Volume 27,Issue 5,2020 Table of Contents
2020, 27(5):1-12.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.001
Abstract:
Huanghekou Sag is located in the northeast of Jiyang Depression in Bohai Bay Basin. Due to the lack of unified 3D seismic data and poor quality of regional mid-deep seismic imaging in 3D seismic data，it is difficult to carry out the whole area correlation and results in many problems，such as unclear recognition of mid-deep sag structure，inconsistent understanding of the division of the Paleogene strata in the whole area，serious difference of the strata thickness and their distribution regularity of Kongdian Formation-the fourth member of Shahejie Formation（Ek-Es4）with the surrounding area.In the process of continuous exploration in mid-shallow strata，problems such as the mismatch between the hydrocarbon resources and the reported reserves and the lack of new exploration strata have severely restricted the exploration process. To this end，the new three-dimensional contiguous seismic data are used and the lithology，paleontology，zircon，isotopic dating and other data of new drilled wells in the study area，etc. are integrated to study the regional stratigraphic correlation and evolution of Paleogene. The attribution of unconformities at all levels are defined，the interface between Es3 and Ek-Es4 is adjusted，and the Cenozoic bottom surface is recognized. After the adjustment，the bottom surface of the Es3 has been move downward by 900 m，the bottom surface of the Cenozoic has been move downward by 2 300 m，and new exploration strata of Ek-Es4 has been found. According to the new understanding of the stratigraphic structure，Huanghekou Sag is defined with a dustpan style and the distribution characteristics of Ek-Es4 has been clarified. The scale of hydrocarbon resources in the study area is recalculated with an increase of 740 million tons，and the contradiction between resource and reserves reported has been solved. The mid-deep strata with a number of favorable traps in Kongdian Formation has great exploration potential.
Huanghekou Sag is located in the northeast of Jiyang Depression in Bohai Bay Basin. Due to the lack of unified 3D seismic data and poor quality of regional mid-deep seismic imaging in 3D seismic data，it is difficult to carry out the whole area correlation and results in many problems，such as unclear recognition of mid-deep sag structure，inconsistent understanding of the division of the Paleogene strata in the whole area，serious difference of the strata thickness and their distribution regularity of Kongdian Formation-the fourth member of Shahejie Formation（Ek-Es4）with the surrounding area.In the process of continuous exploration in mid-shallow strata，problems such as the mismatch between the hydrocarbon resources and the reported reserves and the lack of new exploration strata have severely restricted the exploration process. To this end，the new three-dimensional contiguous seismic data are used and the lithology，paleontology，zircon，isotopic dating and other data of new drilled wells in the study area，etc. are integrated to study the regional stratigraphic correlation and evolution of Paleogene. The attribution of unconformities at all levels are defined，the interface between Es3 and Ek-Es4 is adjusted，and the Cenozoic bottom surface is recognized. After the adjustment，the bottom surface of the Es3 has been move downward by 900 m，the bottom surface of the Cenozoic has been move downward by 2 300 m，and new exploration strata of Ek-Es4 has been found. According to the new understanding of the stratigraphic structure，Huanghekou Sag is defined with a dustpan style and the distribution characteristics of Ek-Es4 has been clarified. The scale of hydrocarbon resources in the study area is recalculated with an increase of 740 million tons，and the contradiction between resource and reserves reported has been solved. The mid-deep strata with a number of favorable traps in Kongdian Formation has great exploration potential.
2020, 27(5):13-24.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.002
Abstract:
Natural gas flow was obtained during the production test in the Upper Triassic in Luoyi Sag. In order to clarify the development characteristics of the large boundary fault，hydrocarbon generation，reservoir formation and hydrocarbon accumulation，based on the analysis of a large number of drilling，boreholes，key outcrops and new and old 2D seismic data，the development characteristics，evolutionary stages and the controlling effect on hydrocarbon accumulation of the southwest boundary fault in Luoyi Sag are studied in detail according to the seismic and geological data，fault patterns and basin dynamics. The results indicate that ① Fault YY is a complex regional deep fault，which can be divided into four sections：imbricated strong overthrusting section，negative inversion section after trust and extrusion，multi-angle imbricated strong overthrust superimposed strike-slip structural section，and asymmetric ox-imbricated strong overthrust section. ②Luoyi Sag has experienced five stages of structural evolution：weak extensional rifting in the middle and late Hercynian period，weak compression and uplift deformation in the early Indosinian period，unbalanced depression in the late Indosinian period，strong overthrust uplift and denudation in the Yanshanian period，and sinistral strike slip rifting in the Himalayan period. ③The tectonic activities of Fault YY not only controls the development characteristics of hydrocarbon source rock in Permian，Triassic and lower-middle Jurassic，and multiple secondary hydrocarbon stages in late Indosinian and Yanshan-Himalayan period，but also controls the development series of strata and zones of favorable reservoirs such as underwater distributary channel sandstone along the tectonic transformation belt，as well as the fracture transformation of tight sandstone reservoirs. Meantime，the fractures also has a destructive effect on the hydrocarbon accumulation of Permian and Mesozoic periods in the study area. ④The three zones in the north of Yima sub-sag are more favorable for hydrocarbon accumulation in Permian and Mesozoic periods.
