There are abundant marine shale gas resources in the Sichuan Basin.After almost one decade of exploration and development,three national shale gas demonstration areas have been built in the Sichuan Basin and its perip...There are abundant marine shale gas resources in the Sichuan Basin.After almost one decade of exploration and development,three national shale gas demonstration areas have been built in the Sichuan Basin and its periphery,and large-scale commercial development of middle and deep(above 3500 m in depth)shale gas has been successfully achieved.The volume of deep shale gas resources(3500e4500 m deep)of the upper Ordovician Wufeng Formation-lower Silurian Longmaxi Formation in the southern Sichuan Basin is 6.61012 m3,with huge exploration and exploitation potential,so it is an important area for large-scale shale gas production increase in China during the 14th Five-year Plan.Deep shale gas in the southern Sichuan Basin is influenced by complex geological engineering conditions,such as great burial depth,high temperature and pressure,and large stress and stress difference,and its high-quality development faces many challenges.After systematically summarizing the new progresses and achievements in deep shale gas exploration and development in the southern Sichuan Basin,this paper analyzes the difficulties and challenges in deep shale gas exploration and development and puts forward the next research directions.And the following research results are obtained.First,based on early practical exploration and independent innovation,key shale gas exploration and development technologies with good area selection,good well deployment,good well drilling,good well fracturing and good well management as the core are formed,and the cultivation mode of high production well is established,which supports the large-scale benefit development of deep shale gas in the southern Sichuan Basin.Second,systematical analysis indicates that the exploration and development of deep shale gas still faces a series of challenges in such three major fields as basic theory,key technology and management mode.Third,in the face of challenges,it is necessary to deepen basic theory research related to exploration and development,continuously improve key main technologies and constantly innovate mechanisms,systems and management modes.In conclusion,after years of continuous researches and pilot tests,a series of main exploration and development technologies suitable for the working conditions of deep shale gas in the southern Sichuan Basin have been basically formed,the first deep shale gas reserves of trillion cubic meters has been submitted,and the first deep shale gas production increase block of ten billion cubic meters has been selected.Thus,great progresses have been made in the exploration and development of deep shale gas,which confirms the confidence and determination in exploring and developing deep shale gas and is of great guiding significance to the rapid development of shale gas industry in China.展开更多
Benthic bivalves,the most widely distributed mollusks since the Mesozoic era,often inhabited environments where their fossilized remains are found adjacent to or intermingled with organic-rich shale.Recent Jurassic sh...Benthic bivalves,the most widely distributed mollusks since the Mesozoic era,often inhabited environments where their fossilized remains are found adjacent to or intermingled with organic-rich shale.Recent Jurassic shale oil exploration in the Sichuan Basin has revealed that bioclastic layers,composed of abundant fossil bivalves and closely associated with shales and,exhibit significant hydrocarbon potentials.However,the microscopic structures of these bivalve fossils and their role in hydrocarbon storage and migration remain poorly understood.In this study,we characterized the microporosity of bivalve shells within the Middle-Lower Jurassic bioclastic shale in the northeastern Sichuan Basin using a combination of 2D imaging(thin section,SEM),3D reconstruction(FIB-SEM),and permeability simulation.The micropores within the shell fossils range from 100 to 1000 nm in radius and are uniformly distributed in a grid-like pattern within the shell interior,where they host liquid hydrocarbons.The bioclastic carbonate layers exhibit an overall porosity of approximately 0.8%.Comparative analysis with extant bivalve shells suggests that these micropores represent residual pores from the nacreous brick wall structure.Due to the regular orientation of the shells and their microporous nacres,permeability coefficients along the long bivalve fossil axes are three to five times higher than those along the short axes.These residual micropores within the bioclastic fossil shells have a positive influence on both the storage and migration of shale oil and gas,making bioclastic fossil-bearing shalespromising sweet spots for shale oil and gas exploration in similar sedimentary environments.展开更多
This paper introduces a novel approach combining radial borehole fracturing with Water-Alternating-Gas(WAG)injection,enabling simultaneous WAG injection and shale oil production in a single vertical well.A numerical r...This paper introduces a novel approach combining radial borehole fracturing with Water-Alternating-Gas(WAG)injection,enabling simultaneous WAG injection and shale oil production in a single vertical well.A numerical reservoir model incorporating the modified exponential non-Darcy law,stress sensitivity,and diffusion is established.The spatial distribution of permeability reduction shows that stress sensitivity enhances the non-Darcy effect,with apparent permeability decreasing to 0-92.1%of the initial value,highlighting the importance of maintaining reservoir pressure.Continuous CO_(2) flooding leads to early gas breakthrough,while continuous water flooding has less displacement efficiency.A 30%water-to-gas injection time ratio improves oil production and delays gas breakthrough compared to continuous CO_(2) injection.Optimal conditions for effective recovery are identified as an initial production period of 100 d and a well vertical spacing of 30 m.This study compares the production capacity of WAG operations under radial borehole fracturing and horizontal well fracturing.When the number of wells is two for both cases,the production capacity of radial borehole fracturing is comparable to that of five-stage horizontal well fracturing,indicating that radial borehole fracturing can serve as an alternative or supplement to horizontal well fracturing when the reservoir volume is limited.This study offers a new method and theoretical basis for the efficient development of shale oil.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
