Volume 29,Issue 5,2022 Table of Contents
2022, 29(5):1-14.
DOI: 10.13673/j.cnki.cn37-1359/te.202105007
Abstract:
Dominated by different controlling factors，the response of river-dominated deltaic morphology to its growth processes is short of systematic quantitative study. On the basis of fractal geometry and variable controlling，we utilized sedimentary forward numerical modeling at an architecture scale to extract morphological types and features of river-dominated deltaic main bodies and channel-mouth bar complex lobes（CMCLs）and verify the controlling effects of sediment supply rates，sediment compositions，and basin bathymetry on morphology. Also，we established a quantitative characterization model relating the values of morphological features to dominant controlling factors of growth processes. The results indicate that the morphology of deltaic main bodies and CMCLs can be characterized by included angles between main distributary channels at initial river mouths，joint distance，the number of channel-mouth bar complexes at a river mouth or a joint，and the number and proportion of main distributary channels. In the case of low sediment concentration，deltaic main bodies are transformed from branching deltas with inter-distributary bays to sand-bar deltas with distributary networks when the river discharge rises. With the increase in the sediment discharge and the decrease in the sediment grain size，deltaic main bodies turn into branching deltas with inter-distributary bays and have weakened convergence，and CMCLs are transformed from complex finger lobes with multiple channels to complex finger lobes with few channels. Deltaic main bodies tend to be oval CMCLs with main distributary channels when the basin bathymetry increase.
Dominated by different controlling factors，the response of river-dominated deltaic morphology to its growth processes is short of systematic quantitative study. On the basis of fractal geometry and variable controlling，we utilized sedimentary forward numerical modeling at an architecture scale to extract morphological types and features of river-dominated deltaic main bodies and channel-mouth bar complex lobes（CMCLs）and verify the controlling effects of sediment supply rates，sediment compositions，and basin bathymetry on morphology. Also，we established a quantitative characterization model relating the values of morphological features to dominant controlling factors of growth processes. The results indicate that the morphology of deltaic main bodies and CMCLs can be characterized by included angles between main distributary channels at initial river mouths，joint distance，the number of channel-mouth bar complexes at a river mouth or a joint，and the number and proportion of main distributary channels. In the case of low sediment concentration，deltaic main bodies are transformed from branching deltas with inter-distributary bays to sand-bar deltas with distributary networks when the river discharge rises. With the increase in the sediment discharge and the decrease in the sediment grain size，deltaic main bodies turn into branching deltas with inter-distributary bays and have weakened convergence，and CMCLs are transformed from complex finger lobes with multiple channels to complex finger lobes with few channels. Deltaic main bodies tend to be oval CMCLs with main distributary channels when the basin bathymetry increase.
2022, 29(5):15-27.
DOI: 10.13673/j.cnki.cn37-1359/te.202108024
Abstract:
The sulfur content of crude oil in the eastern section of the southern slope belt（south slope）of Dongying Sag is regularly distributed：The sulfur content of crude oil gradually decreases from the center of the subsag to the edge in the planar direction，whereas high-sulfur crude oil is mainly developed in the middle-shallow formations in the vertical direction.Typical continental high-sulfur crude oil is developed in the study area，with high density and high viscosity on the whole，high proportions of non-hydrocarbons and asphaltenes in group components，and heavier carbon isotopes in group components. The geochemical characteristics of crude oil reveal that high-sulfur crude oil originates from source rocks developed under sedimentary water bodies with high salinity and great reducibility. Differences in biomarkers of high-sulfur crude oil in different regions reflect different main genesis of the crude oil. The high-sulfur crude oil represented by that in Le’an Oilfield has small burial depth，high maturity，high water body salinity，and high degree of biodegradation，while the high·sulfur crude oil represented by that in Wangjiagang Oilfield is characterized by large burial depth，low maturity，higher water body salinity，and low degree of biodegradation. The main genesis of the former type of high-sulfur crude oil is that the relative enrichment of sulfur during biodegradation and refilling after crude oil degradation lead to reduced sulfur content.In contrast，the latter type is the result of hydrocarbon generation at an early stage from high-sulfur hydrocarbon-generating parent materials deposited in a reducing water body. Thermochemical sulfate reduction（TSR）reaction may have played a role locally. Thus，in a continental basin，the high-sulfur hydrocarbon-generating parent materials formed in a highly reducing environment are the basis for the formation of high-sulfur crude oil，and secondary actions such as biodegradation and TSR are important factors for the further increase in the sulfur content of crude oil.
The sulfur content of crude oil in the eastern section of the southern slope belt（south slope）of Dongying Sag is regularly distributed：The sulfur content of crude oil gradually decreases from the center of the subsag to the edge in the planar direction，whereas high-sulfur crude oil is mainly developed in the middle-shallow formations in the vertical direction.Typical continental high-sulfur crude oil is developed in the study area，with high density and high viscosity on the whole，high proportions of non-hydrocarbons and asphaltenes in group components，and heavier carbon isotopes in group components. The geochemical characteristics of crude oil reveal that high-sulfur crude oil originates from source rocks developed under sedimentary water bodies with high salinity and great reducibility. Differences in biomarkers of high-sulfur crude oil in different regions reflect different main genesis of the crude oil. The high-sulfur crude oil represented by that in Le’an Oilfield has small burial depth，high maturity，high water body salinity，and high degree of biodegradation，while the high·sulfur crude oil represented by that in Wangjiagang Oilfield is characterized by large burial depth，low maturity，higher water body salinity，and low degree of biodegradation. The main genesis of the former type of high-sulfur crude oil is that the relative enrichment of sulfur during biodegradation and refilling after crude oil degradation lead to reduced sulfur content.In contrast，the latter type is the result of hydrocarbon generation at an early stage from high-sulfur hydrocarbon-generating parent materials deposited in a reducing water body. Thermochemical sulfate reduction（TSR）reaction may have played a role locally. Thus，in a continental basin，the high-sulfur hydrocarbon-generating parent materials formed in a highly reducing environment are the basis for the formation of high-sulfur crude oil，and secondary actions such as biodegradation and TSR are important factors for the further increase in the sulfur content of crude oil.