Natural gas flow was obtained during the production test in the Upper Triassic in Luoyi Sag. In order to clarify the development characteristics of the large boundary fault，hydrocarbon generation，reservoir formation and hydrocarbon accumulation，based on the analysis of a large number of drilling，boreholes，key outcrops and new and old 2D seismic data，the development characteristics，evolutionary stages and the controlling effect on hydrocarbon accumulation of the southwest boundary fault in Luoyi Sag are studied in detail according to the seismic and geological data，fault patterns and basin dynamics. The results indicate that ① Fault YY is a complex regional deep fault，which can be divided into four sections：imbricated strong overthrusting section，negative inversion section after trust and extrusion，multi-angle imbricated strong overthrust superimposed strike-slip structural section，and asymmetric ox-imbricated strong overthrust section. ②Luoyi Sag has experienced five stages of structural evolution：weak extensional rifting in the middle and late Hercynian period，weak compression and uplift deformation in the early Indosinian period，unbalanced depression in the late Indosinian period，strong overthrust uplift and denudation in the Yanshanian period，and sinistral strike slip rifting in the Himalayan period. ③The tectonic activities of Fault YY not only controls the development characteristics of hydrocarbon source rock in Permian，Triassic and lower-middle Jurassic，and multiple secondary hydrocarbon stages in late Indosinian and Yanshan-Himalayan period，but also controls the development series of strata and zones of favorable reservoirs such as underwater distributary channel sandstone along the tectonic transformation belt，as well as the fracture transformation of tight sandstone reservoirs. Meantime，the fractures also has a destructive effect on the hydrocarbon accumulation of Permian and Mesozoic periods in the study area. ④The three zones in the north of Yima sub-sag are more favorable for hydrocarbon accumulation in Permian and Mesozoic periods.
2020, 27(5):25-32.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.003
Abstract:
Aiming at the cataclastic band developed in lithic quartz sandstone of K2h Formation in Yuan’an Graben，based on the detailed study of its macro-characteristics and experimental analysis data，the micro-characteristics of the cataclastic band are described，and the deformation mechanism is analyzed and discussed in detail. The results show that the deformation band in the study area has the characteristics of shallow to middle burial depth，in which cataclastic band is mainly developed. The most common modes of grain breakage are multi-point contact and complete fragmentation. The micro-heterogeneity is characterized by the inhomogeneous deformation of a single cataclastic band along its strike，the relatively homogeneousdeformation of a single cataclastic band perpendicular to its strike，the strengthening of the cataclastic band caused by the strong cataclastic flow and the inhomogeneous inner-structure of the cataclastic bandclusters，which reflects the formation of the cataclastic deformation band，and also indicates that its deformation mechanism changes from cataclasis to cataclastic flow. The temporal sequence of the deformation zone is from the cataclastic core formation to medium-degree fragmented cataclastic band to cataclastic band with complete crushed grains to cataclastic band clusters. Finally，a sliding surface may be formed along a certain cataclastic band. In the field，it is common to find the medium-degree fragmented cataclastic band clusters and completely crushed deformation band clusters. Compared with the host rock，the porosity and permeability in the completely crushed deformation band clusters are seriously decreased，which can be reduced by 4 orders of magnitude in actual measurement，and it is likely to have a great impact on fluid flow.
Aiming at the cataclastic band developed in lithic quartz sandstone of K2h Formation in Yuan’an Graben，based on the detailed study of its macro-characteristics and experimental analysis data，the micro-characteristics of the cataclastic band are described，and the deformation mechanism is analyzed and discussed in detail. The results show that the deformation band in the study area has the characteristics of shallow to middle burial depth，in which cataclastic band is mainly developed. The most common modes of grain breakage are multi-point contact and complete fragmentation. The micro-heterogeneity is characterized by the inhomogeneous deformation of a single cataclastic band along its strike，the relatively homogeneousdeformation of a single cataclastic band perpendicular to its strike，the strengthening of the cataclastic band caused by the strong cataclastic flow and the inhomogeneous inner-structure of the cataclastic bandclusters，which reflects the formation of the cataclastic deformation band，and also indicates that its deformation mechanism changes from cataclasis to cataclastic flow. The temporal sequence of the deformation zone is from the cataclastic core formation to medium-degree fragmented cataclastic band to cataclastic band with complete crushed grains to cataclastic band clusters. Finally，a sliding surface may be formed along a certain cataclastic band. In the field，it is common to find the medium-degree fragmented cataclastic band clusters and completely crushed deformation band clusters. Compared with the host rock，the porosity and permeability in the completely crushed deformation band clusters are seriously decreased，which can be reduced by 4 orders of magnitude in actual measurement，and it is likely to have a great impact on fluid flow.
2020, 27(5):33-43.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.004
Abstract:
The brittleness of glutenite core is closely related to the hydraulic fracturing in oil and gas fields. It is of great significance to analyze the influence of the brittleness characteristics of glutenite reservoir on the complexity of hydraulic fractures to provide reference for the selection of target layers and the design of hydraculic fracturing process. Considering the brittleness characteristics of the whole process of rock failure（i.e.，the pre-peak and post-peak stages），a reservoir rock brittleness evaluation model based on the energy dissipation of the whole process of core failure is proposed. The accuracy of the model is verified by using the uniaxial and triaxial total stress-strain curves of glutenite and the existing brittleness evaluation model. The correlation between the core mechanical parameters and brittleness index under the different confining pressures is analyzed，and the effects of the brittleness index on hydraulic fracture complexity is studied by using the results of the laboratory test and microseismic monitoring of hydraulic fractures. The results show that the brittleness evaluation model can comprehensively evaluate the brittleness characteristics of the whole process of core failure，which is more sensitive to the brittleness changes of rocks with different lithology and different confining pressure than the traditional brittleness evaluation models. The parameters of core strength and elastic modulus under the different confining pressures have negative correlation with the brittleness index. The layers with the strong brittleness are more likely to form complex fractures through hydraulic fracturing，and obtain bigger stimulated reservoir volume（SRV）. It is feasible to predict and analyze the complexity of hydraulic fracture according to the brittleness characteristics of core.