Organic-rich shale is a significant potential source of oil and gas that requires development through in situ conversion technology.However,the evolution patterns of the internal three-dimensional(3D)pore structure an...Organic-rich shale is a significant potential source of oil and gas that requires development through in situ conversion technology.However,the evolution patterns of the internal three-dimensional(3D)pore structure and kerogen distribution at high temperatures are not well understood,making it difficult to microscopically explain the evolution of the flow conductivity in organic-rich shale at high temperatures.This study utilizes high-resolution X-ray computed tomography(micro-nano CT)to obtain the distribution of pores,kerogen,and inorganic matter at different temperatures.Combined with the pyrolysis results for the rock,the evolution of the pore structure at various temperatures is quantitatively analyzed.Based on three-phase segmentation technology,a model of kerogen distribution in organicrich shale is established by dividing the kerogen into clustered kerogen and dispersed kerogen stored in the inorganic matter and the pores into inorganic pores and organic pores within the kerogen skeleton.The results show that the inorganic pores in organic-rich shale evolve through three stages as the temperature increases:kerogen pyrolysis(200-400℃),clay mineral decomposition(400-600℃),and carbonate mineral decomposition(600-800℃).The inorganic pores porosity sequentially increases from 3%to 11.4%,13.1%,and 15.4%,and the roughness and connectivity of the inorganic pores gradually increase during this process.When the pyrolysis temperature reaches 400℃,the volume of clustered kerogen decreases from 25%to 12.5%.During this process,the relative density of kerogen decreases from9.5 g/cm^(3) in its original state to 5.4 g/cm^(3),while the kerogen skeleton density increases from 1.15 g/cm^(3) in its original state to 1.54 g/cm^(3).Correspondingly,7%-8%of organic pores develop within the clustered kerogen,accounting for approximately 50%of the volume of clustered kerogen.In addition,approximately 30%of the kerogen in organic-rich shale exists in the form of dispersed kerogen within inorganic matter,and its variation trend is similar to that of clustered kerogen,rapidly decreasing from 200 to 400℃ and stabilizing above 400℃.The results of this study provide an essential microscopic theoretical basis for the industrial development of organic-rich shale resources.展开更多
Measuring gas content is an essential step in estimating the commerciality of gas reserves. In this study,eight shale core samples from the Mouye-1 well were measured using a homemade patented gas desorption apparatus...Measuring gas content is an essential step in estimating the commerciality of gas reserves. In this study,eight shale core samples from the Mouye-1 well were measured using a homemade patented gas desorption apparatus to determine their gas contents. Due to the air contamination that is introduced into the desorption canister, a mathematical method was devised to correct the gas quantity and quality.Compared to the chemical compositions of desorbed gas, the chemical compositions of residual gas are somewhat different. In residual gas, carbon dioxide and nitrogen record a slight increase, and propane is first observed. This phenomenon may be related to the exposure time during the transportation of shale samples from the drilling site to the laboratory, as well as the differences in the mass, size and adsorptivity of different gas molecules. In addition to a series of conventional methods, including the USBM direct method and the Amoco Curve Fit(ACF) method, which were used here for lost gas content estimation, a Modified Curve Fit(MCF) method, based on the 'bidisperse' diffusion model, was established to estimate lost gas content. By fitting the ACF and MCF models to gas desorption data, we determined that the MCF method could reasonably describe the gas desorption data over the entire time period, whereas the ACF method failed. The failure of the ACF method to describe the gas desorption process may be related to its restrictive assumption of a single pore size within shale samples. In comparison to the indirect method, this study demonstrates that none of the three methods studied in this investigation(USBM, ACF and MCF) could individually estimate the lost gas contents of all shale samples and that the proportion of free gas relative to total gas has a significant effect on the estimation accuracy of the selected method. When the ratio of free gas to total gas is lower than 45%, the USBM method is the best for estimating the lost gas content, whereas when the ratio ranges from 45% to 75% or is more than 75%, the ACF and MCF methods, are the best options respectively.展开更多
In contrast to conventional gas-bearing rocks, gas shale has extremely low permeability due to its nano- scale pore networks. Organic matter which is dispersed in the shale matrix makes gas flow characteristics more c...In contrast to conventional gas-bearing rocks, gas shale has extremely low permeability due to its nano- scale pore networks. Organic matter which is dispersed in the shale matrix makes gas flow characteristics more complex. The traditional Darcy＇s law is unable to estimate matrix permeability due to the particular flow mechanisms of shale gas. Transport mechanisms and influence factors are studied to describe gas transport in extremely tight shale. Then Lattice Boltzmann simulation is used to establish a way to estimate the matrix permeability numerically. The results show that net desorption, diffu- sion, and slip flow are very sensitive to the pore scale. Pore pressure also plays an important role in mass fluxes of gas. Temperature variations only cause small changes in mass fluxes. The Lattice Boltzmann method can be used to study the flow field in the micropore spaces and then provides numerical solutions even in complex pore structure models. Understanding the transport characteristics and establishing a way to estimate potential gas flow is very important to guide shale gas t＇eserve estimation and recovery schemes.展开更多
Mechanical heterogeneity is a major characteristic of the organic-rich shale.The relation between mechanical heterogeneity and formation in-situ stress has been seldomly addressed but important to understand hydraulic...Mechanical heterogeneity is a major characteristic of the organic-rich shale.The relation between mechanical heterogeneity and formation in-situ stress has been seldomly addressed but important to understand hydraulic fracture propagation,wellbore stability,and hydrocarbon flow.In this paper,the grid nanoindentation technique was used to characterize the heterogeneity of the mechanical properties of Longmaxi organic-rich shales from various burial depths and in-situ stress.The measured elastic modulus and hardness of each sample are deconvolved into three phases including soft phase,medium stiff phase and stiff phase according to mineral category.As the burial depth and corresponding in-situ stress increase,the overall elastic modulus and hardness of the sample enhance.Simultaneously,the percentage of soft minerals decreases,and the probability distribution tends to concentrate through 95%confidence interval evaluation which demonstrates weakened heterogeneity.Furthermore,SEM images provide evidence that extended cracking,initiated cracking,crushing and ductile deforming always occur around indentation imprints.This confirms that even under deep buried depth and high in-situ stress,brittle fracture and ductile deformation can exist synchronously.This paper demonstrates the influence of in-situ stress on the heterogeneity of shale micromechanics.展开更多
Deep shale gas exploration and production in Fuling(Sichuan Basin,SW China)are confronted with hydraulic fracturing challenges owing to high stress,high fracture pressure,low pump rate and proppant concentration,as we...Deep shale gas exploration and production in Fuling(Sichuan Basin,SW China)are confronted with hydraulic fracturing challenges owing to high stress,high fracture pressure,low pump rate and proppant concentration,as well as high closing pressure in deep strata.This study focused on the mechanical properties of shale core samples from Fuling through high-temperature triaxial rock mechanical tests and in-situ stress tests based on the Kessel effect of acoustic emission.Their mechanical property var-iations with depth were delineated using brittleness index calculated via simulating different depths and different confining pressures for the samples.The results showed that several parameters of deep shale reservoirs,i.e.brittleness index,fracture density,performance of self-propping,and flow conductivity,are lower than that of shale reservoirs with moderate burial depth.Thus,the current operating pressure in deep shale reservoir stimulation should be taken full advantage of,rather than channeling the focus on the propagation of fracture length.The objective is to increase the complexity of the near-hole fracture network for enhancing self-propping and flow conductivity of the fractures.This can be achieved by reducing the number of perforation clusters and cluster spacing,adopting variable-rate fracturing,decreasing proppant size,increasing sand volume,and optimizing the fracturing parameters.A field application showed that,compared with the neighboring wells,the test well had larger drainage area,doubling the gas yield.展开更多