ZHAO Shengxian
,
XIA Ziqiang
,
LIU Wenping
,
ZHANG Chenglin
,
ZHANG Jian
,
WEN Li
,
HE Yuanhan
,
WANG Chongshan
2022, 29(5):28-38.
DOI: 10.13673/j.cnki.cn37-1359/te.202108013
Abstract:
The deep shale gas in Luzhou in the southern Sichuan Basin is the focus of shale gas exploration at this stage.The development of natural fractures has an important impact on shale gas enrichment，fracturing development and productivity. This paper explores the fracture characteristics，phases，formation and evolution of Wufeng-Longmaxi Formation shale in Well Lu203 area with the data such as core，logging，inclusion homogenization temperature and conducting rock acoustic emission experiments. The results show that the structural genesis of Wufeng-Longmaxi Formation shale is dominated by shear fractures，with a few horizontal slip fractures and vertical tension fractures. The filling degree of the fractures is high and the fillings are complicated. The shear fractures are characterized by the vertical and horizontal fractures and short extension distances. Vertically，the fractures mainly develop in Wufeng Formation and the middle-upper parts of the layers 2 and 4 of the Submember I of the first Member of Longmaxi Formation，and the vertical and horizontal fractures develop at the bottom. Additionally，horizontal fractures mainly develop in the upward direction. Wufeng-Longmaxi Formation shale fractures were formed during tectonic movement in three phases. In the first phase，tectonic fractures were formed during the Indosinian movement（253.4-250.0 Ma），which were mainly filled by calcite and pyrite. The inclusion homogenization temperature was 130.4-150.6 ℃，and the tectonic stress was in the NNW-SSE（335°±5°）direction，forming near-NS- and NWW-direction plane shear fractures and NEE-direction section shear fractures. In the second phase，fractures were formed in the late Yanshanian-early Himalayan（70.58-42.64 Ma）. They were filled with calcite and had the inclusion homogenization temperature of 194.8-210 ℃. The tectonic stress was in the SEE-NWW direction（110°±5°），which formed NW- and NEE-direction plane shear fractures and NNE-direction section shear fractures and also strengthened and reformed early fractures. The fractures of the third phase were formed in the middle to late Himalayan（42.64-0 Ma）.Most of them were mainly semi-filled or unfilled，and the inclusion homogenization temperature was 163.3-190 ℃. The tectonic stress in the NEE（75°±5°）direction formed NNE- and WE-irection plane fractures and NW-direction section fractures. The structure became stabilized in this phase，and early fractures underwent a superimposed transformation.
The deep shale gas in Luzhou in the southern Sichuan Basin is the focus of shale gas exploration at this stage.The development of natural fractures has an important impact on shale gas enrichment，fracturing development and productivity. This paper explores the fracture characteristics，phases，formation and evolution of Wufeng-Longmaxi Formation shale in Well Lu203 area with the data such as core，logging，inclusion homogenization temperature and conducting rock acoustic emission experiments. The results show that the structural genesis of Wufeng-Longmaxi Formation shale is dominated by shear fractures，with a few horizontal slip fractures and vertical tension fractures. The filling degree of the fractures is high and the fillings are complicated. The shear fractures are characterized by the vertical and horizontal fractures and short extension distances. Vertically，the fractures mainly develop in Wufeng Formation and the middle-upper parts of the layers 2 and 4 of the Submember I of the first Member of Longmaxi Formation，and the vertical and horizontal fractures develop at the bottom. Additionally，horizontal fractures mainly develop in the upward direction. Wufeng-Longmaxi Formation shale fractures were formed during tectonic movement in three phases. In the first phase，tectonic fractures were formed during the Indosinian movement（253.4-250.0 Ma），which were mainly filled by calcite and pyrite. The inclusion homogenization temperature was 130.4-150.6 ℃，and the tectonic stress was in the NNW-SSE（335°±5°）direction，forming near-NS- and NWW-direction plane shear fractures and NEE-direction section shear fractures. In the second phase，fractures were formed in the late Yanshanian-early Himalayan（70.58-42.64 Ma）. They were filled with calcite and had the inclusion homogenization temperature of 194.8-210 ℃. The tectonic stress was in the SEE-NWW direction（110°±5°），which formed NW- and NEE-direction plane shear fractures and NNE-direction section shear fractures and also strengthened and reformed early fractures. The fractures of the third phase were formed in the middle to late Himalayan（42.64-0 Ma）.Most of them were mainly semi-filled or unfilled，and the inclusion homogenization temperature was 163.3-190 ℃. The tectonic stress in the NEE（75°±5°）direction formed NNE- and WE-irection plane fractures and NW-direction section fractures. The structure became stabilized in this phase，and early fractures underwent a superimposed transformation.
2022, 29(5):39-48.
DOI: 10.13673/j.cnki.cn37-1359/te.202110028
Abstract:
As the complexity of sandstone pore-throat structure is an important factor affecting its permeability and the permeability is crucial to evaluating high-quality reservoirs，it is vital to quantitatively characterize the complexity of sandstone pore-throat structure. Therefore，this paper takes the sandstone of Shahejie Formation in Dongying Sag as an example.On the basis of the thin section identification，XRD，and MICP test，it introduces the pore throat volume fractal dimension，tortuosity，and tortuosity fractal dimension to quantitatively describe the pore throat structure of sandstone and explore their petrological factors. In addition，it systematically analyzes the relationship of volume fractal dimension，tortuosity，and tortuosity fractal dimension with permeability. The results show that the complexity of pore throat structure and permeability of sandstone in Shahejie Formation of Dongying Sag are greatly affected by sedimentary microfacies. The average pore throat diameter is an important factor to control the complexity of pore throat structure，and the complexity of pore throat structure （the volume fractal dimension，the tortuosity，and the tortuosity fractal dimension）is a key factor affecting the permeability of sandstone.