The brittleness of glutenite core is closely related to the hydraulic fracturing in oil and gas fields. It is of great significance to analyze the influence of the brittleness characteristics of glutenite reservoir on the complexity of hydraulic fractures to provide reference for the selection of target layers and the design of hydraculic fracturing process. Considering the brittleness characteristics of the whole process of rock failure（i.e.，the pre-peak and post-peak stages），a reservoir rock brittleness evaluation model based on the energy dissipation of the whole process of core failure is proposed. The accuracy of the model is verified by using the uniaxial and triaxial total stress-strain curves of glutenite and the existing brittleness evaluation model. The correlation between the core mechanical parameters and brittleness index under the different confining pressures is analyzed，and the effects of the brittleness index on hydraulic fracture complexity is studied by using the results of the laboratory test and microseismic monitoring of hydraulic fractures. The results show that the brittleness evaluation model can comprehensively evaluate the brittleness characteristics of the whole process of core failure，which is more sensitive to the brittleness changes of rocks with different lithology and different confining pressure than the traditional brittleness evaluation models. The parameters of core strength and elastic modulus under the different confining pressures have negative correlation with the brittleness index. The layers with the strong brittleness are more likely to form complex fractures through hydraulic fracturing，and obtain bigger stimulated reservoir volume（SRV）. It is feasible to predict and analyze the complexity of hydraulic fracture according to the brittleness characteristics of core.
2020, 27(5):44-52.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.005
Abstract:
Well logging evaluation for shale oil is one of the difficulties in logging interpretation at present. Based on the accumulation characteristics of shale oil such as“self-generation and self-storage”and“high pressure for hydrocarbon generation”，as well as the macro phenomena of geological“sweet spots”such as the abnormal high pressure and active oil and gas display，authors analyze the essential characteristics of shale oil“sweet spots”and consider that the hydrocarbon movability is the most important characteristic of the geological“sweet spots”of shale oil in this study. The statistical results of the drilling，mud logging，well logging and oil testing data from hundreds of shale oil wells in Shengli Oilfield show that the geological“sweet spot”intervals have good physical properties，high formation pressure and high oil and gas charging， which make it easier to form obvious and stable low resistivity invasion profile near the borehole. Since the dual lateral logging is more effective to show the low invasion feature than the induction logging，the response relationship between the hydrocarbon movability of shale oil and well logging curves is established for the first time. Based on the amplitude difference of dual lateral logging，the quantitative evaluation coefficient of hydrocarbon mobility is proposed to evaluate the geological “sweet spots”of shale oil. The grading evaluation of geological“sweet spots”for several shale oil wells is conducted by this method，and the results match well with the lithofacies analysis and oil test results，which indicate a good application performance.
Well logging evaluation for shale oil is one of the difficulties in logging interpretation at present. Based on the accumulation characteristics of shale oil such as“self-generation and self-storage”and“high pressure for hydrocarbon generation”，as well as the macro phenomena of geological“sweet spots”such as the abnormal high pressure and active oil and gas display，authors analyze the essential characteristics of shale oil“sweet spots”and consider that the hydrocarbon movability is the most important characteristic of the geological“sweet spots”of shale oil in this study. The statistical results of the drilling，mud logging，well logging and oil testing data from hundreds of shale oil wells in Shengli Oilfield show that the geological“sweet spot”intervals have good physical properties，high formation pressure and high oil and gas charging， which make it easier to form obvious and stable low resistivity invasion profile near the borehole. Since the dual lateral logging is more effective to show the low invasion feature than the induction logging，the response relationship between the hydrocarbon movability of shale oil and well logging curves is established for the first time. Based on the amplitude difference of dual lateral logging，the quantitative evaluation coefficient of hydrocarbon mobility is proposed to evaluate the geological “sweet spots”of shale oil. The grading evaluation of geological“sweet spots”for several shale oil wells is conducted by this method，and the results match well with the lithofacies analysis and oil test results，which indicate a good application performance.
2020, 27(5):53-61.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.006
Abstract:
The matching between the heterogeneous combination flooding system and the reservoir pore throat is the key factor for realizing the effective injection of the flooding system and dramatically enhancing oil recovery. Based on physical simulation research，a matching relationship chart of the viscoelastic particle flooding agent and reservoir pore throat is established. The 1st to 3rd Submembers of the 2nd Member of Shahejie Formation（Es21-3）in Sheng1 area，Shengtuo Oilfield was preferred as the pilot area，which was the typical post-polymer flooding reservoir. Based on the analysis of the reservoir pore throat characteristics and the established matching relationship chart，the viscoelastic particle flooding agent suitable for the target reservoir in the pilot area was developed，and the efficient heterogeneous combination flooding system suitable for the target reservoir in the pilot area was constructed based on the combination of the polymer and the anionic and nonamphoteric surfactants. The research results show that the heterogeneous combination flooding technology could effectively produce the remaining oil in different types of pores with different pore sizes. The microscopic remaining oil production mechanism of the heterogeneous combination flooding system is proposed. Field application has confirmed that the average injection pressure of injection well was increased by 4.7 MPa，and the average starting pressure was increased by 5.1 MPa.The drag resistance coefficient reached 1.7. The pressure distribution was more uniform，and the displacement was more balanced. As of May 2020，the significant water-cut reduction and production rate increment have been achieved in the pilot area. The comprehensive water-cut of the production well was decreased by 6.3%，and the production rate in the pilot area increased from 39 t/d to 141 t/d. The numerical simulation prediction shows that the oil recovery rate could be further increased by 7.6% after polymer flooding，which has broad prospects for popularization and application.
