the appropriate injection volume is 0.3 PVc（PVc represents the pore volume of the channeling path），and at this injection volume，the recovery can reach 32.43%. Therefore，an effective plugging control technology for an ultra-low permeability heterogeneous reservoir should provide both suitable plugging agents and an appropriate injection volume.
2022, 29(2):117-123.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.014
Abstract:
In view of the complex water invasion characteristics of ultra-deep marine carbonate reservoirs，cores with different types of medium，such as matrix，dissolved pores，and natural fractures are selected to carry out gas-water relative permeability experiments. An experimental device with high temperature and high pressure（150 ℃ and 50 MPa）is built，and the experimental process and scheme are designed. The gas-water two-phase relative permeability is measured under different confining pressures（10，30，and 50 MPa）to plot the relative permeability curves，and the variation characteristics of the curves with the confining pressure are analyzed. The results show that the gas-water relative permeability curves generally move downward with the increase in the confining pressure，and the gas-water relative permeability of the natural fracture core decreases more obviously. The isotonic point of the gas-water relative permeability moves in the direction of low water saturation，and the shapes of the relative permeability curves change. Obvious differences are also observed in the width of the two-phase flow zones in the gas-water relative permeability curves of different media. With the increase in the confining pressure，the width of the two-phase flow zone of the core with dissolved pores undergoes the smallest change.The experimental results can be used to explain the water invasion characteristics of ultra-deep carbonate gas fields and the water production phenomenon of gas wells and provide a basis for determining the water invasion law of such gas reservoirs.
In view of the complex water invasion characteristics of ultra-deep marine carbonate reservoirs，cores with different types of medium，such as matrix，dissolved pores，and natural fractures are selected to carry out gas-water relative permeability experiments. An experimental device with high temperature and high pressure（150 ℃ and 50 MPa）is built，and the experimental process and scheme are designed. The gas-water two-phase relative permeability is measured under different confining pressures（10，30，and 50 MPa）to plot the relative permeability curves，and the variation characteristics of the curves with the confining pressure are analyzed. The results show that the gas-water relative permeability curves generally move downward with the increase in the confining pressure，and the gas-water relative permeability of the natural fracture core decreases more obviously. The isotonic point of the gas-water relative permeability moves in the direction of low water saturation，and the shapes of the relative permeability curves change. Obvious differences are also observed in the width of the two-phase flow zones in the gas-water relative permeability curves of different media. With the increase in the confining pressure，the width of the two-phase flow zone of the core with dissolved pores undergoes the smallest change.The experimental results can be used to explain the water invasion characteristics of ultra-deep carbonate gas fields and the water production phenomenon of gas wells and provide a basis for determining the water invasion law of such gas reservoirs.
2022, 29(2):124-130.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.015
Abstract:
At the middle and high water cut stages of multi-layer sandstone reservoir，the development between layers is uneven，and the interlayer interference is obvious，leading to the great difficulty and low accuracy of productivity prediction for newly drilled adjustment wells. To further analyze the influence of different water cuts on the productivity of multi-layer sandstone reservoirs，this paper constructed the dynamic prediction model of interlayer interference after the variation of interlayer interference coefficients with water cuts was analyzed under different breakthrough coefficients of flow capacity in P Oilfield. The relationship chart of interlayer interference coefficients with the breakthrough coefficients and water cuts was drawn to quantitatively characterize the variation of interlayer interference coefficient with water cuts under different breakthrough coefficients of flow capacity. The productivity formula between productivity index and formation flow coefficient without interlayer interference was constructed to guide the well productivity evaluation of P Oilfield at middle and high water cut stages. The results indicate that the productivity error of new adjustment wells in P Oilfield predicted by interlayer interference correction is 20%，which is lower than that before the correction，indicating a reliable productivity prediction result.