The main area of the Jiaoshiba anticline of the Fuling shale gas field was taken as the research object,laboratory rock mechanical experiments and direct shear experiments were conducted to clarify the mechanical anis...The main area of the Jiaoshiba anticline of the Fuling shale gas field was taken as the research object,laboratory rock mechanical experiments and direct shear experiments were conducted to clarify the mechanical anisotropy characteristics and parameters of rock samples with rich beddings.Based on the experimental results,a 3D fracture propagation model of the target reservoir taking mechanical anisotropy,weak bedding plane and vertical stress difference into account was established by the discrete element method to analyze distribution patterns of hydraulic fractures under different bedding densities,mechanical properties,and fracturing engineering parameters(including perforation clusters,injection rates and fracturing fluid viscosity).The research results show that considering the influence of the weak bedding plane and longitudinal stress difference,the interlayer stress difference 3–4 MPa in the study area can control the fracture height within the zone of stress barrier,and the fracture height is less than 40 m.If the influence of the weak bedding plane is not considered,the simulation result of fracture height is obviously higher.Although the opening of high-density bedding fractures increases the complexity of hydraulic fractures,it significantly limited the propagation of fracture height.By reducing the number of clusters,increasing the injection rate,and increasing the volume and proportion of high-viscosity fracturing fluid in the pad stage,the restriction on fracture height due to the bedding plane and vertical stress difference can be reduced,and the longitudinal propagation of fractures can be promoted.The fracture propagation model was used to simulate one stage of Well A in Fuling shale gas field,and the simulation results were consistent with the micro-seismic monitoring results.展开更多
During the past several years, natural gas production from shale gas is increased and has adsorbed much attention worldwide. The reason behind this is because of advances gained in shale gas recovery techniques from t...During the past several years, natural gas production from shale gas is increased and has adsorbed much attention worldwide. The reason behind this is because of advances gained in shale gas recovery techniques from this ultra-low permeability/porosity rock. These techniques are considered the horizontal drilling of the length of 3000 to 5000 ft long and conducting multi-stage hydraulic fracturing along the horizontal portion of the wells. The successful application of above has also driven down the gas prices worldwide and also culminated the security of gas supply for the upcoming decades. This paper is a technical literature review of shale gas production and modeling for future performance evaluation that identifies the current challenges in different stages. Several different and complex physics of gas flow in such a low permeability formation is also explained and the state of the art of the challenges encountered in the modeling process is also explained. As such, gas desorption phenomena, non-Darcy Flow, gas Klinkenberg effect are investigated for different shale formations in the US. This technical review also takes a look over the hydraulic fracturing effects on the economics of shale gas wells due to its straight tie to the production from shale and also the overall recovery from such reservoirs.展开更多
The autothermic pyrolysis in-situ conversion process (ATS) consumes latent heat of residual organic matter after kerogen pyrolysis by oxidation reaction, and it has the advantages of low development cost and exploitat...The autothermic pyrolysis in-situ conversion process (ATS) consumes latent heat of residual organic matter after kerogen pyrolysis by oxidation reaction, and it has the advantages of low development cost and exploitation of deep oil shale resources. However, the heating mechanism and the characteristic of different reaction zones are still unclear. In this study, an ATS numerical simulation model was proposed for the development of oil shale, which considers the pyrolysis of kerogen, high-temperature oxidation, and low-temperature oxidation. Based on the above model, the mechanism of the ATS was analyzed and the effects of preheating temperature, O_(2) content, and injection rate on recovery factor and energy efficiency were studied. The results showed that the ATS in the formation can be divided into five characteristic zones by evolution of the oil and O_(2) distribution, and the solid organic matter, including residue zone, autothermic zone, pyrolysis zone, preheating zone, and original zone. Energy efficiency was much higher for the ATS than for the high-temperature nitrogen injection in-situ conversion process (HNICP). There is a threshold value of the preheating temperature, the oil content, and the injection rate during the ATS, which is 400 °C, 0.18, and 1100 m3/day, respectively, in this study.展开更多
The Jurassic Yanan Formation is one of the most important coal-producing formations and hydrocarbon source rocks in the Ordos Basin, North China. To evaluate the shale gas potential of the Yanan shale, a total of 48 s...The Jurassic Yanan Formation is one of the most important coal-producing formations and hydrocarbon source rocks in the Ordos Basin, North China. To evaluate the shale gas potential of the Yanan shale, a total of 48 samples from north Ordos Basin were sampled, and their geochemical, petrological, mineralogical and pore characteristics were investigated. It was found that the shale samples are a suite of early mature source rock. The total organic carbon(TOC) content ranges from 0.33% to 24.12% and the hydrogen index(HI) ranges from 43.31 mg/g to 330.58 mg/g. The relationship between Tmax and HI indicates the organic matter is type Ⅱ-Ⅲ. This conclusion is also supported by the organic petrological examination results, which shows that the kerogen is mainly liptinite and vitrinite. Minerals in the samples are composed mainly of quartz, clay and feldspar, and the clay minerals are composed of prevailing kaolinite, illite/smectite, chlorite and a small amount of illite. Under scanning electron microscope, OM pores in the Yanan shale are scarce except pores come from the kerogen intrinsic texture or clay aggregates within the organic particles. As the weak compaction caused by shallow burial depth, interparticle pores and intraparticle pores are common, the hydrocarbon storage capacity of the Yanan shale was improved. According to evaluation, the Yanan shale is considered as a good shale gas reservoir, but its hydrocarbon potential is more dependent on biogenic and coal-derived gas as the thermogenic gas is limited by the lower thermal maturity.展开更多