The matching between the heterogeneous combination flooding system and the reservoir pore throat is the key factor for realizing the effective injection of the flooding system and dramatically enhancing oil recovery. Based on physical simulation research，a matching relationship chart of the viscoelastic particle flooding agent and reservoir pore throat is established. The 1st to 3rd Submembers of the 2nd Member of Shahejie Formation（Es21-3）in Sheng1 area，Shengtuo Oilfield was preferred as the pilot area，which was the typical post-polymer flooding reservoir. Based on the analysis of the reservoir pore throat characteristics and the established matching relationship chart，the viscoelastic particle flooding agent suitable for the target reservoir in the pilot area was developed，and the efficient heterogeneous combination flooding system suitable for the target reservoir in the pilot area was constructed based on the combination of the polymer and the anionic and nonamphoteric surfactants. The research results show that the heterogeneous combination flooding technology could effectively produce the remaining oil in different types of pores with different pore sizes. The microscopic remaining oil production mechanism of the heterogeneous combination flooding system is proposed. Field application has confirmed that the average injection pressure of injection well was increased by 4.7 MPa，and the average starting pressure was increased by 5.1 MPa.The drag resistance coefficient reached 1.7. The pressure distribution was more uniform，and the displacement was more balanced. As of May 2020，the significant water-cut reduction and production rate increment have been achieved in the pilot area. The comprehensive water-cut of the production well was decreased by 6.3%，and the production rate in the pilot area increased from 39 t/d to 141 t/d. The numerical simulation prediction shows that the oil recovery rate could be further increased by 7.6% after polymer flooding，which has broad prospects for popularization and application.
2020, 27(5):62-70.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.007
Abstract:
The heavy oil dispersed viscosity reducer has attracted much attention due to its unique functions and ability to reduce the processing link of crude oil. However，so far，the development of water-soluble dispersed viscosity reducer and the research on microscopic oil displacement mechanisms have been rare. Therefore，on the basis of testing the structure of heavy oil from Shengli Le’an Oilfield，the viscosity reduction mechanisms were studied through infrared spectrum analysis，transmission electron microscopy（TEM）and atomic force microscope scanning（AFMS）experiments on the heavy oil before and after adding the viscosity reducer；Using the CT and micro-etching models under high temperature and high pressure conditions，the micro-displacement mechanism of water-soluble dispersed viscosity reducer in the reservoir was studied.The viscosity reduction mechanisms are mainly as follows：the dispersing viscosity reducer penetrates and diffuses between the colloidal and asphaltene sheet molecules after it is combined with the heavy oil molecules；the combination of heterocyclic atoms in the viscosity reducer and colloids reduces the formation of complexes between family molecules and separates the aggregates；the original regular aggregates are transformed into sheet-like molecules with irregular distribution；the molecular structure becomes loose，the degree of order is decreased，and the entropy is increased，which reduce both the aggregation of heavy oil molecules and the intermolecular forces. Its microscopic oil displacement mechanisms in high temperature and high pressure reservoirs are mainly manifested as that，the dispersive intercalation has a stripping effect on the heavy oil adsorbed on the surface of rock particles and the efficiency is high at the conditions of low displacement rate and high concentration；the stripping effect is relatively weakened and there is a large amount of surrounding cluster-like residual oil at the conditions of high rate and low concentration.
The heavy oil dispersed viscosity reducer has attracted much attention due to its unique functions and ability to reduce the processing link of crude oil. However，so far，the development of water-soluble dispersed viscosity reducer and the research on microscopic oil displacement mechanisms have been rare. Therefore，on the basis of testing the structure of heavy oil from Shengli Le’an Oilfield，the viscosity reduction mechanisms were studied through infrared spectrum analysis，transmission electron microscopy（TEM）and atomic force microscope scanning（AFMS）experiments on the heavy oil before and after adding the viscosity reducer；Using the CT and micro-etching models under high temperature and high pressure conditions，the micro-displacement mechanism of water-soluble dispersed viscosity reducer in the reservoir was studied.The viscosity reduction mechanisms are mainly as follows：the dispersing viscosity reducer penetrates and diffuses between the colloidal and asphaltene sheet molecules after it is combined with the heavy oil molecules；the combination of heterocyclic atoms in the viscosity reducer and colloids reduces the formation of complexes between family molecules and separates the aggregates；the original regular aggregates are transformed into sheet-like molecules with irregular distribution；the molecular structure becomes loose，the degree of order is decreased，and the entropy is increased，which reduce both the aggregation of heavy oil molecules and the intermolecular forces. Its microscopic oil displacement mechanisms in high temperature and high pressure reservoirs are mainly manifested as that，the dispersive intercalation has a stripping effect on the heavy oil adsorbed on the surface of rock particles and the efficiency is high at the conditions of low displacement rate and high concentration；the stripping effect is relatively weakened and there is a large amount of surrounding cluster-like residual oil at the conditions of high rate and low concentration.
