Heterogeneity in carbonate formations due to discontinuities(e.g.,fractures and cavities)will bring about distinctive acid stimulation effects.However,the differences in fracturing behavior between homogeneous and het...Heterogeneity in carbonate formations due to discontinuities(e.g.,fractures and cavities)will bring about distinctive acid stimulation effects.However,the differences in fracturing behavior between homogeneous and heterogeneous carbonate formations remain unclear,complicating the optimization of acid fracturing strategies.In this paper,full-diameter carbonate rock samples with different degrees of discontinuity development are selected to investigate the fracturing behavior under different fluid types and injection schemes.Advanced techniques,including 3D CT scanning and 3D laser scanning,are employed to analyze fracture morphology and etching characteristics,respectively.Experimental results show that the coupled hydraulic-chemical effects play different roles in fracture induction between fracture-cavity developed and undeveloped carbonate rocks.Acid-fracturing stimulation consistently induces multiple types of complex fractures in fracture-cavity carbonate rocks,whereas it results in a single artificial fracture in less fracture-cavity carbonate rocks.Furthermore,localized etching patterns are prevalent in most fracture-cavity carbonate rocks,whereas homogeneous carbonate rocks exhibit regional or global etching characteristics.In both carbonate rocks,the stimulation effect of guar fluid is inferior to that of gelled acid but comparable to self-generating acid.Further findings are that alternating fracturing with guar and acid fluids in fracture-cavity carbonate rocks can sustain or even increase the injection pressure,facilitating the formation of new or depth-penetrating fractures.This phenomenon,however,is not observed in fracture-cavity undeveloped carbonate rocks.Potential interaction modes between induced fracture and natural fractures/cavities under different injection conditions are also identified.Finally,preferred fracturing schemes applicable to different carbonate formations are recommended based on the area,number and roughness of the induced fractures.展开更多
Pressure control in deep shale gas horizontal wells can reduce the stress sensitivity of hydraulic fractures and improve the estimated ultimate recovery(EUR).In this study,a hydraulic fracture stress sensitivity model...Pressure control in deep shale gas horizontal wells can reduce the stress sensitivity of hydraulic fractures and improve the estimated ultimate recovery(EUR).In this study,a hydraulic fracture stress sensitivity model is proposed to characterize the effect of pressure drop rate on fracture permeability.Furthermore,a production prediction model is introduced accounting for a non-uniform hydraulic fracture conductivity distribution.The results reveal that increasing the fracture conductivity leads to a rapid daily production increase in the early stages.However,above 0.50 D·cm,a further increase in the fracture conductivity has a limited effect on shale gas production growth.The initial production is lower under pressure-controlled conditions than that under pressure-release.For extended pressure control durations,the cumulative production initially increases and then decreases.For a fracture conductivity of 0.10 D·cm,the increase in production output under controlled-pressure conditions is~35%.For representative deep shale gas wells(Southern Sichuan,China),if the pressure drop rate under controlled-pressure conditions is reduced from 0.19 to 0.04 MPa/d,the EUR increase for 5 years of pressure-controlled production is 41.0 million,with an increase percentage of~29%.展开更多
By conducting organic geochemical analysis of the samples taken from the drilled wells in Baiyun Sag of Pearl River Mouth Basin,China,the development characteristics of hydrocarbon source rocks in the sag are clarifie...By conducting organic geochemical analysis of the samples taken from the drilled wells in Baiyun Sag of Pearl River Mouth Basin,China,the development characteristics of hydrocarbon source rocks in the sag are clarified.Reconstruct the current geothermal field of the sag and restore the tectonic-thermal evolution process to predict the type,scale,and distribution of resources in Baiyun Sag through thermal pressure simulation experiments and numerical simulation.The Baiyun Sag is characterized by the development of Paleogene shallow lacustrine source rocks,which are deposited in a slightly oxidizing environment.The source rocks are mainly composed of terrestrial higher plants,with algae making a certain contribution,and are oil and gas source rocks.Current geothermal field of the sag was reconstructed,in which the range of geothermal gradients is(3.5–5.2)℃/100 m,showing an overall increasing trend from northwest to southeast,with significant differences in geothermal gradients across different sub-sags.Baiyun Sag has undergone two distinct periods of extensional process,the Eocene and Miocene,since the Cenozoic era.These two periods of heating and warming events have been identified,accelerating the maturation and evolution of source rocks.The main body of ancient basal heat flow value reached its highest at 13.82 Ma.The basin modelling results show that the maturity of source rocks is significantly higher in Baiyun main sub-sag than that in other sub-sags.The Eocene Wenchang Formation is currently in the stage of high maturity to over maturity,while the Eocene Enping Formation has reached the stage of maturity to high maturity.The rock thermal simulation experiment shows that the shallow lacustrine mudstone of the Wenchang Formation has a good potential of generating gas from kerogen cracking with high gas yield and long period of gas window.Shallow lacustrine mudstone of the Enping Formation has a good ability to generate light oil,and has ability to generate kerogen cracking gas in the late stage.The gas yield of shallow lacustrine mudstone of the Enping Formation is less than that of shallow lacustrine mudstone of the Wenchang Formation and the delta coal-bearing mudstone of the Enping Formation.The numerical simulation results indicate that the source rocks of Baiyun main sub-sag generate hydrocarbons earlier and have significantly higher hydrocarbon generation intensity than other sub-sags,with an average of about 1200×10^(4)t/km^(2).Oil and gas resources were mainly distributed in Baiyun main sub-sag and the main source rocks are distributed in the 3^(rd)and 4^(th)members of Wenchang Formation.Four favorable zones are selected for the division and evaluation of migration and aggregation units:No.(1)Panyu 30 nose-shaped structural belt,No.(3)Liuhua 29 nose-shaped uplift belt and Liwan 3 nose-shaped uplift belt,No.(2)gentle slope belt of Baiyun east sag,and No.(8)Baiyun 1 low-uplift.展开更多