As the complexity of sandstone pore-throat structure is an important factor affecting its permeability and the permeability is crucial to evaluating high-quality reservoirs，it is vital to quantitatively characterize the complexity of sandstone pore-throat structure. Therefore，this paper takes the sandstone of Shahejie Formation in Dongying Sag as an example.On the basis of the thin section identification，XRD，and MICP test，it introduces the pore throat volume fractal dimension，tortuosity，and tortuosity fractal dimension to quantitatively describe the pore throat structure of sandstone and explore their petrological factors. In addition，it systematically analyzes the relationship of volume fractal dimension，tortuosity，and tortuosity fractal dimension with permeability. The results show that the complexity of pore throat structure and permeability of sandstone in Shahejie Formation of Dongying Sag are greatly affected by sedimentary microfacies. The average pore throat diameter is an important factor to control the complexity of pore throat structure，and the complexity of pore throat structure （the volume fractal dimension，the tortuosity，and the tortuosity fractal dimension）is a key factor affecting the permeability of sandstone.
2022, 29(5):49-57.
DOI: 10.13673/j.cnki.cn37-1359/te.202110030
Abstract:
In recent years，deep resources in the southern margin of Junggar Basin have been a hot spot for natural gas exploration. Among them，in the middle of the southern margin，the Jurassic source rocks in Huomatu anticline zone have huge potential resources. However，due to the low degree of exploration，the relationship between the thermal evolution of source rocks and the gas accumulation conditions is still unclear. Based on the seismic interpretation and thermal history data，a basin simulation system was applied to restore the thermal evolution histories of Middle and Lower Jurassic source rocks in the southern margin of Junggar Basin.Furthermore，combined with the geochemical characteristics of Jurassic source rocks，the generation and accumulation of gas and the coupling relationships with structural evolution were systematically studied. The research showed that the Middle and Lower Jurassic source rocks developed in the middle of the southern margin. Moreover，the gas mainly generated in the early stage of the Early Cretaceous Epoch（99.6 Ma）and the late stage of the Late Cretaceous Epoch（65.5 Ma），respectively. Now，the Middle and Lower Jurassic source rocks are in the stage of high and over maturity and still have hydrocarbon generation potential. At the same time，two hydrocarbon accumulation models have been formed in the area，and they are secondary accumulation with late uplift and high-mature accumulation with continuous buried depth. In addition，the gas distribution has been controlled by the evolution of the source rocks and the structure.
In recent years，deep resources in the southern margin of Junggar Basin have been a hot spot for natural gas exploration. Among them，in the middle of the southern margin，the Jurassic source rocks in Huomatu anticline zone have huge potential resources. However，due to the low degree of exploration，the relationship between the thermal evolution of source rocks and the gas accumulation conditions is still unclear. Based on the seismic interpretation and thermal history data，a basin simulation system was applied to restore the thermal evolution histories of Middle and Lower Jurassic source rocks in the southern margin of Junggar Basin.Furthermore，combined with the geochemical characteristics of Jurassic source rocks，the generation and accumulation of gas and the coupling relationships with structural evolution were systematically studied. The research showed that the Middle and Lower Jurassic source rocks developed in the middle of the southern margin. Moreover，the gas mainly generated in the early stage of the Early Cretaceous Epoch（99.6 Ma）and the late stage of the Late Cretaceous Epoch（65.5 Ma），respectively. Now，the Middle and Lower Jurassic source rocks are in the stage of high and over maturity and still have hydrocarbon generation potential. At the same time，two hydrocarbon accumulation models have been formed in the area，and they are secondary accumulation with late uplift and high-mature accumulation with continuous buried depth. In addition，the gas distribution has been controlled by the evolution of the source rocks and the structure.
2022, 29(5):58-66.
DOI: 10.13673/j.cnki.cn37-1359/te.202108060
Abstract:
In order to solve the difficult problem of tight sandstone reservoir prediction due to the small difference of wave impedance, this paper presents a prediction method for channel characterization and“sweet spot”based on the spectral decomposition and fusion technology. In this method，the nonlinear mapping relationship between the target sand body and the seismic spectrum was established to form a mixed data volume with direct frequency information，and a facies control model of macroscopic geological significance was constructed. In this way，the high-resolution inversion was performed to determine the distribution of“sweet spots”in tight sandstone reservoirs. By taking the tight sandstone in the Jurassic Qianyi Member of Tongnanba anticline as the research object，the early channel distribution of Qianyi Member was accurately described by spectral decomposition and fusion technology. The high-resolution inversion results based on mixed data volumes reveal that the porosity of channel sand bodies in Qianyi Member is less than 6%，and the porosity at the anticline is high（4%-6%）. The horizontal distribution of sand bodies in the channel is stable，where the thickness of the brittle sand bodies（with gamma-ray（GR）less than 65 API）changes rapidly and is generally more than 20 m at the anticline. The reservoir prediction results indicate that the channel sand bodies in Qianyi Member of the anticline belt feature large thickness，good brittleness，high porosity，and shallow burial depth，which are not only the“sweet spots”development areas in Qianyi Member but also favorable target areas for tight reservoir stimulation in the future.