At the middle and high water cut stages of multi-layer sandstone reservoir，the development between layers is uneven，and the interlayer interference is obvious，leading to the great difficulty and low accuracy of productivity prediction for newly drilled adjustment wells. To further analyze the influence of different water cuts on the productivity of multi-layer sandstone reservoirs，this paper constructed the dynamic prediction model of interlayer interference after the variation of interlayer interference coefficients with water cuts was analyzed under different breakthrough coefficients of flow capacity in P Oilfield. The relationship chart of interlayer interference coefficients with the breakthrough coefficients and water cuts was drawn to quantitatively characterize the variation of interlayer interference coefficient with water cuts under different breakthrough coefficients of flow capacity. The productivity formula between productivity index and formation flow coefficient without interlayer interference was constructed to guide the well productivity evaluation of P Oilfield at middle and high water cut stages. The results indicate that the productivity error of new adjustment wells in P Oilfield predicted by interlayer interference correction is 20%，which is lower than that before the correction，indicating a reliable productivity prediction result.
2022, 29(2):131-139.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.016
Abstract:
The distribution area of deep shale gas blocks in Luzhou-western Chongqing area accounts for 86% of the southern Sichuan Basin，and the Ordovician Wufeng Formation-Silurian Longmaxi Formation are the main reservoirs for further large-scale production of natural gas. However，the reservoirs in the western Chongqing Block faces many geological challenges，including thin reservoirs，“dual sweet spots”of geological engineering converging in the same layer，poor connectivity of pores and fractures，large burial depth，developed fault systems，and harsh geostress conditions. Based on the geological and engineering parameters of the wells fractured in the block and combined with the theory on shale gas fracture-network fracturing，big data analysis was adopted to develop optimization measures for the fracturing process to meet different geological challenges. These measures included high drilling ratios in the first layer of the first sub-member in the first member of Longmaxi Formation（Long111），great fracturing fluid intensity，short cluster distances，high proppant concentrations，high pump rates，and temporary plugging and diversion. The adaptive analysis of the fracturing parameters in the fractured wells was carried out to verify the feasibility of those measures. On this basis，a template of fracture-network fracturing parameters suitable for the western Chongqing Block was put forward and applied in the field for fracture-network fracturing. As a result，the fracture complexity and stimulated reservoir volume of a single well were increased by 60.59% and 38.3% respectively compared with the earlier three clusters of wells，and the overall production was high. The single-well test productivity grew by 68.67%，and the cumulative production was enhanced significantly，laying a foundation for the efficient development of deep shale gas reservoirs.
The distribution area of deep shale gas blocks in Luzhou-western Chongqing area accounts for 86% of the southern Sichuan Basin，and the Ordovician Wufeng Formation-Silurian Longmaxi Formation are the main reservoirs for further large-scale production of natural gas. However，the reservoirs in the western Chongqing Block faces many geological challenges，including thin reservoirs，“dual sweet spots”of geological engineering converging in the same layer，poor connectivity of pores and fractures，large burial depth，developed fault systems，and harsh geostress conditions. Based on the geological and engineering parameters of the wells fractured in the block and combined with the theory on shale gas fracture-network fracturing，big data analysis was adopted to develop optimization measures for the fracturing process to meet different geological challenges. These measures included high drilling ratios in the first layer of the first sub-member in the first member of Longmaxi Formation（Long111），great fracturing fluid intensity，short cluster distances，high proppant concentrations，high pump rates，and temporary plugging and diversion. The adaptive analysis of the fracturing parameters in the fractured wells was carried out to verify the feasibility of those measures. On this basis，a template of fracture-network fracturing parameters suitable for the western Chongqing Block was put forward and applied in the field for fracture-network fracturing. As a result，the fracture complexity and stimulated reservoir volume of a single well were increased by 60.59% and 38.3% respectively compared with the earlier three clusters of wells，and the overall production was high. The single-well test productivity grew by 68.67%，and the cumulative production was enhanced significantly，laying a foundation for the efficient development of deep shale gas reservoirs.