Deep shale reservoirs(3500–4500 m)exhibit significantly different stress states than moderately deep shale reservoirs(2000–3500 m).As a result,the brittleness response mechanisms of deep shales are also different.It...Deep shale reservoirs(3500–4500 m)exhibit significantly different stress states than moderately deep shale reservoirs(2000–3500 m).As a result,the brittleness response mechanisms of deep shales are also different.It is urgent to investigate methods to evaluate the brittleness of deep shales to meet the increasingly urgent needs of deep shale gas development.In this paper,the quotient of Young’s modulus divided by Poisson’s ratio based on triaxial compression tests under in situ stress conditions is taken as SSBV(Static Standard Brittleness Value).A new and pragmatic technique is developed to determine the static brittleness index that considers elastic parameters,the mineral content,and the in situ stress conditions(BIEMS).The coefficient of determination between BIEMS and SSBV reaches 0.555 for experimental data and 0.805 for field data.This coefficient is higher than that of other brittleness indices when compared to SSBV.BIEMS can offer detailed insights into shale brittleness under various conditions,including different mineral compositions,depths,and stress states.This technique can provide a solid data-based foundation for the selection of‘sweet spots’for single-well engineering and the comparison of the brittleness of shale gas production layers in different areas.展开更多
The transientflow testing of ultra-deepwater gas wells is greatly impacted by the low temperatures of seawater encountered over extended distances.This leads to a redistribution of temperature within the wellbore,whic...The transientflow testing of ultra-deepwater gas wells is greatly impacted by the low temperatures of seawater encountered over extended distances.This leads to a redistribution of temperature within the wellbore,which in turn influences theflow behavior.To accurately predict such a temperature distribution,in this study a comprehensive model of theflowing temperature and pressurefields is developed.This model is based on principles offluid mechanics,heat transfer,mass conservation,and energy conservation and relies on the Runge-Kutta method for accurate integration in time of the resulting equations.The analysis includes the examination of the influence of various factors,such as gasflow production rate,thermal diffusivity of the formation,and thermal diffusivity of seawater,on the temperature and pressure profiles of the wellbore.The keyfindings can be summarized as follows:1.Higher production rates during testing lead to increasedflowing temperatures and decreased pressures within the wellbore.However,in the presence of a seawater thermocline,a crossover inflowing temperature is observed.2.An increase in wellbore pressure is associated with larger pipe diameters.3.Greater thermal diffusivity of the formation results in more rapid heat transfer from the wellbore to the formation,which causes lowerflowing temperatures within the wellbore.4.In an isothermal layer,higher thermal diffusivity of seawater leads to increased wellboreflowing temperatures.Conversely,in thermocline and mixed layer segments,lower temperatures are noted.5.Production test data from a representative deep-water gas well in the South China Sea,used to calculate the bottom-seafloor-wellhead temperature and pressurefields across three operating modes,indicate that the average error in temperature prediction is 2.18%,while the average error in pressure prediction is 5.26%,thereby confirming the reliability of the theoretical model.展开更多
Almost all sandstone reservoirs contain interlayers. The identification and characterization of these interlayers iscritical for minimizing the uncertainty associated with oilfield development and improving oil and ga...Almost all sandstone reservoirs contain interlayers. The identification and characterization of these interlayers iscritical for minimizing the uncertainty associated with oilfield development and improving oil and gas recovery.Identifying interlayers outside wells using identification methods based on logging data and machine learning isdifficult and seismic-based identification techniques are expensive. Herein, a numerical model based on seepageand well-testing theories is introduced to identify interlayers using transient pressure data. The proposed modelrelies on the open-source MATLAB Reservoir Simulation Toolbox. The effects of the interlayer thickness, position,and width on the pressure response are thoroughly investigated. A procedure for inverting interlayer parametersin the reservoir using the bottom-hole pressure is also proposed. This method uses only transient pressuredata during well testing and can effectively identify the interlayer distribution near the wellbore at an extremelylow cost. The reliability of the model is verified using effective oilfield examples.展开更多
Multistage multi-cluster hydraulic fracturing has enabled the economic exploitation of shale reservoirs,but the interpretation of hydraulic fracture parameters is challenging.The pressure signals after pump shutdown a...Multistage multi-cluster hydraulic fracturing has enabled the economic exploitation of shale reservoirs,but the interpretation of hydraulic fracture parameters is challenging.The pressure signals after pump shutdown are influenced by hydraulic fractures,which can reflect the geometric features of hydraulic fracture.The shutdown pressure can be used to interpret the hydraulic fracture parameters in a real-time and cost-effective manner.In this paper,a mathematical model for shutdown pressure evolution is developed considering the effects of wellbore friction,perforation friction and fluid loss in fractures.An efficient numerical simulation method is established by using the method of characteristics.Based on this method,the impacts of fracture half-length,fracture height,opened cluster and perforation number,and filtration coefficient on the evolution of shutdown pressure are analyzed.The results indicate that a larger fracture half-length may hasten the decay of shutdown pressure,while a larger fracture height can slow down the decay of shutdown pressure.A smaller number of opened clusters and perforations can significantly increase the perforation friction and decrease the overall level of shutdown pressure.A larger filtration coefficient may accelerate the fluid filtration in the fracture and hasten the drop of the shutdown pressure.The simulation method of shutdown pressure,as well as the analysis results,has important implications for the interpretation of hydraulic fracture parameters.展开更多
CO_(2)huff and puff experiments of different injection parameters,production parameters and soaking time were carried out on large-scale cubic and long columnar outcrop samples to analyze dynamic characteristics and i...CO_(2)huff and puff experiments of different injection parameters,production parameters and soaking time were carried out on large-scale cubic and long columnar outcrop samples to analyze dynamic characteristics and influencing factors of CO_(2)huff and puff and the contribution of sweeping mode to recovery.The experimental results show that the development process of CO_(2)huff and puff can be divided into four stages,namely,CO_(2)backflow,production of gas with some oil,high-speed oil production,and oil production rate decline stages.The production of gas with some oil stage is dominated by free gas displacement,and the high-speed oil production stage is dominated by dissolved gas displacement.CO_(2)injection volume and development speed are the major factors affecting the oil recovery.The larger the injected CO_(2)volume and the lower the development speed,the higher the oil recovery will be.The reasonable CO_(2)injection volume and development speed should be worked out according to oilfield demand and economic evaluation.There is a reasonable soaking time in CO_(2)huff and puff.Longer soaking time than the optimum time makes little contribution to oil recovery.In field applications,the stability of bottom hole pressure is important to judge whether the soaking time is sufficient during the huff period.The oil recovery of CO_(2)huff and puff mainly comes from the contribution of flow sweep and diffusion sweep,and diffusion sweep contributes more to the oil recovery when the soaking time is sufficient.展开更多