The relationship between fracture calcite veins and shale gas enrichment in the deep Ordovician Wufeng Formation-Silurian Longmaxi Formation (Wufeng-Longmaxi) shales in southern Sichuan Basin was investigated through ...The relationship between fracture calcite veins and shale gas enrichment in the deep Ordovician Wufeng Formation-Silurian Longmaxi Formation (Wufeng-Longmaxi) shales in southern Sichuan Basin was investigated through core and thin section observations, cathodoluminescence analysis, isotopic geochemistry analysis, fluid inclusion testing, and basin simulation. Tectonic fracture calcite veins mainly in the undulating part of the structure and non-tectonic fracture calcite veins are mainly formed in the gentle part of the structure. The latter, mainly induced by hydrocarbon generation, occurred at the stage of peak oil and gas generation, while the former turned up with the formation of Luzhou paleouplift during the Indosinian. Under the influence of hydrocarbon generation pressurization process, fractures were opened and closed frequently, and oil and gas episodic activities are recorded by veins. The formation pressure coefficient at the maximum paleodepth exceeds 2.0. The formation uplift stage after the Late Yanshanian is the key period for shale gas migration. Shale gas migrates along the bedding to the high part of the structure. The greater the structural fluctuation is, the more intense the shale gas migration activity is, and the loss is more. The gentler the formation is, the weaker the shale gas migration activity is, and the loss is less. The shale gas enrichment in the core of gentle anticlines and gentle synclines is relatively higher.展开更多
The accurate prediction of formation pressure is important in oil/gas exploration and development.However,the achievement of this goal remains challenging,due to insufficient logging data and the low predictive data a...The accurate prediction of formation pressure is important in oil/gas exploration and development.However,the achievement of this goal remains challenging,due to insufficient logging data and the low predictive data accuracy from seismic data.In this work,a case study was carried out in the Baima area of Wulong,in order to develop a workflow for accurately predicting shale gas formation pressure.The multi-channel stack method was first used,as well as the inversion of single-channel seismic data,to construct velocity and density models of the formation.Combined with the existing welllogging data,the velocity and density models of the whole well section were established.The shale gas formation pressure was then estimated using the Eaton method.The results show that the multi-channel seismic stacking method has a higher accuracy than the inversion of the formation velocity obtained by the single-channel seismic method.The discrepancies between our predicted formation pressure and the actual formation pressure measurement are within an acceptable range,indicating that our workflow is effective.展开更多
Shale gas wells frequently suffer from liquid loading and insufficient formation pressure in the late stage of production.To address this issue,an intelligent production optimization method for low pressure and low pr...Shale gas wells frequently suffer from liquid loading and insufficient formation pressure in the late stage of production.To address this issue,an intelligent production optimization method for low pressure and low productivity shale gas well is proposed.Based on the artificial intelligence algorithms,this method realizes automatic production and monitoring of gas well.The method can forecast the production performance of a single well by using the long short-term memory neural network and then guide gas well production accordingly,to fulfill liquid loading warning and automatic intermittent production.Combined with adjustable nozzle,the method can keep production and pressure of gas wells stable automatically,extend normal production time of shale gas wells,enhance automatic level of well sites,and reach the goal of refined production management by making production regime for each well.Field tests show that wells with production regime optimized by this method increased 15%in estimated ultimate reserve(EUR).Compared with the development mode of drainage after depletion recovery,this method is more economical and can increase and stabilize production effectively,so it has a bright application prospect.展开更多
Developing mathematical models for high Knudsen number(Kn)flow for isotopic gas fractionation in tight sedimentary rocks is still challenging.In this study,carbon isotopic reversals(δ^(13)C_(1)>δ^(13)C_(2))were f...Developing mathematical models for high Knudsen number(Kn)flow for isotopic gas fractionation in tight sedimentary rocks is still challenging.In this study,carbon isotopic reversals(δ^(13)C_(1)>δ^(13)C_(2))were found for four Longmaxi shale samples based on gas degassing experiments.Gas in shale with higher gas content exhibits larger reversal.Then,a mathematical model was developed to simulate the carbon isotopic reversals of methane and ethane.This model is based on these hypotheses:(i)diffusion flow is dominating during gas transport process;(ii)diffusion coefficients are nonlinear depending on concentration gradient.Our model not only shows a good agreement with isotopic reversals,but also well predicts gas production rates by selecting appropriate exponents m and m^(*) of gas pressure gradient,where m is for ^(12)C and m^(*)is for ^(13)C.Moreover,the(m−m^(*))value has a positive correlation with fractionation level.(m1−m1^(*))of methane are much higher than that of ethane.Finally,the predicted carbon isotopic reversal magnitude(δ^(13)C_(1)−δ^(13)C_(2))exhibits a positive relationship with total gas content since gas in shale with higher gas content experiences a more extensive high Kn number diffusion flow.As a result,our model demonstrates an impressive agreement with the experimental carbon isotopic reversal data.展开更多
In this paper,a large-scale experimental system was established to identify the migration and distribution laws of complex fracture proppant in shale reservoir volume fracturing.With this system,the effects of seconda...In this paper,a large-scale experimental system was established to identify the migration and distribution laws of complex fracture proppant in shale reservoir volume fracturing.With this system,the effects of secondary fracture angle,fluid displacement,proppant concentration and size,fracturing fluid viscosity and other factors on the migration and distribution of proppant were tested,and the migration and distribution of proppant in primary/secondary fractures were analyzed.The following results were obtained.First,the fluid flow pattern in fractures transforms gradually from laminar flow into turbulent flow with the increase of fracture supporting height.Second,the migration modes of proppant in fractures mainly include suspended migration and gliding migration.Third,the distribution form of proppant in primary fractures before branching is related to secondary fracture angle,fluid displacement and proppant concentration and size,among which the fluid displacement is the most important factor.Fourth,the mass ratio of proppant in primary fractures after branching is proportional to the secondary fracture angle,fluid displacement,fracturing fluid viscosity and proppant concentration and size,and is inversely proportional to the flow ratio between secondary fractures and primary fractures.Fifth,the mass ratio of proppant in secondary fractures after branching is proportional to fluid displacement,fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures,and is inversely proportional to secondary fracture angle and proppant concentration and size.Sixth,the angle at the leading edge of proppant bank in the primary fractures after branching is proportional to the proppant concentration and size and the flow ratio between secondary fractures and primary fractures,but is inversely proportional to secondary fracture angle,fluid displacement and fracturing fluid viscosity.Seventh,the angle at the leading edge of proppant bank in the secondary fractures after branching is proportional to the secondary fracture angle and the proppant concentration and size,but is inversely proportional to the fluid displacement,fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures.In conclusion,the research results can provide a theoretical support for proppant optimization and program design of shale reservoir volume fracturing.展开更多