In order to solve the difficult problem of tight sandstone reservoir prediction due to the small difference of wave impedance, this paper presents a prediction method for channel characterization and“sweet spot”based on the spectral decomposition and fusion technology. In this method，the nonlinear mapping relationship between the target sand body and the seismic spectrum was established to form a mixed data volume with direct frequency information，and a facies control model of macroscopic geological significance was constructed. In this way，the high-resolution inversion was performed to determine the distribution of“sweet spots”in tight sandstone reservoirs. By taking the tight sandstone in the Jurassic Qianyi Member of Tongnanba anticline as the research object，the early channel distribution of Qianyi Member was accurately described by spectral decomposition and fusion technology. The high-resolution inversion results based on mixed data volumes reveal that the porosity of channel sand bodies in Qianyi Member is less than 6%，and the porosity at the anticline is high（4%-6%）. The horizontal distribution of sand bodies in the channel is stable，where the thickness of the brittle sand bodies（with gamma-ray（GR）less than 65 API）changes rapidly and is generally more than 20 m at the anticline. The reservoir prediction results indicate that the channel sand bodies in Qianyi Member of the anticline belt feature large thickness，good brittleness，high porosity，and shallow burial depth，which are not only the“sweet spots”development areas in Qianyi Member but also favorable target areas for tight reservoir stimulation in the future.
2022, 29(5):67-75.
DOI: 10.13673/j.cnki.cn37-1359/te.202108019
Abstract:
The migration flux is a crucial parameter controlling the migration of hydrocarbon and other fluids in geological media，whereas there is no still unified rate model for describing non-linear flow of hydrocarbon and other fluids in sandbody transport layer with characteristics of typical porous media. Combining with the non-linear dynamics characteristics of hydrocarbon migration，we construct a new migration rate model for calculating the hydrocarbon migration rate in sandbody transport layers based on the main existing rate models of fluids in porous media. Moreover，taking transport layers of Shawan Formation etc. at Chepaizi area in Junggar Basin as an example，this paper illustrates the calculation steps，parameter characterization and resource evaluation application of the new model. The studies show that the hydrocarbon migration rate in sandbody transport layer has very strong non-linear dynamic characteristics. The migration rate，which is the key link between the dynamic mechanism and the migration and accumulation volume in sandbody transport layer，decreases as a power function with increase of the ratio of the resistance gradient to the dynamic gradient. The new model suggests the hydrocarbon migration and accumulation volumes in sandbody transport layers are controlled by the migration rate，the equivalent transport channel，and the charging time. The study provides a new analytical method for hydrocarbon migration analysis and resource potential evaluation in sandbody transport layers.
The migration flux is a crucial parameter controlling the migration of hydrocarbon and other fluids in geological media，whereas there is no still unified rate model for describing non-linear flow of hydrocarbon and other fluids in sandbody transport layer with characteristics of typical porous media. Combining with the non-linear dynamics characteristics of hydrocarbon migration，we construct a new migration rate model for calculating the hydrocarbon migration rate in sandbody transport layers based on the main existing rate models of fluids in porous media. Moreover，taking transport layers of Shawan Formation etc. at Chepaizi area in Junggar Basin as an example，this paper illustrates the calculation steps，parameter characterization and resource evaluation application of the new model. The studies show that the hydrocarbon migration rate in sandbody transport layer has very strong non-linear dynamic characteristics. The migration rate，which is the key link between the dynamic mechanism and the migration and accumulation volume in sandbody transport layer，decreases as a power function with increase of the ratio of the resistance gradient to the dynamic gradient. The new model suggests the hydrocarbon migration and accumulation volumes in sandbody transport layers are controlled by the migration rate，the equivalent transport channel，and the charging time. The study provides a new analytical method for hydrocarbon migration analysis and resource potential evaluation in sandbody transport layers.
2022, 29(5):75-82.
DOI: 10.13673/j.cnki.cn37-1359/te.202106032
Abstract:
The main uncompartmentalized oilfields in Shengli Petroleum Province have entered the late waterflooding stage after long-term development. Their comprehensive water cut has reached more than 98%，but the recovery rate is only 41%，and thus the oilfields still have large residual oil reserves and enhanced oil recovery（EOR）potential. Through the core analysis of cored wells in uncompartmentalized oilfields，it was found that in the ultra-high water cut stage，there were extreme waterflooding intervals with the saturation of remaining oil less than that of residual oil as well as weak waterflooding intervals with the oil saturation greater than the oil saturation of waterflood front in all uncompartmentalized oilfields.Therefore，this paper proposed the definition and classification criteria of the extreme waterflooding zone，strong waterflooding zone，and weak waterflooding zone of an ultra-high water cut reservoirs. The influence of water injection，displacement rate，and permeability on the formation of the extreme waterflooding zone was studied. The research results reveal that with the increase in injected water volume，in the priority breakthrough area of the injected water，oil saturation gradually decreases with the gradual rise in water phase permeability，water fractional flow，and displacement rate. As a result，the remaining oil saturation in this area is lower than the residual oil remaining oil saturation，and thus the extreme waterflooding zone is formed. The volume calculation method for different graded waterflooding zones was established，and the dynamic production data of Gudong，Gudao，and Chengdong oilfields were used to verify the calculation. It is proved that the established method is scientific and accurate and has the advantage of easy access to required data and simple calculations.
The main uncompartmentalized oilfields in Shengli Petroleum Province have entered the late waterflooding stage after long-term development. Their comprehensive water cut has reached more than 98%，but the recovery rate is only 41%，and thus the oilfields still have large residual oil reserves and enhanced oil recovery（EOR）potential. Through the core analysis of cored wells in uncompartmentalized oilfields，it was found that in the ultra-high water cut stage，there were extreme waterflooding intervals with the saturation of remaining oil less than that of residual oil as well as weak waterflooding intervals with the oil saturation greater than the oil saturation of waterflood front in all uncompartmentalized oilfields.Therefore，this paper proposed the definition and classification criteria of the extreme waterflooding zone，strong waterflooding zone，and weak waterflooding zone of an ultra-high water cut reservoirs. The influence of water injection，displacement rate，and permeability on the formation of the extreme waterflooding zone was studied. The research results reveal that with the increase in injected water volume，in the priority breakthrough area of the injected water，oil saturation gradually decreases with the gradual rise in water phase permeability，water fractional flow，and displacement rate. As a result，the remaining oil saturation in this area is lower than the residual oil remaining oil saturation，and thus the extreme waterflooding zone is formed. The volume calculation method for different graded waterflooding zones was established，and the dynamic production data of Gudong，Gudao，and Chengdong oilfields were used to verify the calculation. It is proved that the established method is scientific and accurate and has the advantage of easy access to required data and simple calculations.