2020, 27(5):71-78.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.008
Abstract:
The tight sandstone reservoirs are characterized by small pore throats，strong hydrophilicity，and well-developed micro-fractures，etc. The capillary imbibition phenomenon is prone to occur in the reservoir under the action of a large capillary force. In order to reveal the microscopic distribution of capillary imbibition of water in the pore network，the tight sandstones of Penglaizhen Formation in western Sichuan are selected to conduct the vertical spontaneous imbibition experiments under simulated formation water conditions，and the distribution and variation laws of the fluid during the imbibition process are studied by using the nuclear magnetic resonance（NMR）technology. The results show that when the spontaneous imbibition lasts for 5 minutes，the self-imbibition water is mainly concentrated in the nano-scale pores of 0-0.1 μm，accounting for more than 84%. With the increase of spontaneous imbibition time，the proportion of self-imbibition water distributed in the nano-scale pores of 0-0.1 μm gradually decreases，and the proportion of self-imbibition water distributed in the pores of submicron level of 0.1-1 μm and micron level of 1-10 μm gradually increases，in which the maximum increase of self-imbibition water in submicron pores of 0.1-1 μm increases from 11% to 25%. The number of micron pores with a radius greater than 10 μm is small，and the capillary force is extremely weak，resulting in a low degree of self-imbibition water. The largest proportion is only 1.95%. There is no obvious upward or downward trend in the proportion of self-imbibition water. When the external positive pressure difference is not considered，the capillary imbibition phenomenon will preferentially occur in nano-scale pores. Pore radius size，pore type，proportion of different pore radius，water saturation，etc.are the main factors that affect the microscopic distribution characteristics of capillary imbibition.
The tight sandstone reservoirs are characterized by small pore throats，strong hydrophilicity，and well-developed micro-fractures，etc. The capillary imbibition phenomenon is prone to occur in the reservoir under the action of a large capillary force. In order to reveal the microscopic distribution of capillary imbibition of water in the pore network，the tight sandstones of Penglaizhen Formation in western Sichuan are selected to conduct the vertical spontaneous imbibition experiments under simulated formation water conditions，and the distribution and variation laws of the fluid during the imbibition process are studied by using the nuclear magnetic resonance（NMR）technology. The results show that when the spontaneous imbibition lasts for 5 minutes，the self-imbibition water is mainly concentrated in the nano-scale pores of 0-0.1 μm，accounting for more than 84%. With the increase of spontaneous imbibition time，the proportion of self-imbibition water distributed in the nano-scale pores of 0-0.1 μm gradually decreases，and the proportion of self-imbibition water distributed in the pores of submicron level of 0.1-1 μm and micron level of 1-10 μm gradually increases，in which the maximum increase of self-imbibition water in submicron pores of 0.1-1 μm increases from 11% to 25%. The number of micron pores with a radius greater than 10 μm is small，and the capillary force is extremely weak，resulting in a low degree of self-imbibition water. The largest proportion is only 1.95%. There is no obvious upward or downward trend in the proportion of self-imbibition water. When the external positive pressure difference is not considered，the capillary imbibition phenomenon will preferentially occur in nano-scale pores. Pore radius size，pore type，proportion of different pore radius，water saturation，etc.are the main factors that affect the microscopic distribution characteristics of capillary imbibition.
2020, 27(5):79-85.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.009
Abstract:
At present，the supercritical CO2 assisted fracturing technology has become one of the effective methods for the development of tight oil reservoirs. In the process of fracturing，the energy storage and flowback effect of fracturing fluid has become one of the focuses in recent years. In order to quantitatively evaluate the energy storage in the formation and fluid flowback efficiency during the supercritical CO2 displacement，this paper independently designed an experimental apparatus to investigate the efficiency of energy storage and flowback under different displacement modes of the supercritical CO2. The changes of mean pressure and flowback efficiencies of the core system under continuous gas injection，continuous water injection and alternate water and gas injection were compared by the laboratory experiment under reservoir temperature and pressure，and the gas injection slug with alternating water and gas injection was also optimized. The results show that the supercritical CO2 as a preflush can increase the energy storage efficiency of subsequent injection of slippery water.The injected supercritical CO2 expands the volume of crude oil and irreducible water，and the degree of expansion is greatly affected by the dissolved amount of supercritical CO2，but less affected by the core system pressure. The displacement method of injecting supercritical CO2 followed by injecting slippage water shows the best energy increasing efficiency，which can achieve supercritical CO2 storage，and the highest flowback efficiency of slippage water and oil recovery. From the perspective of the energy storage and fluid flowback efficiencies，the best volume of the supercritical CO2 slug is 0.5 PV.
At present，the supercritical CO2 assisted fracturing technology has become one of the effective methods for the development of tight oil reservoirs. In the process of fracturing，the energy storage and flowback effect of fracturing fluid has become one of the focuses in recent years. In order to quantitatively evaluate the energy storage in the formation and fluid flowback efficiency during the supercritical CO2 displacement，this paper independently designed an experimental apparatus to investigate the efficiency of energy storage and flowback under different displacement modes of the supercritical CO2. The changes of mean pressure and flowback efficiencies of the core system under continuous gas injection，continuous water injection and alternate water and gas injection were compared by the laboratory experiment under reservoir temperature and pressure，and the gas injection slug with alternating water and gas injection was also optimized. The results show that the supercritical CO2 as a preflush can increase the energy storage efficiency of subsequent injection of slippery water.The injected supercritical CO2 expands the volume of crude oil and irreducible water，and the degree of expansion is greatly affected by the dissolved amount of supercritical CO2，but less affected by the core system pressure. The displacement method of injecting supercritical CO2 followed by injecting slippage water shows the best energy increasing efficiency，which can achieve supercritical CO2 storage，and the highest flowback efficiency of slippage water and oil recovery. From the perspective of the energy storage and fluid flowback efficiencies，the best volume of the supercritical CO2 slug is 0.5 PV.