Taking the Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation shale reservoirs in western Chongqing area as the study target,the argon ion polishing scanning electron microscope and nuclear magneti...Taking the Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation shale reservoirs in western Chongqing area as the study target,the argon ion polishing scanning electron microscope and nuclear magnetic resonance(NMR)experiments of different saturated wetting media were carried out.Based on the image processing technology and the results of gas desorption,the pore-fracture configuration of the shale reservoirs and its influence on gas-filled mechanism were analyzed.(1)The reservoir space includes organic pores,inorganic pores and micro-fractures and there are obvious differences between wells in the development characteristics of micro-fractures;the organic pores adjacent to the micro-fractures are poorly developed,while the inorganic pores are well preserved.(2)According to the type,development degree and contact relationship of organic pore and micro-fracture,the pore-fracture configuration of the shale reservoir is divided into four types.(3)Based on the differences in NMR T_(2) spectra of shale samples saturated with oil and water,an evaluation parameter of pore-fracture configuration was constructed and calculated.The smaller the parameter,the better the pore-fracture configuration is.(4)The shale reservoir with good pore-fracture configuration has well-developed organic pores,high porosity,high permeability and high gas content,while the shale reservoir with poor pore-fracture configuration has micro-fractures developed,which improves the natural gas conductivity and leads to low porosity and gas content of the reservoir.(5)Based on pore-fracture configuration,from the perspective of organic matter generating hydrocarbon,micro-fracture providing migration channel,three types of micro gas-filled models of shale gas were established.展开更多
For the sake of figuring out the influential mechanisms of structural characteristics on the productivity of shale gas wells,the structural characteristics of the Jiaoshiba Block in the Fuling shale gasfield,Sichuan B...For the sake of figuring out the influential mechanisms of structural characteristics on the productivity of shale gas wells,the structural characteristics of the Jiaoshiba Block in the Fuling shale gasfield,Sichuan Basin,were analyzed.Then,based on well test data of more than 190 horizontal wells,the effects of structures on shale gas well productivity were discussed systematically,and the main structural factors of different structural units in the Jiaoshiba Block that influence the productivity of shale gas wells were clarified.The following results were obtained.First,the structural units in the Jiaoshiba Block were obviously different in structural characteristics and their deformation strength is different.Second,the influence of structural characteristics on shale gas well productivity is directly manifested in gas-bearing property and fracturing effect.The stronger the structural deformation and the more developed the large faults and natural fractures,the more easily shale gas escapes and the poorer the gas bearing property will be,and vice versa.Third,The stronger the structural deformation,the more developed the fractures,the greater the burial depth and the higher the compressive stress of negative structures,the worse the fracturing effect will be,and vice versa.And fourth,Tectonics is the key factor controlling the difference of shale gas productivity between different structural units in the Jiaoshiba Block,but the main structural factors influencing the productivity are different in different structural units.展开更多
基金Project supported by the Scientific Research and Technology Development Project of Petro China Company Limited“Research and test on key technologies for effective exploitation of deep shale gas”(No.2019F-31).
文摘There are abundant marine shale gas resources in the Sichuan Basin.After almost one decade of exploration and development,three national shale gas demonstration areas have been built in the Sichuan Basin and its periphery,and large-scale commercial development of middle and deep(above 3500 m in depth)shale gas has been successfully achieved.The volume of deep shale gas resources(3500e4500 m deep)of the upper Ordovician Wufeng Formation-lower Silurian Longmaxi Formation in the southern Sichuan Basin is 6.61012 m3,with huge exploration and exploitation potential,so it is an important area for large-scale shale gas production increase in China during the 14th Five-year Plan.Deep shale gas in the southern Sichuan Basin is influenced by complex geological engineering conditions,such as great burial depth,high temperature and pressure,and large stress and stress difference,and its high-quality development faces many challenges.After systematically summarizing the new progresses and achievements in deep shale gas exploration and development in the southern Sichuan Basin,this paper analyzes the difficulties and challenges in deep shale gas exploration and development and puts forward the next research directions.And the following research results are obtained.First,based on early practical exploration and independent innovation,key shale gas exploration and development technologies with good area selection,good well deployment,good well drilling,good well fracturing and good well management as the core are formed,and the cultivation mode of high production well is established,which supports the large-scale benefit development of deep shale gas in the southern Sichuan Basin.Second,systematical analysis indicates that the exploration and development of deep shale gas still faces a series of challenges in such three major fields as basic theory,key technology and management mode.Third,in the face of challenges,it is necessary to deepen basic theory research related to exploration and development,continuously improve key main technologies and constantly innovate mechanisms,systems and management modes.In conclusion,after years of continuous researches and pilot tests,a series of main exploration and development technologies suitable for the working conditions of deep shale gas in the southern Sichuan Basin have been basically formed,the first deep shale gas reserves of trillion cubic meters has been submitted,and the first deep shale gas production increase block of ten billion cubic meters has been selected.Thus,great progresses have been made in the exploration and development of deep shale gas,which confirms the confidence and determination in exploring and developing deep shale gas and is of great guiding significance to the rapid development of shale gas industry in China.
基金supported by the National Natural Science Foundation of China(No.42173030)the Open Project from the Key Laboratory of Shale Gas Exploration,Ministry of Natural Resources(KLSGE-202406).