2022, 29(5):83-90.
DOI: 10.13673/j.cnki.cn37-1359/te.202203045
Abstract:
The underground distribution of remaining oil in the ultra-high water cut stage is growing complex，and it is more and more difficult to tap the potential. Clarifying the development potential of the remaining oil is the basis for enhancing the oil recovery of reservoirs in the ultra-high water cut stage. Considering the spatial distribution，enrichment，water consumption characteristics，and economic mobility of the remaining oil in the ultra-high water cut stage，the recoverability coefficient and recoverable potential factor of the remaining oil were proposed from the aspects of recoverable resources of remaining oil and regional development potential to construct a comprehensive index set for the classification and evaluation of remaining oil in the ultra-high water cut stage. On this basis，the fuzzy C-means clustering（FCM）algorithm was improved by the Xie-Beni function to conduct an unsupervised clustering evaluation of the remaining oil in the ultra-high water cut stage. As a result，a new classification and evaluation method of the remaining oil in the ultra-high water cut stage was formed. With the north of the west area of Gudao Oilfield as an example，the research on classification，evaluation，and potential adjustment of remaining oil in the ultra-high water cut stage was carried out. The results show that this method can accurately determine the dominant position of the remaining oil potential. According to the evaluation results of various remaining oil potential of north Ng3-4 unit，corresponding potential tapping measures were proposed respectively，which guide the well pattern exchange and flow line adjustment between unit strata. After the adjustment，the recovery of this unit increases 2.1%，and the recoverable reserves increases 29×104 t.
The underground distribution of remaining oil in the ultra-high water cut stage is growing complex，and it is more and more difficult to tap the potential. Clarifying the development potential of the remaining oil is the basis for enhancing the oil recovery of reservoirs in the ultra-high water cut stage. Considering the spatial distribution，enrichment，water consumption characteristics，and economic mobility of the remaining oil in the ultra-high water cut stage，the recoverability coefficient and recoverable potential factor of the remaining oil were proposed from the aspects of recoverable resources of remaining oil and regional development potential to construct a comprehensive index set for the classification and evaluation of remaining oil in the ultra-high water cut stage. On this basis，the fuzzy C-means clustering（FCM）algorithm was improved by the Xie-Beni function to conduct an unsupervised clustering evaluation of the remaining oil in the ultra-high water cut stage. As a result，a new classification and evaluation method of the remaining oil in the ultra-high water cut stage was formed. With the north of the west area of Gudao Oilfield as an example，the research on classification，evaluation，and potential adjustment of remaining oil in the ultra-high water cut stage was carried out. The results show that this method can accurately determine the dominant position of the remaining oil potential. According to the evaluation results of various remaining oil potential of north Ng3-4 unit，corresponding potential tapping measures were proposed respectively，which guide the well pattern exchange and flow line adjustment between unit strata. After the adjustment，the recovery of this unit increases 2.1%，and the recoverable reserves increases 29×104 t.
2022, 29(5):91-101.
DOI: 10.13673/j.cnki.cn37-1359/te.202108044
Abstract:
Xi233 area Chang7 reservoir in Ordos Basin is one of the typical shale oil reservoirs in China. In the early stage of production relying on quasi-natural energy，oil production declines fast and oil recovery is low. Given abundant associated gas resources，we selected typical shale oil reservoir rock samples to conduct the gas-flooding experiment and huff-puff experiment in the shale oil samples with the associated gas by the nuclear magnetic resonance technology. The results show that the oil is mainly produced from the medium and large pores，while the recovery percent of micropores is lower，and oil recovery is less than 43% in the associated gas-flooding process. Compared with the saturated oil samples，the samples with irreducible water show the lower oil recovery，which is affected by factors such as pore heterogeneity，specific surface area，and irreducible water. In the huff-puff process with associated gas injection，oil is also mainly produced from the medium and large pores. Compared with the flooding experiment with associated gas injection，the recovery percent in each level of pores is greater in the huff-puff oil recovery process，and the oil recovery of samples is greater than 44%. With the increase in the huff-puff cycle，the cycle oil recovery gradually decreases，and oil production tends to be steady. As the huff-puff pressure rises，both the oil production and the oil recovery increase. The study confirms that the huff-puff pressure higher than the formation pressure can improve the oil recovery in Xi233 area Chang7 shale oil reservoir. The development method of advanced gas injection huff-puff is recommended in the study area.
Xi233 area Chang7 reservoir in Ordos Basin is one of the typical shale oil reservoirs in China. In the early stage of production relying on quasi-natural energy，oil production declines fast and oil recovery is low. Given abundant associated gas resources，we selected typical shale oil reservoir rock samples to conduct the gas-flooding experiment and huff-puff experiment in the shale oil samples with the associated gas by the nuclear magnetic resonance technology. The results show that the oil is mainly produced from the medium and large pores，while the recovery percent of micropores is lower，and oil recovery is less than 43% in the associated gas-flooding process. Compared with the saturated oil samples，the samples with irreducible water show the lower oil recovery，which is affected by factors such as pore heterogeneity，specific surface area，and irreducible water. In the huff-puff process with associated gas injection，oil is also mainly produced from the medium and large pores. Compared with the flooding experiment with associated gas injection，the recovery percent in each level of pores is greater in the huff-puff oil recovery process，and the oil recovery of samples is greater than 44%. With the increase in the huff-puff cycle，the cycle oil recovery gradually decreases，and oil production tends to be steady. As the huff-puff pressure rises，both the oil production and the oil recovery increase. The study confirms that the huff-puff pressure higher than the formation pressure can improve the oil recovery in Xi233 area Chang7 shale oil reservoir. The development method of advanced gas injection huff-puff is recommended in the study area.