2020, 27(5):86-96.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.010
Abstract:
CO2 flooding has the advantages of easy injection and miscibility in the development of low permeability reservoirs，but it will inevitably bring asphaltene deposition problems in the process of oil displacement，resulting in reservoir pore throat blockage，wettability change and permeability reduction. Nanoparticles have great potential in inhibiting asphaltene deposition，and are expected to be further used to improve oil recovery in low permeability reservoirs. In this paper，the mechanism of nanoparticles inhibiting asphaltene deposition is discussed from the molecular structure level，the latest research progress in recent years is summarized，the challenges of the research and application are pointed out，and its prospective is predicted. Nanoparticles mainly inhibit asphaltene deposition through adsorption and dispersion. Adsorption de? pends on the electrostatic attraction between the surface charge of the nanoparticles and the strong polar groups of the asphaltene，so that the nanoparticles are coated on the surface of asphaltene molecules and asphaltene deposition is avoided.Dispersion is mainly through the grafting of organic chains on the surface of nanoparticles to form van der Waals force or steric hindrance with asphaltene molecules，thus destroying the self-association between asphaltene molecules and achieving the inhibition of asphaltene deposition. However，the technology is still in the stage of laboratory study，and its large scale field application is restricted by factors such as the stability of nanofluids，the economy of nanomaterials，and the uncertainty to the environment，etc. The development of novel nanofluids with good stability，high economic benefits and environment-friendly is the key to future research，and the establishment of a more accurate mathematical model is also an important direction for future work.
CO2 flooding has the advantages of easy injection and miscibility in the development of low permeability reservoirs，but it will inevitably bring asphaltene deposition problems in the process of oil displacement，resulting in reservoir pore throat blockage，wettability change and permeability reduction. Nanoparticles have great potential in inhibiting asphaltene deposition，and are expected to be further used to improve oil recovery in low permeability reservoirs. In this paper，the mechanism of nanoparticles inhibiting asphaltene deposition is discussed from the molecular structure level，the latest research progress in recent years is summarized，the challenges of the research and application are pointed out，and its prospective is predicted. Nanoparticles mainly inhibit asphaltene deposition through adsorption and dispersion. Adsorption de? pends on the electrostatic attraction between the surface charge of the nanoparticles and the strong polar groups of the asphaltene，so that the nanoparticles are coated on the surface of asphaltene molecules and asphaltene deposition is avoided.Dispersion is mainly through the grafting of organic chains on the surface of nanoparticles to form van der Waals force or steric hindrance with asphaltene molecules，thus destroying the self-association between asphaltene molecules and achieving the inhibition of asphaltene deposition. However，the technology is still in the stage of laboratory study，and its large scale field application is restricted by factors such as the stability of nanofluids，the economy of nanomaterials，and the uncertainty to the environment，etc. The development of novel nanofluids with good stability，high economic benefits and environment-friendly is the key to future research，and the establishment of a more accurate mathematical model is also an important direction for future work.
2020, 27(5):97-104.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.011
Abstract:
The acidic fluid formed by CO2 dissolved in water could dissolve sandstone in the process of CO2 flooding in reservoirs. The dissolution could change the physical properties of the reservoirs and obviously affect the oil recovery. Therefore，the static immersion experiment and dynamic displacement experiment of CO2 flooding in sandstone reservoirs were carried out to quantitatively study the influence of dissolution on the physical properties of the reservoirs under different temperature and pressure conditions. The experimental results show that the dissolution effect is obvious in the process of CO2 immersion and flooding. The porosity and permeability increase with the increase of temperature and pressure exponentially. The mathematical expression equations of the relationships between the temperature，pressure and porosity change rate and permeability change rate were obtained based on the experimental data. The numerical simulation study was carried out on Block H3 of Changqing Oilfield with the aid of mathematical equations. The results showed that the dissolution in the overall reservoir of the study area occurred，and the dissolution degree in the injection well area was higher. The oil recovery considering dissolution is 26.08%，but the oil recovery without considering dissolution is 21.03%. The enhanced oil recovery（EOR）is 5.05%.
The acidic fluid formed by CO2 dissolved in water could dissolve sandstone in the process of CO2 flooding in reservoirs. The dissolution could change the physical properties of the reservoirs and obviously affect the oil recovery. Therefore，the static immersion experiment and dynamic displacement experiment of CO2 flooding in sandstone reservoirs were carried out to quantitatively study the influence of dissolution on the physical properties of the reservoirs under different temperature and pressure conditions. The experimental results show that the dissolution effect is obvious in the process of CO2 immersion and flooding. The porosity and permeability increase with the increase of temperature and pressure exponentially. The mathematical expression equations of the relationships between the temperature，pressure and porosity change rate and permeability change rate were obtained based on the experimental data. The numerical simulation study was carried out on Block H3 of Changqing Oilfield with the aid of mathematical equations. The results showed that the dissolution in the overall reservoir of the study area occurred，and the dissolution degree in the injection well area was higher. The oil recovery considering dissolution is 26.08%，but the oil recovery without considering dissolution is 21.03%. The enhanced oil recovery（EOR）is 5.05%.
2020, 27(5):105-111.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.012
Abstract:
When the low permeability reservoirs are developed with conventional waterflooding technology，producers will have low efficiency，low oil and liquid production，and poor economic benefits. Traditional water-flooding development technology cannot meet the requirements of economic and effective development of low permeability reservoirs. Although the development mode of depletion recovery after volume fracturing of tight oil can improve the initial productivity of single well, due to the characteristics of small sand body, low formation pressure coefficient, high viscosity of crude oil and low gas oil ratio, there are still defects of rapid production decline, low cumulative oil production and low recovery factor. There is an urgent need to adjust development ideas and change waterflooding development mode. Therefore，this paper innovatively puts forward three development ideas for low permeability reservoirs，namely，the transformation from radial displacement to linear displacement，transformation from continuous water injection to imbibition oil recovery such as asynchronous injection and production，water injection huff and puff，producer-injector exchange，and transformation from increasing producing reserves by shortening well distance of producer and injector to increasing fracture-controlled reserve by volume fracturing. A brand-new development model of“volume fracturing+effective displacement+imbibition oil recovery”is established and applied to GD6X1 Block in Dagang Oilfield. The preliminary implementation effect is remarkable.