With the rapid development of shale gas exploration and development in China,casing deformation in shale gas horizontal wells happens frequently,which directly impacts the development efficiency and benefits of shale ...With the rapid development of shale gas exploration and development in China,casing deformation in shale gas horizontal wells happens frequently,which directly impacts the development efficiency and benefits of shale gas.In order to explore casing deformation prediction,prevention and treatment methods,this paper analyzes the geological and engineering causes of casing deformation in shale-gas horizontal wells through laboratory work,such as the casing resistance to internal pressure alternating test,the ground simulation test and systematical casing deformation characteristic analysis of MIT24 caliper logging,and the large-scale physical simulation test and numerical simulation of casing deformation.Then,combined with the generalized shear activity criterion,a new method for evaluating casing deformation risk points and some technical measures for preventing casing deformation were formulated.And the following research results were obtained.First,the deformation characteristics of 119 casing deformation points in 23 wells interpreted by MIT24 caliper logging are consistent with the mechanical behaviors of shear compression deformation test.Second,the large-scale physical simulation test shows that natural fault-fractures slip obviously under the state of strike-slip stress.Third,numerical simulation shows that the compression stress on casing increases with the increase of fault-fracture slip.When the fault-fracture slip is between 7.5 mm and 9.0 mm,the casing reaches the critical yield strength and begins to undergo plastic deformation.The“temporary fracture plugging+long segment and multi-cluster”and other technologies are field tested in 28 wells in Weiyuan area of southern Sichuan Basin.The casing deformation rate decreases from 54%(before this research)to 14.3%,and the segment loss rate decreases from 7.8%to 0,which reveals remarkable achievements in casing deformation treatment.In conclusion,the shear slip of fault and macro fractures(referred to as fault-fracture)is the main cause of casing deformation in shale gas horizontal wells,and some measures(e.g.“temporary fracture plugging+long segment and multi-cluster”,reducing fracturing scale and releasing wellbore pressure properly)shall be taken in advance to reduce the fault-fracture activity before the risk point of casing deformation is fractured,so as to reach the goal of casing deformation prevention.展开更多
The field data of shale fracturing demonstrate that the flowback performance of fracturing fluid is different from that of conventional reservoirs,where the flowback rate of shale fracturing fluid is lower than that o...The field data of shale fracturing demonstrate that the flowback performance of fracturing fluid is different from that of conventional reservoirs,where the flowback rate of shale fracturing fluid is lower than that of conventional reservoirs.At the early stage of flowback,there is no single-phase flow of the liquid phase in shale,but rather a gas-water two-phase flow,such that the single-phase flow model for tight oil and gas reservoirs is not applicable.In this study,pores and microfractures are extracted based on the experimental results of computed tomography(CT)scanning,and a spatial model of microfractures is established.Then,the influence of rough microfracture surfaces on the flow is corrected using the modified cubic law,which was modified by introducing the average deviation of the microfracture height as a roughness factor to consider the influence of microfracture surface roughness.The flow in the fracture network is simulated using the modified cubic law and the lattice Boltzmann method(LBM).The results obtained demonstrate that most of the fracturing fluid is retained in the shale microfractures,which explains the low fracturing fluid flowback rate in shale hydraulic fracturing.展开更多
The fi rst arrival waveform inversion(FAWI)has a strong nonlinearity due to the objective function using L2 parametrization.When the initial velocity is not accurate,the inversion can easily fall into local minima.In ...The fi rst arrival waveform inversion(FAWI)has a strong nonlinearity due to the objective function using L2 parametrization.When the initial velocity is not accurate,the inversion can easily fall into local minima.In the full waveform inversion method,adding a cross-correlation function to the objective function can eff ectively reduce the nonlinearity of the inversion process.In this paper,the nonlinearity of this process is reduced by introducing the correlation objective function into the FAWI and by deriving the corresponding gradient formula.We then combine the first-arrival wave travel-time tomography with the FAWI to form a set of inversion processes.This paper uses the limited memory Broyden-Fletcher-Goldfarb-Shanno(L-BFGS)algorithm to improve the computational effi ciency of inversion and solve the problem of the low effi ciency of the FAWI method.The overthrust model and fi eld data test show that the method used in this paper can eff ectively reduce the nonlinearity of inversion and improve the inversion calculation effi ciency at the same time.展开更多
In the Northern Jiangsu basin there are high pure CO2 gas pools, low condensed oil-containing CO2 gas pools, high condensed oil-containing CO2 gas pools and He-containing natural gas pools, with the δ13Cco2 (PDB) val...In the Northern Jiangsu basin there are high pure CO2 gas pools, low condensed oil-containing CO2 gas pools, high condensed oil-containing CO2 gas pools and He-containing natural gas pools, with the δ13Cco2 (PDB) values ranging from ?2.87%o to ?6.50%o, 3He/4He 3.71 × 10?6 to 6.42 × 10?6, R/Ra 2.64 to 4.5, 40Ar/36Ar 705 to 734, belonging to typical mantle source inorganic gas pools which are related to young magmatic activity. The gas layers occur in two major reservoir-caprock systems, the terrestrial Meso-Cenozoic clastic rock system and the marine Meso-Palaeozoic carbonate rock-clastic rock system. Controlled by the difference in the scale of traps in the two reservoir-caprock systems, large and medium-scale inorganic gas pools are formed in the marine Meso-Palaeozoic Group and only small ones are formed in the terrestrial Meso-Cenozoic strata. Inorganic gas pools in this basin are distributed along the two deep lithospheric faults on the west and south boundaries of the basin. Gas pools are developed at the intersected part of the ENE-trending faults that control the half graben and the E-W tenso-shear faults, mainly distributed near the Es1, Ny1 and Ny2-Q basalt eruption centres.展开更多