文摘Benthic bivalves,the most widely distributed mollusks since the Mesozoic era,often inhabited environments where their fossilized remains are found adjacent to or intermingled with organic-rich shale.Recent Jurassic shale oil exploration in the Sichuan Basin has revealed that bioclastic layers,composed of abundant fossil bivalves and closely associated with shales and,exhibit significant hydrocarbon potentials.However,the microscopic structures of these bivalve fossils and their role in hydrocarbon storage and migration remain poorly understood.In this study,we characterized the microporosity of bivalve shells within the Middle-Lower Jurassic bioclastic shale in the northeastern Sichuan Basin using a combination of 2D imaging(thin section,SEM),3D reconstruction(FIB-SEM),and permeability simulation.The micropores within the shell fossils range from 100 to 1000 nm in radius and are uniformly distributed in a grid-like pattern within the shell interior,where they host liquid hydrocarbons.The bioclastic carbonate layers exhibit an overall porosity of approximately 0.8%.Comparative analysis with extant bivalve shells suggests that these micropores represent residual pores from the nacreous brick wall structure.Due to the regular orientation of the shells and their microporous nacres,permeability coefficients along the long bivalve fossil axes are three to five times higher than those along the short axes.These residual micropores within the bioclastic fossil shells have a positive influence on both the storage and migration of shale oil and gas,making bioclastic fossil-bearing shalespromising sweet spots for shale oil and gas exploration in similar sedimentary environments.
基金the Young Scientists Fund of the National Natural Science Foundation of China(52204063)the Key Laboratory of Shale Gas Exploration,Ministry of Natural Resources(Chongqing Institute of Geology and Mineral Resources),Chongqing,China(KLSGE-202202).
文摘This paper introduces a novel approach combining radial borehole fracturing with Water-Alternating-Gas(WAG)injection,enabling simultaneous WAG injection and shale oil production in a single vertical well.A numerical reservoir model incorporating the modified exponential non-Darcy law,stress sensitivity,and diffusion is established.The spatial distribution of permeability reduction shows that stress sensitivity enhances the non-Darcy effect,with apparent permeability decreasing to 0-92.1%of the initial value,highlighting the importance of maintaining reservoir pressure.Continuous CO_(2) flooding leads to early gas breakthrough,while continuous water flooding has less displacement efficiency.A 30%water-to-gas injection time ratio improves oil production and delays gas breakthrough compared to continuous CO_(2) injection.Optimal conditions for effective recovery are identified as an initial production period of 100 d and a well vertical spacing of 30 m.This study compares the production capacity of WAG operations under radial borehole fracturing and horizontal well fracturing.When the number of wells is two for both cases,the production capacity of radial borehole fracturing is comparable to that of five-stage horizontal well fracturing,indicating that radial borehole fracturing can serve as an alternative or supplement to horizontal well fracturing when the reservoir volume is limited.This study offers a new method and theoretical basis for the efficient development of shale oil.
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the financial support offered by the National Oil Shale Exploitation R&D Center Open Fund Project(Grant No.33550000-24-ZC0613-0055)National Key R&D Program of China(Grant No.2019YFA0705502,Grant No.2019YFA0705501)+1 种基金Science and technology research project of Education Department of Jilin Province(Grant No.JJKH20231185K)the National Natural Science Fund project of China(Grant No.4210020395,51974334)。
文摘Organic-rich shale is a significant potential source of oil and gas that requires development through in situ conversion technology.However,the evolution patterns of the internal three-dimensional(3D)pore structure and kerogen distribution at high temperatures are not well understood,making it difficult to microscopically explain the evolution of the flow conductivity in organic-rich shale at high temperatures.This study utilizes high-resolution X-ray computed tomography(micro-nano CT)to obtain the distribution of pores,kerogen,and inorganic matter at different temperatures.Combined with the pyrolysis results for the rock,the evolution of the pore structure at various temperatures is quantitatively analyzed.Based on three-phase segmentation technology,a model of kerogen distribution in organicrich shale is established by dividing the kerogen into clustered kerogen and dispersed kerogen stored in the inorganic matter and the pores into inorganic pores and organic pores within the kerogen skeleton.The results show that the inorganic pores in organic-rich shale evolve through three stages as the temperature increases:kerogen pyrolysis(200-400℃),clay mineral decomposition(400-600℃),and carbonate mineral decomposition(600-800℃).The inorganic pores porosity sequentially increases from 3%to 11.4%,13.1%,and 15.4%,and the roughness and connectivity of the inorganic pores gradually increase during this process.When the pyrolysis temperature reaches 400℃,the volume of clustered kerogen decreases from 25%to 12.5%.During this process,the relative density of kerogen decreases from9.5 g/cm^(3) in its original state to 5.4 g/cm^(3),while the kerogen skeleton density increases from 1.15 g/cm^(3) in its original state to 1.54 g/cm^(3).Correspondingly,7%-8%of organic pores develop within the clustered kerogen,accounting for approximately 50%of the volume of clustered kerogen.In addition,approximately 30%of the kerogen in organic-rich shale exists in the form of dispersed kerogen within inorganic matter,and its variation trend is similar to that of clustered kerogen,rapidly decreasing from 200 to 400℃ and stabilizing above 400℃.The results of this study provide an essential microscopic theoretical basis for the industrial development of organic-rich shale resources.
文摘Measuring gas content is an essential step in estimating the commerciality of gas reserves. In this study,eight shale core samples from the Mouye-1 well were measured using a homemade patented gas desorption apparatus to determine their gas contents. Due to the air contamination that is introduced into the desorption canister, a mathematical method was devised to correct the gas quantity and quality.Compared to the chemical compositions of desorbed gas, the chemical compositions of residual gas are somewhat different. In residual gas, carbon dioxide and nitrogen record a slight increase, and propane is first observed. This phenomenon may be related to the exposure time during the transportation of shale samples from the drilling site to the laboratory, as well as the differences in the mass, size and adsorptivity of different gas molecules. In addition to a series of conventional methods, including the USBM direct method and the Amoco Curve Fit(ACF) method, which were used here for lost gas content estimation, a Modified Curve Fit(MCF) method, based on the 'bidisperse' diffusion model, was established to estimate lost gas content. By fitting the ACF and MCF models to gas desorption data, we determined that the MCF method could reasonably describe the gas desorption data over the entire time period, whereas the ACF method failed. The failure of the ACF method to describe the gas desorption process may be related to its restrictive assumption of a single pore size within shale samples. In comparison to the indirect method, this study demonstrates that none of the three methods studied in this investigation(USBM, ACF and MCF) could individually estimate the lost gas contents of all shale samples and that the proportion of free gas relative to total gas has a significant effect on the estimation accuracy of the selected method. When the ratio of free gas to total gas is lower than 45%, the USBM method is the best for estimating the lost gas content, whereas when the ratio ranges from 45% to 75% or is more than 75%, the ACF and MCF methods, are the best options respectively.