When the low permeability reservoirs are developed with conventional waterflooding technology，producers will have low efficiency，low oil and liquid production，and poor economic benefits. Traditional water-flooding development technology cannot meet the requirements of economic and effective development of low permeability reservoirs. Although the development mode of depletion recovery after volume fracturing of tight oil can improve the initial productivity of single well, due to the characteristics of small sand body, low formation pressure coefficient, high viscosity of crude oil and low gas oil ratio, there are still defects of rapid production decline, low cumulative oil production and low recovery factor. There is an urgent need to adjust development ideas and change waterflooding development mode. Therefore，this paper innovatively puts forward three development ideas for low permeability reservoirs，namely，the transformation from radial displacement to linear displacement，transformation from continuous water injection to imbibition oil recovery such as asynchronous injection and production，water injection huff and puff，producer-injector exchange，and transformation from increasing producing reserves by shortening well distance of producer and injector to increasing fracture-controlled reserve by volume fracturing. A brand-new development model of“volume fracturing+effective displacement+imbibition oil recovery”is established and applied to GD6X1 Block in Dagang Oilfield. The preliminary implementation effect is remarkable.
2020, 27(5):112-118.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.013
Abstract:
The water drive volume sweep coefficient is an important parameter in oilfield development. At present，its calculation method needs to fit the relative permeability curves of oil and water phases，and it is difficult to meet the application requirements of complex reservoirs with diverse oil-water percolation laws. To solve this problem，based on the approximate theoretical water drive curve and the Welge linear equation，a new dynamic calculation method of displacement efficiency and volume sweep coefficient of water drive reservoir is established through theoretical derivation. The volume sweep coefficient and displacement efficiency in different development stages can be calculated based on actual production data，which overcomes the dependence of existing methods on the relative permeability curves of oil and water phases. The results show that the new method is reliable，and can accurately obtain the variation rules of displacement efficiency and volume sweep coefficient in different water cut stages in complex reservoirs. The proposed method is featured with accessible date，convenient calculation，and wide adaptability to various types of reservoirs，and it can realize the accurate calculation from low water cut stage to ultra-high water cut stage，showing a broad application prospect in dynamic analysis and development effect evaluation in oilfield.
The water drive volume sweep coefficient is an important parameter in oilfield development. At present，its calculation method needs to fit the relative permeability curves of oil and water phases，and it is difficult to meet the application requirements of complex reservoirs with diverse oil-water percolation laws. To solve this problem，based on the approximate theoretical water drive curve and the Welge linear equation，a new dynamic calculation method of displacement efficiency and volume sweep coefficient of water drive reservoir is established through theoretical derivation. The volume sweep coefficient and displacement efficiency in different development stages can be calculated based on actual production data，which overcomes the dependence of existing methods on the relative permeability curves of oil and water phases. The results show that the new method is reliable，and can accurately obtain the variation rules of displacement efficiency and volume sweep coefficient in different water cut stages in complex reservoirs. The proposed method is featured with accessible date，convenient calculation，and wide adaptability to various types of reservoirs，and it can realize the accurate calculation from low water cut stage to ultra-high water cut stage，showing a broad application prospect in dynamic analysis and development effect evaluation in oilfield.
2020, 27(5):119-125.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.014
Abstract:
Low permeability reservoirs have high seepage resistance，and the reservoir fracturing is an effective measure to improve the oil well production and development effect. Based on the basic seepage characteristics of well fracturing，the unstable seepage process of well in the elastic energy development is analyzed. By using the fracture microelement method and the superposition principle of pressure drop，a calculation method for the production of fractured wells under different radius is established under the influence of the starting pressure gradient. Combined with actual reservoir conditions，the effects of different reservoir parameters and fracturing parameters on well production，as well as the variation rules of the production and the propagation range of pressure drop in the reservoir，are analyzed. Then，the limit of the effective radius of the oil well in both parallel and vertical fractures and the effective radius that meets the economic daily oil production limit are determined. The study results show that，for the fracturing development of low-permeability reservoirs，the influence of starting pressure gradient and fracture parameters should be comprehensively considered to determine the limit range of oil wells in different directions，and so as to provide scientific basis for the effective development of such reservoirs.
Low permeability reservoirs have high seepage resistance，and the reservoir fracturing is an effective measure to improve the oil well production and development effect. Based on the basic seepage characteristics of well fracturing，the unstable seepage process of well in the elastic energy development is analyzed. By using the fracture microelement method and the superposition principle of pressure drop，a calculation method for the production of fractured wells under different radius is established under the influence of the starting pressure gradient. Combined with actual reservoir conditions，the effects of different reservoir parameters and fracturing parameters on well production，as well as the variation rules of the production and the propagation range of pressure drop in the reservoir，are analyzed. Then，the limit of the effective radius of the oil well in both parallel and vertical fractures and the effective radius that meets the economic daily oil production limit are determined. The study results show that，for the fracturing development of low-permeability reservoirs，the influence of starting pressure gradient and fracture parameters should be comprehensively considered to determine the limit range of oil wells in different directions，and so as to provide scientific basis for the effective development of such reservoirs.