Multi-cluster perforation and multi-staged fracturing of horizontal well is one of the main technologies in volumetric fracturing stimulation of unconventional oil and gas reservoirs,but unconventional reservoirs in C...Multi-cluster perforation and multi-staged fracturing of horizontal well is one of the main technologies in volumetric fracturing stimulation of unconventional oil and gas reservoirs,but unconventional reservoirs in China are generally of strong heterogeneity,which causes different fracture initiation pressures in different positions of lateral,making it difficult to ensure the balanced fracture initiation and propagation between clusters in multi-cluster perforating.It is in urgent need to precisely evaluate the difference in rock strength in lateral and determine the well section with similar rock strength to deploy fractures,so as to reach the goal of balanced stimulation.Based on the drilling and logging data,this paper establishes an unsupervised clustering model of mechanical specific energy of bit at the bottomhole the lateral.Then,the influence of drill string friction,composite drilling and jet-assisted rock breaking on the mechanical specific energy is analyzed,and the distribution and clustering categories of bottomhole mechanical specific energy with decimeter spatial resolution are obtained.Finally,a fracture deployment optimization method for horizontal well volumetric fracturing aiming balanced stimulation is developed by comprehensively considering inter-fracture interference,casing collar position,plug position,and clustering result of bottomhole mechanical specific energy.The following results are obtained.First,compared with brittleness index,Poisson's ratioandstressdifference,perforation erosion area isina strongercorrelationwith themechanical specific energy,andthemechanical specific energy can effectively characterize the difference in the amount of proppant injected into the perforation clusters in the lateral,so it can be served as one of the important indicators for the selection of fracture deployment position.Second,the drilling and logging data cleaning and smoothing and the clustering number selection by the elbow method are the key steps to obtain the clustering results of bottomhole mechanical specific energy,which can tell the difference in the mechanical specific energy with decimeter-level resolution.Third,the interval with mechanical specific energy within 10%of the averagevalue in the section is selected for deploying perforation clusters,and the compiled computer algorithm can automatically determine the optimal position of fracturing section and cluster,so as to realize the differential design of stage spacing and cluster spacing.In conclusion,the research results can further improve the fractures deployment efficiency and balanced stimulation of volumetric fracturing in unconventional oil andgasreservoirs,and this technology is expected to provide ideas andnew methods forthe fracturedeployment optimization of horizontal well volumetric fracturing in unconventional oil and gas reservoirs.展开更多
The characteristics of a shale gas reservoir and the potential of a shale gas resource of Ordovician-Silurian age in the north of the central Yangtze area were determined. Core samples from three wells in the study ar...The characteristics of a shale gas reservoir and the potential of a shale gas resource of Ordovician-Silurian age in the north of the central Yangtze area were determined. Core samples from three wells in the study area were subjected to thin-section examination, scanning electron microscopy, nuclear magnetic resonance testing, X-ray diffraction mineral analysis, total organic carbon （TOC） testing, maturity testing, gas-bearing analysis, and gas component and isothermal adsorption experiments. A favorable segment of the gas shale reservoir was found in both the Wufeng Formation and the lower part of the Longmaxi Formation; these formations were formed from the late Katian to early Rhuddanian. The high-quality shale layers in wells J1, J2, and J3 featured thicknesses of 54.88 m, 48.49 m, and 52.00 m, respectively, and mainly comprised carbonaceous and siliceous shales. Clay and brittle minerals showed average contents of 37.5% and 62.5% （48.9% quartz）, respectively. The shale exhibited type Ⅱ1 kerogens with a vitrinite reflectance ranging from 1.94% to 3.51%. TOC contents of 0.22%-6.05% （average, 2.39%） were also observed. The reservoir spaces mainly included micropores and microfractures and were characterized by low porosity and permeability. Well J3 showed generally high gas contents, i.e., 1.12-3.16 m^3/t （average 2.15 m^3/t）, and its gas was primarily methane. The relatively thick black shale reservoir featured high TOC content, high organic material maturity, high brittle mineral content, high gas content, low porosity, and low permeability. Shale gas adsorption was positively correlated with TOC content and organic maturity, weakly positive correlated with quartz content, and weakly negatively correlated with clay content. Therefore, the Wufeng and Longmaxi formations in the north of the central Yangtze area have a good potential for shale gas exploration.展开更多
This study aims to determine the effects of nanoscale pores system characteristics on CH4 adsorption capacity in anthracite.A total of 24 coal samples from the southern Sichuan Basin,China,were examined systemically u...This study aims to determine the effects of nanoscale pores system characteristics on CH4 adsorption capacity in anthracite.A total of 24 coal samples from the southern Sichuan Basin,China,were examined systemically using coal maceral analysis,vitrinite reflectance tests, proximate analysis,ultimate analysis,low-temperature N2 adsorption-desorption experiments,nuclear magnetic resonance (NMR)analysis,and CH4 isotherm adsorption experiments.Results show that nano-pores are divided into four types on the basis of pore size ranges:super micropores (<4 nm),micropores (4-10 nm),mesopores (10-100 nm),and macropores (>100 nm).Super micropores,micropores,and mesopores make up the bulk of coal porosity,providing extremely large adsorption space with large intemal surface area.This leads us to the conclusion that the threshold of pore diameter between adsorption pores and seepage pores is 100 nm.The "ink bottle"pores have the largest CH4 adsorption capacity, followed by semi-opened pores,whereas opened pores have the smallest CH4 adsorption capacity which indicates that anthracite pores with more irregular shapes possess higher CH4 adsorption capacity.CH4 adsorption capacity increased with the increase in NMR porosity and the bound water saturation.Moreover,CH4 adsorption capacity is positively correlated with NMR permeability when NMR permeability is less than 8 ×10^-3 md.By contrast,the two factors are negatively correlated when NMR permeability is greater than 8 × 10^-3 md.展开更多
基金supported by the National Natural Science Foundation of China(Grant No.52404020 and Grant No.U1762216).