基金supported by the National Natural Science Foundation of China(Grant No.41130417)‘‘111 Program’’(B13010)Shell Ph.D.Scholarship
文摘In contrast to conventional gas-bearing rocks, gas shale has extremely low permeability due to its nano- scale pore networks. Organic matter which is dispersed in the shale matrix makes gas flow characteristics more complex. The traditional Darcy＇s law is unable to estimate matrix permeability due to the particular flow mechanisms of shale gas. Transport mechanisms and influence factors are studied to describe gas transport in extremely tight shale. Then Lattice Boltzmann simulation is used to establish a way to estimate the matrix permeability numerically. The results show that net desorption, diffu- sion, and slip flow are very sensitive to the pore scale. Pore pressure also plays an important role in mass fluxes of gas. Temperature variations only cause small changes in mass fluxes. The Lattice Boltzmann method can be used to study the flow field in the micropore spaces and then provides numerical solutions even in complex pore structure models. Understanding the transport characteristics and establishing a way to estimate potential gas flow is very important to guide shale gas t＇eserve estimation and recovery schemes.
基金financially supported by National Natural Science Foundation of China(No.U19B6003,No.52074315)。
文摘Mechanical heterogeneity is a major characteristic of the organic-rich shale.The relation between mechanical heterogeneity and formation in-situ stress has been seldomly addressed but important to understand hydraulic fracture propagation,wellbore stability,and hydrocarbon flow.In this paper,the grid nanoindentation technique was used to characterize the heterogeneity of the mechanical properties of Longmaxi organic-rich shales from various burial depths and in-situ stress.The measured elastic modulus and hardness of each sample are deconvolved into three phases including soft phase,medium stiff phase and stiff phase according to mineral category.As the burial depth and corresponding in-situ stress increase,the overall elastic modulus and hardness of the sample enhance.Simultaneously,the percentage of soft minerals decreases,and the probability distribution tends to concentrate through 95%confidence interval evaluation which demonstrates weakened heterogeneity.Furthermore,SEM images provide evidence that extended cracking,initiated cracking,crushing and ductile deforming always occur around indentation imprints.This confirms that even under deep buried depth and high in-situ stress,brittle fracture and ductile deformation can exist synchronously.This paper demonstrates the influence of in-situ stress on the heterogeneity of shale micromechanics.
文摘Deep shale gas exploration and production in Fuling(Sichuan Basin,SW China)are confronted with hydraulic fracturing challenges owing to high stress,high fracture pressure,low pump rate and proppant concentration,as well as high closing pressure in deep strata.This study focused on the mechanical properties of shale core samples from Fuling through high-temperature triaxial rock mechanical tests and in-situ stress tests based on the Kessel effect of acoustic emission.Their mechanical property var-iations with depth were delineated using brittleness index calculated via simulating different depths and different confining pressures for the samples.The results showed that several parameters of deep shale reservoirs,i.e.brittleness index,fracture density,performance of self-propping,and flow conductivity,are lower than that of shale reservoirs with moderate burial depth.Thus,the current operating pressure in deep shale reservoir stimulation should be taken full advantage of,rather than channeling the focus on the propagation of fracture length.The objective is to increase the complexity of the near-hole fracture network for enhancing self-propping and flow conductivity of the fractures.This can be achieved by reducing the number of perforation clusters and cluster spacing,adopting variable-rate fracturing,decreasing proppant size,increasing sand volume,and optimizing the fracturing parameters.A field application showed that,compared with the neighboring wells,the test well had larger drainage area,doubling the gas yield.
基金Supported by the China National Science and Technology Major Project(2016ZX05060001-032)
文摘The main area of the Jiaoshiba anticline of the Fuling shale gas field was taken as the research object,laboratory rock mechanical experiments and direct shear experiments were conducted to clarify the mechanical anisotropy characteristics and parameters of rock samples with rich beddings.Based on the experimental results,a 3D fracture propagation model of the target reservoir taking mechanical anisotropy,weak bedding plane and vertical stress difference into account was established by the discrete element method to analyze distribution patterns of hydraulic fractures under different bedding densities,mechanical properties,and fracturing engineering parameters(including perforation clusters,injection rates and fracturing fluid viscosity).The research results show that considering the influence of the weak bedding plane and longitudinal stress difference,the interlayer stress difference 3–4 MPa in the study area can control the fracture height within the zone of stress barrier,and the fracture height is less than 40 m.If the influence of the weak bedding plane is not considered,the simulation result of fracture height is obviously higher.Although the opening of high-density bedding fractures increases the complexity of hydraulic fractures,it significantly limited the propagation of fracture height.By reducing the number of clusters,increasing the injection rate,and increasing the volume and proportion of high-viscosity fracturing fluid in the pad stage,the restriction on fracture height due to the bedding plane and vertical stress difference can be reduced,and the longitudinal propagation of fractures can be promoted.The fracture propagation model was used to simulate one stage of Well A in Fuling shale gas field,and the simulation results were consistent with the micro-seismic monitoring results.
文摘During the past several years, natural gas production from shale gas is increased and has adsorbed much attention worldwide. The reason behind this is because of advances gained in shale gas recovery techniques from this ultra-low permeability/porosity rock. These techniques are considered the horizontal drilling of the length of 3000 to 5000 ft long and conducting multi-stage hydraulic fracturing along the horizontal portion of the wells. The successful application of above has also driven down the gas prices worldwide and also culminated the security of gas supply for the upcoming decades. This paper is a technical literature review of shale gas production and modeling for future performance evaluation that identifies the current challenges in different stages. Several different and complex physics of gas flow in such a low permeability formation is also explained and the state of the art of the challenges encountered in the modeling process is also explained. As such, gas desorption phenomena, non-Darcy Flow, gas Klinkenberg effect are investigated for different shale formations in the US. This technical review also takes a look over the hydraulic fracturing effects on the economics of shale gas wells due to its straight tie to the production from shale and also the overall recovery from such reservoirs.