2020, 27(5):126-133.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.015
Abstract:
The deep and ultra-deep reservoirs have high formation pressure，and the unreasonable parameter control during the development process can easily lead to sanding，casing damage，and cement plugging in oil wells. Determining a reasonable production pressure drop is the key to the effective use of the reservoir. Taking Yongjin Oilfield as an example，through preliminary oil test and trial production analysis，it is believed that improper production pressure drop control and inadequate understanding of asphaltene precipitation are the key factors that have prevented the oilfield from being developed economically for years. Mature software is used for sand production prediction，and wellbore pressure calculation is carried out，in order to seek a reasonable working system. The reason and prevention method of asphaltene precipitation are studied by experimental methods. The results show that the critical production pressure drop of the formation in the study area is 34.9 MPa. During the preliminary oil test，trial production perforation and production，the pressure drop exceeded the critical production pressure drop and resulted in sand production. The crude oil system is unstable，and the CI value is 2.33.The wellbore pressure is lower than the asphaltene stable pressure，which leads to asphaltene precipitation and plugging.The analysis shows that this is the main reason for the poor early development effect. Based on this，the development strategy for the whole process of pressure control is determined from the opening of the oil and gas layer. When the formation pressure is high，the reasonable pressure controlled production can solve the problems of sand production and asphaltene precipitation. When the pressure drops，asphalt dispersant is added to assist production. Two wells have been tested and all have been successful.
The deep and ultra-deep reservoirs have high formation pressure，and the unreasonable parameter control during the development process can easily lead to sanding，casing damage，and cement plugging in oil wells. Determining a reasonable production pressure drop is the key to the effective use of the reservoir. Taking Yongjin Oilfield as an example，through preliminary oil test and trial production analysis，it is believed that improper production pressure drop control and inadequate understanding of asphaltene precipitation are the key factors that have prevented the oilfield from being developed economically for years. Mature software is used for sand production prediction，and wellbore pressure calculation is carried out，in order to seek a reasonable working system. The reason and prevention method of asphaltene precipitation are studied by experimental methods. The results show that the critical production pressure drop of the formation in the study area is 34.9 MPa. During the preliminary oil test，trial production perforation and production，the pressure drop exceeded the critical production pressure drop and resulted in sand production. The crude oil system is unstable，and the CI value is 2.33.The wellbore pressure is lower than the asphaltene stable pressure，which leads to asphaltene precipitation and plugging.The analysis shows that this is the main reason for the poor early development effect. Based on this，the development strategy for the whole process of pressure control is determined from the opening of the oil and gas layer. When the formation pressure is high，the reasonable pressure controlled production can solve the problems of sand production and asphaltene precipitation. When the pressure drops，asphalt dispersant is added to assist production. Two wells have been tested and all have been successful.
2020, 27(5):134-142.
DOI: 10.13673/j.cnki.cn37-1359/te.2020.05.016
Abstract:
The hydraulic fracturing technology has been widely applied to the development of shale gas and oil reservoirs.In order to increase the productivity，the proppant and sand-carrying fluid are mixed into the fracture according to different mass ratios，which can form an effective proppant layout，thereby improving the fracture conductivity. The transportation distance and laying range of proppant in the complex fracture network are important indicators to measure the effect of hydraulic fracturing. Physical experiments are conducted to study the effects of the sand ratio，angle between main fracture and branch fracture and type of proppant on the proppant transportation and layout in complex fracture networks. It is found that：①As the sand ratio increased from 3.0% to 4.2%，the ratio of proppant layout height to fracture height in the main fracture increases from 0.44 to 0.465，and the ratio of proppant mass in branch fracture to proppant mass in the complex fracture network increases from 17% to 25%. ②As the angle between the main fracture and the branch fracture decreases from 90° to 30°，the ratio of the mass of proppant in the branch fracture to the mass of proppant in the complex fracture network increases from 22% to 30%. ③The ratio of the mass of the proppant entering the complex fracture network to the total mass of the proppant used in the experiment shows a tendency to increase rapidly and then slowly with the ratio of the experiment time to the total experiment time. When the ratio of the experimental time to the total experimental time is 0.6，the ratio of the mass of the proppant entering the complex fracture network to the total mass of the proppant used in the experiment is 65% to 80%. ④The ceramsite and self-suspending proppant are not well placed at the entrance of the fracture. The proppant layout height has obvious abrupt changes at the intersection of the main fracture and the branch fracture and at the position where the fracture height changes.
The hydraulic fracturing technology has been widely applied to the development of shale gas and oil reservoirs.In order to increase the productivity，the proppant and sand-carrying fluid are mixed into the fracture according to different mass ratios，which can form an effective proppant layout，thereby improving the fracture conductivity. The transportation distance and laying range of proppant in the complex fracture network are important indicators to measure the effect of hydraulic fracturing. Physical experiments are conducted to study the effects of the sand ratio，angle between main fracture and branch fracture and type of proppant on the proppant transportation and layout in complex fracture networks. It is found that：①As the sand ratio increased from 3.0% to 4.2%，the ratio of proppant layout height to fracture height in the main fracture increases from 0.44 to 0.465，and the ratio of proppant mass in branch fracture to proppant mass in the complex fracture network increases from 17% to 25%. ②As the angle between the main fracture and the branch fracture decreases from 90° to 30°，the ratio of the mass of proppant in the branch fracture to the mass of proppant in the complex fracture network increases from 22% to 30%. ③The ratio of the mass of the proppant entering the complex fracture network to the total mass of the proppant used in the experiment shows a tendency to increase rapidly and then slowly with the ratio of the experiment time to the total experiment time. When the ratio of the experimental time to the total experimental time is 0.6，the ratio of the mass of the proppant entering the complex fracture network to the total mass of the proppant used in the experiment is 65% to 80%. ④The ceramsite and self-suspending proppant are not well placed at the entrance of the fracture. The proppant layout height has obvious abrupt changes at the intersection of the main fracture and the branch fracture and at the position where the fracture height changes.
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