2022, 29(5):102-110.
DOI: 10.13673/j.cnki.cn37-1359/te.202105013
Abstract:
History matching of polymer flooding is exposed to problems such as the multiple parameters，heavy workload，and huge time consumption. Considering this，on the basis of the basic numerical simulation principle of polymer flooding and the research on the influencing factors in multi-parameter history matching，the widely used ENKF method was selected to explore the automatic history matching of polymer flooding. The nonlinear characteristics of the history matching parameters for polymer flooding were improved，and the automatic history matching software was developed by the ESMDA algorithm. Moreover，the history matching of polymer flooding was performed for an actual block. The results revealed that the multi-parameter mathematical model of polymer flooding can satisfactorily reflect the basic laws of polymer flooding in oil reservoirs. Upon the comprehensive adjustment to the parameters such as the polymer adsorption capacity，viscosity-concentration relationship，residual resistance coefficient，and inaccessible pore volume，the simulations are consistent with the actual performance of the reservoirs. In this way，the purpose of history matching is achieved. The constructed mathematical model for automatic history matching meets the algorithm requirements，and the developed automatic history matching software can reduce the systematic error of model calculations. The actual test results indicate that the water cut trend of the whole region basically conforms to the historical performance，and the cumulative oil production error of the whole region is 3.8%；the single well matching result is good，with a single well matching coincidence rate of 81.2%，which meet the requirement of history matching of polymer flooding.
History matching of polymer flooding is exposed to problems such as the multiple parameters，heavy workload，and huge time consumption. Considering this，on the basis of the basic numerical simulation principle of polymer flooding and the research on the influencing factors in multi-parameter history matching，the widely used ENKF method was selected to explore the automatic history matching of polymer flooding. The nonlinear characteristics of the history matching parameters for polymer flooding were improved，and the automatic history matching software was developed by the ESMDA algorithm. Moreover，the history matching of polymer flooding was performed for an actual block. The results revealed that the multi-parameter mathematical model of polymer flooding can satisfactorily reflect the basic laws of polymer flooding in oil reservoirs. Upon the comprehensive adjustment to the parameters such as the polymer adsorption capacity，viscosity-concentration relationship，residual resistance coefficient，and inaccessible pore volume，the simulations are consistent with the actual performance of the reservoirs. In this way，the purpose of history matching is achieved. The constructed mathematical model for automatic history matching meets the algorithm requirements，and the developed automatic history matching software can reduce the systematic error of model calculations. The actual test results indicate that the water cut trend of the whole region basically conforms to the historical performance，and the cumulative oil production error of the whole region is 3.8%；the single well matching result is good，with a single well matching coincidence rate of 81.2%，which meet the requirement of history matching of polymer flooding.
2022, 29(5):111-117.
DOI: 10.13673/j.cnki.cn37-1359/te.202106013
Abstract:
The application scale of heterogeneous combination flooding has been expanding significantly since the pilot test carried out at Ng3 of Zhongyi area，Gudao Oilfield，Shengli Petroleum Province in 2010. It has become one of the leading chemical flooding technologies for further enhancing oil recovery in old oilfields. Although the application of heterogeneous combination flooding technology has achieved successful results at Ng3 of Zhongyi area，the remaining oil distribution and reservoir response law after heterogeneous combination flooding are still the key problems to be addressed in the promotion and implementation of the technology. This paper systematically analyzes the distribution characteristics of remaining oil after heterogeneous combination flooding based on sealed cored well and summarizes the reservoir response law by comparing the remaining oil distribution before and after heterogeneous combination flooding. The results show that the average remaining oil saturation at Ng3 of Zhongyi area is 28.3% after heterogeneous combination flooding. The samples with high remaining oil saturation mostly appear at the top of the positive rhythm reservoir and near the interlayer. The microscopic occurrence mode of remaining oil is mainly disseminated. Compared with that before heterogeneous combination flooding，the average remaining oil saturation is reduced by 7%，and the average displacement efficiency is increased by 13.1%. Moreover，the displacement is more balanced in the vertical direction，and the difference in remaining oil saturation between the top and bottom of the positive rhythm reservoir is reduced after heterogeneous combination flooding.
The application scale of heterogeneous combination flooding has been expanding significantly since the pilot test carried out at Ng3 of Zhongyi area，Gudao Oilfield，Shengli Petroleum Province in 2010. It has become one of the leading chemical flooding technologies for further enhancing oil recovery in old oilfields. Although the application of heterogeneous combination flooding technology has achieved successful results at Ng3 of Zhongyi area，the remaining oil distribution and reservoir response law after heterogeneous combination flooding are still the key problems to be addressed in the promotion and implementation of the technology. This paper systematically analyzes the distribution characteristics of remaining oil after heterogeneous combination flooding based on sealed cored well and summarizes the reservoir response law by comparing the remaining oil distribution before and after heterogeneous combination flooding. The results show that the average remaining oil saturation at Ng3 of Zhongyi area is 28.3% after heterogeneous combination flooding. The samples with high remaining oil saturation mostly appear at the top of the positive rhythm reservoir and near the interlayer. The microscopic occurrence mode of remaining oil is mainly disseminated. Compared with that before heterogeneous combination flooding，the average remaining oil saturation is reduced by 7%，and the average displacement efficiency is increased by 13.1%. Moreover，the displacement is more balanced in the vertical direction，and the difference in remaining oil saturation between the top and bottom of the positive rhythm reservoir is reduced after heterogeneous combination flooding.