文摘Heterogeneity in carbonate formations due to discontinuities(e.g.,fractures and cavities)will bring about distinctive acid stimulation effects.However,the differences in fracturing behavior between homogeneous and heterogeneous carbonate formations remain unclear,complicating the optimization of acid fracturing strategies.In this paper,full-diameter carbonate rock samples with different degrees of discontinuity development are selected to investigate the fracturing behavior under different fluid types and injection schemes.Advanced techniques,including 3D CT scanning and 3D laser scanning,are employed to analyze fracture morphology and etching characteristics,respectively.Experimental results show that the coupled hydraulic-chemical effects play different roles in fracture induction between fracture-cavity developed and undeveloped carbonate rocks.Acid-fracturing stimulation consistently induces multiple types of complex fractures in fracture-cavity carbonate rocks,whereas it results in a single artificial fracture in less fracture-cavity carbonate rocks.Furthermore,localized etching patterns are prevalent in most fracture-cavity carbonate rocks,whereas homogeneous carbonate rocks exhibit regional or global etching characteristics.In both carbonate rocks,the stimulation effect of guar fluid is inferior to that of gelled acid but comparable to self-generating acid.Further findings are that alternating fracturing with guar and acid fluids in fracture-cavity carbonate rocks can sustain or even increase the injection pressure,facilitating the formation of new or depth-penetrating fractures.This phenomenon,however,is not observed in fracture-cavity undeveloped carbonate rocks.Potential interaction modes between induced fracture and natural fractures/cavities under different injection conditions are also identified.Finally,preferred fracturing schemes applicable to different carbonate formations are recommended based on the area,number and roughness of the induced fractures.
基金supported by the Chongqing Natural Science Foundation Innovation and Development Joint Fund(CSTB2023NSCQ-LZX0078)the Science and Technology Research Program of Chongqing Municipal Education Commission(KJQN202201519),which are gratefully acknowledged.
文摘Pressure control in deep shale gas horizontal wells can reduce the stress sensitivity of hydraulic fractures and improve the estimated ultimate recovery(EUR).In this study,a hydraulic fracture stress sensitivity model is proposed to characterize the effect of pressure drop rate on fracture permeability.Furthermore,a production prediction model is introduced accounting for a non-uniform hydraulic fracture conductivity distribution.The results reveal that increasing the fracture conductivity leads to a rapid daily production increase in the early stages.However,above 0.50 D·cm,a further increase in the fracture conductivity has a limited effect on shale gas production growth.The initial production is lower under pressure-controlled conditions than that under pressure-release.For extended pressure control durations,the cumulative production initially increases and then decreases.For a fracture conductivity of 0.10 D·cm,the increase in production output under controlled-pressure conditions is~35%.For representative deep shale gas wells(Southern Sichuan,China),if the pressure drop rate under controlled-pressure conditions is reduced from 0.19 to 0.04 MPa/d,the EUR increase for 5 years of pressure-controlled production is 41.0 million,with an increase percentage of~29%.
基金Supported by the National Oil and Gas Resource Evaluation Project for the 14th Five Year Plan of the Ministry of Natural Resources(QGYQZYPJ2022-3)China National Offshore Oil Corporation"14th Five Year Plan"Major Science and Technology Project(KJGG2022-0103-03)。
文摘By conducting organic geochemical analysis of the samples taken from the drilled wells in Baiyun Sag of Pearl River Mouth Basin,China,the development characteristics of hydrocarbon source rocks in the sag are clarified.Reconstruct the current geothermal field of the sag and restore the tectonic-thermal evolution process to predict the type,scale,and distribution of resources in Baiyun Sag through thermal pressure simulation experiments and numerical simulation.The Baiyun Sag is characterized by the development of Paleogene shallow lacustrine source rocks,which are deposited in a slightly oxidizing environment.The source rocks are mainly composed of terrestrial higher plants,with algae making a certain contribution,and are oil and gas source rocks.Current geothermal field of the sag was reconstructed,in which the range of geothermal gradients is(3.5–5.2)℃/100 m,showing an overall increasing trend from northwest to southeast,with significant differences in geothermal gradients across different sub-sags.Baiyun Sag has undergone two distinct periods of extensional process,the Eocene and Miocene,since the Cenozoic era.These two periods of heating and warming events have been identified,accelerating the maturation and evolution of source rocks.The main body of ancient basal heat flow value reached its highest at 13.82 Ma.The basin modelling results show that the maturity of source rocks is significantly higher in Baiyun main sub-sag than that in other sub-sags.The Eocene Wenchang Formation is currently in the stage of high maturity to over maturity,while the Eocene Enping Formation has reached the stage of maturity to high maturity.The rock thermal simulation experiment shows that the shallow lacustrine mudstone of the Wenchang Formation has a good potential of generating gas from kerogen cracking with high gas yield and long period of gas window.Shallow lacustrine mudstone of the Enping Formation has a good ability to generate light oil,and has ability to generate kerogen cracking gas in the late stage.The gas yield of shallow lacustrine mudstone of the Enping Formation is less than that of shallow lacustrine mudstone of the Wenchang Formation and the delta coal-bearing mudstone of the Enping Formation.The numerical simulation results indicate that the source rocks of Baiyun main sub-sag generate hydrocarbons earlier and have significantly higher hydrocarbon generation intensity than other sub-sags,with an average of about 1200×10^(4)t/km^(2).Oil and gas resources were mainly distributed in Baiyun main sub-sag and the main source rocks are distributed in the 3^(rd)and 4^(th)members of Wenchang Formation.Four favorable zones are selected for the division and evaluation of migration and aggregation units:No.(1)Panyu 30 nose-shaped structural belt,No.(3)Liuhua 29 nose-shaped uplift belt and Liwan 3 nose-shaped uplift belt,No.(2)gentle slope belt of Baiyun east sag,and No.(8)Baiyun 1 low-uplift.