2022, 29(2):140-144.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.017
Abstract:
The low-permeability sandstone reservoirs in Shengli Oilfield have many oil layers，strong interlayer heterogeneity，and poor reservoir petrophysical properties. The previously fractured wells are generally subject to low production and low efficiency，and repeated fracturing is urgently needed. For scientific well selection，a method for selecting repeated fracturing wells based on the Pearson correlation coefficient was developed. The reservoir petrophysical properties，fracturing parameters，and production data were comprehensively considered in the method，and the Pearson correlation coefficients of the candidate well and the virtual target well were calculated to quantitatively evaluate the potential of the candidate well for repeated fracturing stimulation. Aiming at a well group in Shengli Dawangbei Oilfield，the proposed well selection method was used to screen out the well with the greatest potential for repeated fracturing stimulation. Repeated fracturing was implemented on the well with multiple temporary-plugging fracturing techniques. After the fracturing，the daily oil production increases from 2.5 t/d to 7.3 t/d，which confirms the effectiveness of the method. It does not require massive samples and complex calculations and can be applied to field practices.
The low-permeability sandstone reservoirs in Shengli Oilfield have many oil layers，strong interlayer heterogeneity，and poor reservoir petrophysical properties. The previously fractured wells are generally subject to low production and low efficiency，and repeated fracturing is urgently needed. For scientific well selection，a method for selecting repeated fracturing wells based on the Pearson correlation coefficient was developed. The reservoir petrophysical properties，fracturing parameters，and production data were comprehensively considered in the method，and the Pearson correlation coefficients of the candidate well and the virtual target well were calculated to quantitatively evaluate the potential of the candidate well for repeated fracturing stimulation. Aiming at a well group in Shengli Dawangbei Oilfield，the proposed well selection method was used to screen out the well with the greatest potential for repeated fracturing stimulation. Repeated fracturing was implemented on the well with multiple temporary-plugging fracturing techniques. After the fracturing，the daily oil production increases from 2.5 t/d to 7.3 t/d，which confirms the effectiveness of the method. It does not require massive samples and complex calculations and can be applied to field practices.
2022, 29(2):145-154.
DOI: 10.13673/j.cnki.cn37-1359/te.2022.02.018
Abstract:
To improve the low productivity and acidification feasibility of volcanic rock reservoirs in Huizhou Sag，Pearl River Mouth Basin，we analyze the characteristics of the target reservoir. The lithology is mainly andesite with a tight core，low porosity，low permeability，and high temperature. Through the research on the high-temperature-resistant and strongly corrosive acid solution systems，we select an acid solution system with a 40.29%-61.29% corrosion rate of rock debris，and the main agent is composed of 12% hydrochloric acid and 30% organic fluorosilicic acid. A corrosion inhibitor that is resistant to as high as 180 ℃ and consists of 4% HZ-1 and 0.7% HZ-2 is selected. Its corrosion rate is 59.33-63.86 g（/ m2·h），which can satisfy the industrial standard. The combined process of deflagration fracturing and acidification can enhance the ability of acidification stimulation. When the skin factor is 0-3，the stimulation ratio is 1.4-4.3，much higher than the prediction data of matrix acidification. The obvious advantages of the combined process of deflagration fracturing and acidification are confirmed by the application of typical well conditions in low permeability reservoirs in China’s offshore oilfields.The acidification of volcanic rocks in this area can be used as a reserve technology to further increase the productivity of oil wells.
To improve the low productivity and acidification feasibility of volcanic rock reservoirs in Huizhou Sag，Pearl River Mouth Basin，we analyze the characteristics of the target reservoir. The lithology is mainly andesite with a tight core，low porosity，low permeability，and high temperature. Through the research on the high-temperature-resistant and strongly corrosive acid solution systems，we select an acid solution system with a 40.29%-61.29% corrosion rate of rock debris，and the main agent is composed of 12% hydrochloric acid and 30% organic fluorosilicic acid. A corrosion inhibitor that is resistant to as high as 180 ℃ and consists of 4% HZ-1 and 0.7% HZ-2 is selected. Its corrosion rate is 59.33-63.86 g（/ m2·h），which can satisfy the industrial standard. The combined process of deflagration fracturing and acidification can enhance the ability of acidification stimulation. When the skin factor is 0-3，the stimulation ratio is 1.4-4.3，much higher than the prediction data of matrix acidification. The obvious advantages of the combined process of deflagration fracturing and acidification are confirmed by the application of typical well conditions in low permeability reservoirs in China’s offshore oilfields.The acidification of volcanic rocks in this area can be used as a reserve technology to further increase the productivity of oil wells.
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