2022, 29(5):118-125.
DOI: 10.13673/j.cnki.cn37-1359/te.202106029
Abstract:
The thick oil layers of Lamadian Oilfield in Daqing are mainly characterized by multiple intervals and multiple rhythms. Deeply understanding the channeling law is crucial for further tapping the potential of the remaining oil. Therefore，intralayer heterogeneous cores were used to study the internal channeling law of intra-layer heterogeneous reservoirs experimentally. The results show that in the stage of water flooding with an injection volume of 0-0.4 PV，the diversion rate at the injection end is slightly lower than that at the production end in the high-permeability layer，which is opposite to those observed in the medium-and low-permeability layers；in the stage from water flooding with an injection volume of 0.4 PV to the end of water flooding，the diversion rate at the production end of the high-permeability layer greatly increases，while the diversion rate in the medium-permeability layer significantly reduces and that in the low-permeability layer slightly decreases. With the increase in the core permeability ratio，the channeling degree between the sublayers at the production end and the injection end decreases，and the same goes with the interlayer interference. As water flooding continues，the channeling degree of interlayer first decreases and then increases. As the injection rate goes up，the diversion rate difference between the production end and the injection end of the high-permeability layer increases，hence the channeling degree rising. Increasing the injection rates of water wells can achieve the purpose of raising the injection pressure. Nevertheless，because the increase in fluid absorption in the high-permeability layer is much greater than those in the mediumand low-permeability layers，besides the influence of channeling inside the reservoir，the effect of expanding the swept volume is not distinct. Moreover，increasing the injection rates of water wells also puts forward higher requirements on the capabilities of equipment at the injection end and the production end and that on the surface. Therefore，increasing the flow resistance of the high-permeability layer is the effective technical way of increasing the injection pressure.
The thick oil layers of Lamadian Oilfield in Daqing are mainly characterized by multiple intervals and multiple rhythms. Deeply understanding the channeling law is crucial for further tapping the potential of the remaining oil. Therefore，intralayer heterogeneous cores were used to study the internal channeling law of intra-layer heterogeneous reservoirs experimentally. The results show that in the stage of water flooding with an injection volume of 0-0.4 PV，the diversion rate at the injection end is slightly lower than that at the production end in the high-permeability layer，which is opposite to those observed in the medium-and low-permeability layers；in the stage from water flooding with an injection volume of 0.4 PV to the end of water flooding，the diversion rate at the production end of the high-permeability layer greatly increases，while the diversion rate in the medium-permeability layer significantly reduces and that in the low-permeability layer slightly decreases. With the increase in the core permeability ratio，the channeling degree between the sublayers at the production end and the injection end decreases，and the same goes with the interlayer interference. As water flooding continues，the channeling degree of interlayer first decreases and then increases. As the injection rate goes up，the diversion rate difference between the production end and the injection end of the high-permeability layer increases，hence the channeling degree rising. Increasing the injection rates of water wells can achieve the purpose of raising the injection pressure. Nevertheless，because the increase in fluid absorption in the high-permeability layer is much greater than those in the mediumand low-permeability layers，besides the influence of channeling inside the reservoir，the effect of expanding the swept volume is not distinct. Moreover，increasing the injection rates of water wells also puts forward higher requirements on the capabilities of equipment at the injection end and the production end and that on the surface. Therefore，increasing the flow resistance of the high-permeability layer is the effective technical way of increasing the injection pressure.
2022, 29(5):126-132.
DOI: 10.13673/j.cnki.cn37-1359/te.202107006
Abstract:
The conventional drainage gas recovery and water-controlled gas recovery techniques are difficult to solve the problems of low porosity，low permeability，and small pore throats in tight gas reservoirs. For this reason，the phase inversion technology is utilized to prepare nano-drainage agents suitable for tight gas reservoirs to change the rock surface characteristics and improve the drainage effects of tight gas reservoirs. On the basis of self-prepared nano-drainage agents and tight cores，this paper explored the action mechanism of nano-drainage agents to core slices and their powder by modern testing technology and evaluated the effects on core wettability and microscopic morphology. The drainage gas recovery action mechanism of nano-drainage agents was then discussed. The results show that instead of reacting chemically with the core surface，the nano-drainage agent is only adsorbed on the core surface by electrostatic and hydrogen bonding effects to form a hydrophobic film，which can reduce the core surface roughness and the flow resistance in the pores to achieve drainage gas recovery. At the same time，the nano-drainage agent can reverse the core wettability in the reservoir，namely that the capillary pressure becomes a resistance to prevent the discharged formation water from flowing into the reservoir again，extending the validity period of drainage gas recovery.
The conventional drainage gas recovery and water-controlled gas recovery techniques are difficult to solve the problems of low porosity，low permeability，and small pore throats in tight gas reservoirs. For this reason，the phase inversion technology is utilized to prepare nano-drainage agents suitable for tight gas reservoirs to change the rock surface characteristics and improve the drainage effects of tight gas reservoirs. On the basis of self-prepared nano-drainage agents and tight cores，this paper explored the action mechanism of nano-drainage agents to core slices and their powder by modern testing technology and evaluated the effects on core wettability and microscopic morphology. The drainage gas recovery action mechanism of nano-drainage agents was then discussed. The results show that instead of reacting chemically with the core surface，the nano-drainage agent is only adsorbed on the core surface by electrostatic and hydrogen bonding effects to form a hydrophobic film，which can reduce the core surface roughness and the flow resistance in the pores to achieve drainage gas recovery. At the same time，the nano-drainage agent can reverse the core wettability in the reservoir，namely that the capillary pressure becomes a resistance to prevent the discharged formation water from flowing into the reservoir again，extending the validity period of drainage gas recovery.