文摘Deep shale reservoirs(3500–4500 m)exhibit significantly different stress states than moderately deep shale reservoirs(2000–3500 m).As a result,the brittleness response mechanisms of deep shales are also different.It is urgent to investigate methods to evaluate the brittleness of deep shales to meet the increasingly urgent needs of deep shale gas development.In this paper,the quotient of Young’s modulus divided by Poisson’s ratio based on triaxial compression tests under in situ stress conditions is taken as SSBV(Static Standard Brittleness Value).A new and pragmatic technique is developed to determine the static brittleness index that considers elastic parameters,the mineral content,and the in situ stress conditions(BIEMS).The coefficient of determination between BIEMS and SSBV reaches 0.555 for experimental data and 0.805 for field data.This coefficient is higher than that of other brittleness indices when compared to SSBV.BIEMS can offer detailed insights into shale brittleness under various conditions,including different mineral compositions,depths,and stress states.This technique can provide a solid data-based foundation for the selection of‘sweet spots’for single-well engineering and the comparison of the brittleness of shale gas production layers in different areas.
文摘The transientflow testing of ultra-deepwater gas wells is greatly impacted by the low temperatures of seawater encountered over extended distances.This leads to a redistribution of temperature within the wellbore,which in turn influences theflow behavior.To accurately predict such a temperature distribution,in this study a comprehensive model of theflowing temperature and pressurefields is developed.This model is based on principles offluid mechanics,heat transfer,mass conservation,and energy conservation and relies on the Runge-Kutta method for accurate integration in time of the resulting equations.The analysis includes the examination of the influence of various factors,such as gasflow production rate,thermal diffusivity of the formation,and thermal diffusivity of seawater,on the temperature and pressure profiles of the wellbore.The keyfindings can be summarized as follows:1.Higher production rates during testing lead to increasedflowing temperatures and decreased pressures within the wellbore.However,in the presence of a seawater thermocline,a crossover inflowing temperature is observed.2.An increase in wellbore pressure is associated with larger pipe diameters.3.Greater thermal diffusivity of the formation results in more rapid heat transfer from the wellbore to the formation,which causes lowerflowing temperatures within the wellbore.4.In an isothermal layer,higher thermal diffusivity of seawater leads to increased wellboreflowing temperatures.Conversely,in thermocline and mixed layer segments,lower temperatures are noted.5.Production test data from a representative deep-water gas well in the South China Sea,used to calculate the bottom-seafloor-wellhead temperature and pressurefields across three operating modes,indicate that the average error in temperature prediction is 2.18%,while the average error in pressure prediction is 5.26%,thereby confirming the reliability of the theoretical model.
文摘Almost all sandstone reservoirs contain interlayers. The identification and characterization of these interlayers iscritical for minimizing the uncertainty associated with oilfield development and improving oil and gas recovery.Identifying interlayers outside wells using identification methods based on logging data and machine learning isdifficult and seismic-based identification techniques are expensive. Herein, a numerical model based on seepageand well-testing theories is introduced to identify interlayers using transient pressure data. The proposed modelrelies on the open-source MATLAB Reservoir Simulation Toolbox. The effects of the interlayer thickness, position,and width on the pressure response are thoroughly investigated. A procedure for inverting interlayer parametersin the reservoir using the bottom-hole pressure is also proposed. This method uses only transient pressuredata during well testing and can effectively identify the interlayer distribution near the wellbore at an extremelylow cost. The reliability of the model is verified using effective oilfield examples.
基金The work is supported by the Sub-Project of“Research on Key Technologies and Equipment of Reservoir Stimulation”of China National Petroleum Corporation Post–14th Five-Year Plan Forward-Looking Major Science and Technology Project“Research on New Technology of Monitoring and Diagnosis of Horizontal Well Hydraulic Fracture Network Distribution Pattern”(2021DJ4502).
文摘Multistage multi-cluster hydraulic fracturing has enabled the economic exploitation of shale reservoirs,but the interpretation of hydraulic fracture parameters is challenging.The pressure signals after pump shutdown are influenced by hydraulic fractures,which can reflect the geometric features of hydraulic fracture.The shutdown pressure can be used to interpret the hydraulic fracture parameters in a real-time and cost-effective manner.In this paper,a mathematical model for shutdown pressure evolution is developed considering the effects of wellbore friction,perforation friction and fluid loss in fractures.An efficient numerical simulation method is established by using the method of characteristics.Based on this method,the impacts of fracture half-length,fracture height,opened cluster and perforation number,and filtration coefficient on the evolution of shutdown pressure are analyzed.The results indicate that a larger fracture half-length may hasten the decay of shutdown pressure,while a larger fracture height can slow down the decay of shutdown pressure.A smaller number of opened clusters and perforations can significantly increase the perforation friction and decrease the overall level of shutdown pressure.A larger filtration coefficient may accelerate the fluid filtration in the fracture and hasten the drop of the shutdown pressure.The simulation method of shutdown pressure,as well as the analysis results,has important implications for the interpretation of hydraulic fracture parameters.
文摘CO_(2)huff and puff experiments of different injection parameters,production parameters and soaking time were carried out on large-scale cubic and long columnar outcrop samples to analyze dynamic characteristics and influencing factors of CO_(2)huff and puff and the contribution of sweeping mode to recovery.The experimental results show that the development process of CO_(2)huff and puff can be divided into four stages,namely,CO_(2)backflow,production of gas with some oil,high-speed oil production,and oil production rate decline stages.The production of gas with some oil stage is dominated by free gas displacement,and the high-speed oil production stage is dominated by dissolved gas displacement.CO_(2)injection volume and development speed are the major factors affecting the oil recovery.The larger the injected CO_(2)volume and the lower the development speed,the higher the oil recovery will be.The reasonable CO_(2)injection volume and development speed should be worked out according to oilfield demand and economic evaluation.There is a reasonable soaking time in CO_(2)huff and puff.Longer soaking time than the optimum time makes little contribution to oil recovery.In field applications,the stability of bottom hole pressure is important to judge whether the soaking time is sufficient during the huff period.The oil recovery of CO_(2)huff and puff mainly comes from the contribution of flow sweep and diffusion sweep,and diffusion sweep contributes more to the oil recovery when the soaking time is sufficient.
基金supported by the Scientific Research and Technology Development Project of CNPC“Research and field test of key technologies for effective exploitation of deep shale gas”(No.2019F-31JT).
文摘With the rapid development of shale gas exploration and development in China,casing deformation in shale gas horizontal wells happens frequently,which directly impacts the development efficiency and benefits of shale gas.In order to explore casing deformation prediction,prevention and treatment methods,this paper analyzes the geological and engineering causes of casing deformation in shale-gas horizontal wells through laboratory work,such as the casing resistance to internal pressure alternating test,the ground simulation test and systematical casing deformation characteristic analysis of MIT24 caliper logging,and the large-scale physical simulation test and numerical simulation of casing deformation.Then,combined with the generalized shear activity criterion,a new method for evaluating casing deformation risk points and some technical measures for preventing casing deformation were formulated.And the following research results were obtained.First,the deformation characteristics of 119 casing deformation points in 23 wells interpreted by MIT24 caliper logging are consistent with the mechanical behaviors of shear compression deformation test.Second,the large-scale physical simulation test shows that natural fault-fractures slip obviously under the state of strike-slip stress.Third,numerical simulation shows that the compression stress on casing increases with the increase of fault-fracture slip.When the fault-fracture slip is between 7.5 mm and 9.0 mm,the casing reaches the critical yield strength and begins to undergo plastic deformation.The“temporary fracture plugging+long segment and multi-cluster”and other technologies are field tested in 28 wells in Weiyuan area of southern Sichuan Basin.The casing deformation rate decreases from 54%(before this research)to 14.3%,and the segment loss rate decreases from 7.8%to 0,which reveals remarkable achievements in casing deformation treatment.In conclusion,the shear slip of fault and macro fractures(referred to as fault-fracture)is the main cause of casing deformation in shale gas horizontal wells,and some measures(e.g.“temporary fracture plugging+long segment and multi-cluster”,reducing fracturing scale and releasing wellbore pressure properly)shall be taken in advance to reduce the fault-fracture activity before the risk point of casing deformation is fractured,so as to reach the goal of casing deformation prevention.
基金supported by the National Natural Science Foundation of China(Grant No.52022087).
文摘The field data of shale fracturing demonstrate that the flowback performance of fracturing fluid is different from that of conventional reservoirs,where the flowback rate of shale fracturing fluid is lower than that of conventional reservoirs.At the early stage of flowback,there is no single-phase flow of the liquid phase in shale,but rather a gas-water two-phase flow,such that the single-phase flow model for tight oil and gas reservoirs is not applicable.In this study,pores and microfractures are extracted based on the experimental results of computed tomography(CT)scanning,and a spatial model of microfractures is established.Then,the influence of rough microfracture surfaces on the flow is corrected using the modified cubic law,which was modified by introducing the average deviation of the microfracture height as a roughness factor to consider the influence of microfracture surface roughness.The flow in the fracture network is simulated using the modified cubic law and the lattice Boltzmann method(LBM).The results obtained demonstrate that most of the fracturing fluid is retained in the shale microfractures,which explains the low fracturing fluid flowback rate in shale hydraulic fracturing.
基金supported by the Major Scientific and Technological Project of PetroChina (ZD2019-183-003)Project of National Natural Science Foundation of China (42074133)+1 种基金the Fundamental Research Funds for the Central Universities (19CX02056A)Project of State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development (33550000-21-FW0399-0009)
文摘The fi rst arrival waveform inversion(FAWI)has a strong nonlinearity due to the objective function using L2 parametrization.When the initial velocity is not accurate,the inversion can easily fall into local minima.In the full waveform inversion method,adding a cross-correlation function to the objective function can eff ectively reduce the nonlinearity of the inversion process.In this paper,the nonlinearity of this process is reduced by introducing the correlation objective function into the FAWI and by deriving the corresponding gradient formula.We then combine the first-arrival wave travel-time tomography with the FAWI to form a set of inversion processes.This paper uses the limited memory Broyden-Fletcher-Goldfarb-Shanno(L-BFGS)algorithm to improve the computational effi ciency of inversion and solve the problem of the low effi ciency of the FAWI method.The overthrust model and fi eld data test show that the method used in this paper can eff ectively reduce the nonlinearity of inversion and improve the inversion calculation effi ciency at the same time.
文摘In the Northern Jiangsu basin there are high pure CO2 gas pools, low condensed oil-containing CO2 gas pools, high condensed oil-containing CO2 gas pools and He-containing natural gas pools, with the δ13Cco2 (PDB) values ranging from ?2.87%o to ?6.50%o, 3He/4He 3.71 × 10?6 to 6.42 × 10?6, R/Ra 2.64 to 4.5, 40Ar/36Ar 705 to 734, belonging to typical mantle source inorganic gas pools which are related to young magmatic activity. The gas layers occur in two major reservoir-caprock systems, the terrestrial Meso-Cenozoic clastic rock system and the marine Meso-Palaeozoic carbonate rock-clastic rock system. Controlled by the difference in the scale of traps in the two reservoir-caprock systems, large and medium-scale inorganic gas pools are formed in the marine Meso-Palaeozoic Group and only small ones are formed in the terrestrial Meso-Cenozoic strata. Inorganic gas pools in this basin are distributed along the two deep lithospheric faults on the west and south boundaries of the basin. Gas pools are developed at the intersected part of the ENE-trending faults that control the half graben and the E-W tenso-shear faults, mainly distributed near the Es1, Ny1 and Ny2-Q basalt eruption centres.
基金supported by the Science Fund for Excellent Youth of the National Natural Science Foundation of China"Well hydrodynamics and engineering"(No.52122401).