2022, 29(5):133-140.
DOI: 10.13673/j.cnki.cn37-1359/te.202106042
Abstract:
Taking Chang8 reservoir in A83 area of Ordos Basin as the research object，a core displacement experiment based on the online scanning of nuclear magnetic resonance（NMR）was performed to explore the method of enhanced oil recovery（EOR）in tight sandstone reservoirs and solve the problem of low production of matrix during water flooding. Specifically，the process of dynamic imbibition between fractures and matrix in water flooding was simulated；the recovery of three types of pores was quantitatively evaluated regarding pore scale，and four factors affecting imbibition efficiency were analyzed. The results show that the process of dynamic imbibition of water flooding can be divided into three stages，i.e.，the stage of a rapid rise of recovery of the macropores under the displacement effect，the stage of a slow rise of recovery of the micropores under the imbibition effect，and the stage of basically reaching dynamic imbibition balance. In the process of imbibition，the recovery of micropores registers the largest，which is the main contributor to total recovery，and the recovery of the mesopores，flow channels connecting the micropores and the macropores，registers the smallest. To sum up，the whole process of dynamic imbibition is like an organism. For the maximization of the total recovery rate，it is necessary to control the injection rate（0.1 mL/min），surfactant concentration（0.05%），and soaking time（accounting for 75% of the total）. In addition，we should make the best use of the two oil recovery methods of the imbibition and displacement to ensure that the recovery of the micropores and macropores is increased as much as possible.
Taking Chang8 reservoir in A83 area of Ordos Basin as the research object，a core displacement experiment based on the online scanning of nuclear magnetic resonance（NMR）was performed to explore the method of enhanced oil recovery（EOR）in tight sandstone reservoirs and solve the problem of low production of matrix during water flooding. Specifically，the process of dynamic imbibition between fractures and matrix in water flooding was simulated；the recovery of three types of pores was quantitatively evaluated regarding pore scale，and four factors affecting imbibition efficiency were analyzed. The results show that the process of dynamic imbibition of water flooding can be divided into three stages，i.e.，the stage of a rapid rise of recovery of the macropores under the displacement effect，the stage of a slow rise of recovery of the micropores under the imbibition effect，and the stage of basically reaching dynamic imbibition balance. In the process of imbibition，the recovery of micropores registers the largest，which is the main contributor to total recovery，and the recovery of the mesopores，flow channels connecting the micropores and the macropores，registers the smallest. To sum up，the whole process of dynamic imbibition is like an organism. For the maximization of the total recovery rate，it is necessary to control the injection rate（0.1 mL/min），surfactant concentration（0.05%），and soaking time（accounting for 75% of the total）. In addition，we should make the best use of the two oil recovery methods of the imbibition and displacement to ensure that the recovery of the micropores and macropores is increased as much as possible.
2022, 29(5):141-146.
DOI: 10.13673/j.cnki.cn37-1359/te.202108049
Abstract:
To clarify the effect of previous well pattern infillings of Daqing Oilfield，this paper analyzed changes in the water-breakthrough thickness ratio，water-washing thickness ratio，and oil displacement efficiency of various oil layers on the basis of cored well data obtained 5-10 years after the adjustments. The result shows that the basic well pattern enabled the effective producing of oil layers with an effective thickness above 2.0 m，and the water-breakthrough thickness ratio reached 75.8%. The primary well pattern infilling significantly improved the water-breakthrough thickness ratio of oil layers with effective thicknesses of 2.0 m or less，and the water-breakthrough thickness ratio with effective thicknesses of 0.5-2.0 m increased by 195.0%~264.4%，thus the untabulated oil layers effectively produced well too. The secondary infilling further improved the water-breakthrough thickness ratio of oil layers with effective thicknesses between 0-1.0 m by nearly 50.0%. The tertiary infilling did not improve the water-breakthrough thickness ratio of the oil layers considerably，the water-breakthrough thickness ratio of the thin and poor oil layers increased no more than 2.3%，which represented the gradually worsening effect of well pattern infilling. The high interlayer heterogeneity, the large producing zone, and the decreasing interlayer water cut difference are key factors for the low water-breakthrough thickness ratio of the thin and poor oil layers and the worsening effect of previous infillings. According to the analysis above，a well pattern infilling mode that equally emphasizes the reduction of producing section length and well spacing was proposed.
To clarify the effect of previous well pattern infillings of Daqing Oilfield，this paper analyzed changes in the water-breakthrough thickness ratio，water-washing thickness ratio，and oil displacement efficiency of various oil layers on the basis of cored well data obtained 5-10 years after the adjustments. The result shows that the basic well pattern enabled the effective producing of oil layers with an effective thickness above 2.0 m，and the water-breakthrough thickness ratio reached 75.8%. The primary well pattern infilling significantly improved the water-breakthrough thickness ratio of oil layers with effective thicknesses of 2.0 m or less，and the water-breakthrough thickness ratio with effective thicknesses of 0.5-2.0 m increased by 195.0%~264.4%，thus the untabulated oil layers effectively produced well too. The secondary infilling further improved the water-breakthrough thickness ratio of oil layers with effective thicknesses between 0-1.0 m by nearly 50.0%. The tertiary infilling did not improve the water-breakthrough thickness ratio of the oil layers considerably，the water-breakthrough thickness ratio of the thin and poor oil layers increased no more than 2.3%，which represented the gradually worsening effect of well pattern infilling. The high interlayer heterogeneity, the large producing zone, and the decreasing interlayer water cut difference are key factors for the low water-breakthrough thickness ratio of the thin and poor oil layers and the worsening effect of previous infillings. According to the analysis above，a well pattern infilling mode that equally emphasizes the reduction of producing section length and well spacing was proposed.
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