文摘Multi-cluster perforation and multi-staged fracturing of horizontal well is one of the main technologies in volumetric fracturing stimulation of unconventional oil and gas reservoirs,but unconventional reservoirs in China are generally of strong heterogeneity,which causes different fracture initiation pressures in different positions of lateral,making it difficult to ensure the balanced fracture initiation and propagation between clusters in multi-cluster perforating.It is in urgent need to precisely evaluate the difference in rock strength in lateral and determine the well section with similar rock strength to deploy fractures,so as to reach the goal of balanced stimulation.Based on the drilling and logging data,this paper establishes an unsupervised clustering model of mechanical specific energy of bit at the bottomhole the lateral.Then,the influence of drill string friction,composite drilling and jet-assisted rock breaking on the mechanical specific energy is analyzed,and the distribution and clustering categories of bottomhole mechanical specific energy with decimeter spatial resolution are obtained.Finally,a fracture deployment optimization method for horizontal well volumetric fracturing aiming balanced stimulation is developed by comprehensively considering inter-fracture interference,casing collar position,plug position,and clustering result of bottomhole mechanical specific energy.The following results are obtained.First,compared with brittleness index,Poisson's ratioandstressdifference,perforation erosion area isina strongercorrelationwith themechanical specific energy,andthemechanical specific energy can effectively characterize the difference in the amount of proppant injected into the perforation clusters in the lateral,so it can be served as one of the important indicators for the selection of fracture deployment position.Second,the drilling and logging data cleaning and smoothing and the clustering number selection by the elbow method are the key steps to obtain the clustering results of bottomhole mechanical specific energy,which can tell the difference in the mechanical specific energy with decimeter-level resolution.Third,the interval with mechanical specific energy within 10%of the averagevalue in the section is selected for deploying perforation clusters,and the compiled computer algorithm can automatically determine the optimal position of fracturing section and cluster,so as to realize the differential design of stage spacing and cluster spacing.In conclusion,the research results can further improve the fractures deployment efficiency and balanced stimulation of volumetric fracturing in unconventional oil andgasreservoirs,and this technology is expected to provide ideas andnew methods forthe fracturedeployment optimization of horizontal well volumetric fracturing in unconventional oil and gas reservoirs.
基金Acknowledgements This study was supported by the National Natural Science Foundation of China （Grant No. 41302123）, the Doctoral Program of Higher Education （Specialized Research Fund） of China （Grant No. 20125121130001）, and the Science Foundation of Education Department of Sichuan Province （Grant No. 13ZB0190）.
文摘The characteristics of a shale gas reservoir and the potential of a shale gas resource of Ordovician-Silurian age in the north of the central Yangtze area were determined. Core samples from three wells in the study area were subjected to thin-section examination, scanning electron microscopy, nuclear magnetic resonance testing, X-ray diffraction mineral analysis, total organic carbon （TOC） testing, maturity testing, gas-bearing analysis, and gas component and isothermal adsorption experiments. A favorable segment of the gas shale reservoir was found in both the Wufeng Formation and the lower part of the Longmaxi Formation; these formations were formed from the late Katian to early Rhuddanian. The high-quality shale layers in wells J1, J2, and J3 featured thicknesses of 54.88 m, 48.49 m, and 52.00 m, respectively, and mainly comprised carbonaceous and siliceous shales. Clay and brittle minerals showed average contents of 37.5% and 62.5% （48.9% quartz）, respectively. The shale exhibited type Ⅱ1 kerogens with a vitrinite reflectance ranging from 1.94% to 3.51%. TOC contents of 0.22%-6.05% （average, 2.39%） were also observed. The reservoir spaces mainly included micropores and microfractures and were characterized by low porosity and permeability. Well J3 showed generally high gas contents, i.e., 1.12-3.16 m^3/t （average 2.15 m^3/t）, and its gas was primarily methane. The relatively thick black shale reservoir featured high TOC content, high organic material maturity, high brittle mineral content, high gas content, low porosity, and low permeability. Shale gas adsorption was positively correlated with TOC content and organic maturity, weakly positive correlated with quartz content, and weakly negatively correlated with clay content. Therefore, the Wufeng and Longmaxi formations in the north of the central Yangtze area have a good potential for shale gas exploration.
基金This research was funded by the Open Foundation of Key Laboratory of Tectonics and Petroleum Resources (China University of Geosciences)(No.TPR-2016-04)the Open Foundation of Shandong Provincial Key Laboratory of Depositional Mineralization & Sedimentary Mineral,(Shandong University of Science and Technology)(No. DMSM2017031)+3 种基金the Youth Science and Technology Innovation Fund Project (Xi'an Shiyou University)(No.290088259)the National Science and Technology Major Project (No.2017ZX05039001-002)the National Natural Science Foundation of China (Grant Nos.41702127 and 41772150)the Scientific Research Program Funded by Shaanxi Provincial Education Department (No.17JK0617).
文摘This study aims to determine the effects of nanoscale pores system characteristics on CH4 adsorption capacity in anthracite.A total of 24 coal samples from the southern Sichuan Basin,China,were examined systemically using coal maceral analysis,vitrinite reflectance tests, proximate analysis,ultimate analysis,low-temperature N2 adsorption-desorption experiments,nuclear magnetic resonance (NMR)analysis,and CH4 isotherm adsorption experiments.Results show that nano-pores are divided into four types on the basis of pore size ranges:super micropores (<4 nm),micropores (4-10 nm),mesopores (10-100 nm),and macropores (>100 nm).Super micropores,micropores,and mesopores make up the bulk of coal porosity,providing extremely large adsorption space with large intemal surface area.This leads us to the conclusion that the threshold of pore diameter between adsorption pores and seepage pores is 100 nm.The "ink bottle"pores have the largest CH4 adsorption capacity, followed by semi-opened pores,whereas opened pores have the smallest CH4 adsorption capacity which indicates that anthracite pores with more irregular shapes possess higher CH4 adsorption capacity.CH4 adsorption capacity increased with the increase in NMR porosity and the bound water saturation.Moreover,CH4 adsorption capacity is positively correlated with NMR permeability when NMR permeability is less than 8 ×10^-3 md.By contrast,the two factors are negatively correlated when NMR permeability is greater than 8 × 10^-3 md.