基金financial support offered by the National Key R&D Program of China(Grant No.2019YFA0705502,Grant No.2019YFA0705501)the National Natural Science Fund Project of China(Grant No.4210020395)+1 种基金the China Postdoctoral Science Foundation(Grant No.2021M700053)Technology Development Plan Project of Jilin Province(Grant No.20200201219JC).
文摘The autothermic pyrolysis in-situ conversion process (ATS) consumes latent heat of residual organic matter after kerogen pyrolysis by oxidation reaction, and it has the advantages of low development cost and exploitation of deep oil shale resources. However, the heating mechanism and the characteristic of different reaction zones are still unclear. In this study, an ATS numerical simulation model was proposed for the development of oil shale, which considers the pyrolysis of kerogen, high-temperature oxidation, and low-temperature oxidation. Based on the above model, the mechanism of the ATS was analyzed and the effects of preheating temperature, O_(2) content, and injection rate on recovery factor and energy efficiency were studied. The results showed that the ATS in the formation can be divided into five characteristic zones by evolution of the oil and O_(2) distribution, and the solid organic matter, including residue zone, autothermic zone, pyrolysis zone, preheating zone, and original zone. Energy efficiency was much higher for the ATS than for the high-temperature nitrogen injection in-situ conversion process (HNICP). There is a threshold value of the preheating temperature, the oil content, and the injection rate during the ATS, which is 400 °C, 0.18, and 1100 m3/day, respectively, in this study.
基金supported by the Ordos administrative district, Ordos Basin shale gas resource potential investigation and evaluation program (grant No. 2013CGKY0893)funded by the Ordos city energy investment and development Co., LTDthe National Natural Science Foundation of China (grant No. 41872124)
文摘The Jurassic Yanan Formation is one of the most important coal-producing formations and hydrocarbon source rocks in the Ordos Basin, North China. To evaluate the shale gas potential of the Yanan shale, a total of 48 samples from north Ordos Basin were sampled, and their geochemical, petrological, mineralogical and pore characteristics were investigated. It was found that the shale samples are a suite of early mature source rock. The total organic carbon(TOC) content ranges from 0.33% to 24.12% and the hydrogen index(HI) ranges from 43.31 mg/g to 330.58 mg/g. The relationship between Tmax and HI indicates the organic matter is type Ⅱ-Ⅲ. This conclusion is also supported by the organic petrological examination results, which shows that the kerogen is mainly liptinite and vitrinite. Minerals in the samples are composed mainly of quartz, clay and feldspar, and the clay minerals are composed of prevailing kaolinite, illite/smectite, chlorite and a small amount of illite. Under scanning electron microscope, OM pores in the Yanan shale are scarce except pores come from the kerogen intrinsic texture or clay aggregates within the organic particles. As the weak compaction caused by shallow burial depth, interparticle pores and intraparticle pores are common, the hydrocarbon storage capacity of the Yanan shale was improved. According to evaluation, the Yanan shale is considered as a good shale gas reservoir, but its hydrocarbon potential is more dependent on biogenic and coal-derived gas as the thermogenic gas is limited by the lower thermal maturity.
基金Supported by the PetroChina Science and Technology Project(2022KT1205).
文摘The relationship between fracture calcite veins and shale gas enrichment in the deep Ordovician Wufeng Formation-Silurian Longmaxi Formation (Wufeng-Longmaxi) shales in southern Sichuan Basin was investigated through core and thin section observations, cathodoluminescence analysis, isotopic geochemistry analysis, fluid inclusion testing, and basin simulation. Tectonic fracture calcite veins mainly in the undulating part of the structure and non-tectonic fracture calcite veins are mainly formed in the gentle part of the structure. The latter, mainly induced by hydrocarbon generation, occurred at the stage of peak oil and gas generation, while the former turned up with the formation of Luzhou paleouplift during the Indosinian. Under the influence of hydrocarbon generation pressurization process, fractures were opened and closed frequently, and oil and gas episodic activities are recorded by veins. The formation pressure coefficient at the maximum paleodepth exceeds 2.0. The formation uplift stage after the Late Yanshanian is the key period for shale gas migration. Shale gas migrates along the bedding to the high part of the structure. The greater the structural fluctuation is, the more intense the shale gas migration activity is, and the loss is more. The gentler the formation is, the weaker the shale gas migration activity is, and the loss is less. The shale gas enrichment in the core of gentle anticlines and gentle synclines is relatively higher.
基金support of the National Natural Science Key Foundation of China(Grant Nos.91958206,91858215)the Key Research and Development Program of Shandong(Grant No.2019GHY112019)+2 种基金the China Sponsorship Council(Grant No.201806335026)the Opening Foundation of Key Lab of Submarine Geosciences and Prospecting Techniques,MOE,Ocean University of China(Grant No.SGPT-20210F-06)the Fundamental Research Funds for the Central Universities(Grant No.202161013)。
文摘The accurate prediction of formation pressure is important in oil/gas exploration and development.However,the achievement of this goal remains challenging,due to insufficient logging data and the low predictive data accuracy from seismic data.In this work,a case study was carried out in the Baima area of Wulong,in order to develop a workflow for accurately predicting shale gas formation pressure.The multi-channel stack method was first used,as well as the inversion of single-channel seismic data,to construct velocity and density models of the formation.Combined with the existing welllogging data,the velocity and density models of the whole well section were established.The shale gas formation pressure was then estimated using the Eaton method.The results show that the multi-channel seismic stacking method has a higher accuracy than the inversion of the formation velocity obtained by the single-channel seismic method.The discrepancies between our predicted formation pressure and the actual formation pressure measurement are within an acceptable range,indicating that our workflow is effective.
基金Supported by the China National Science and Technology Major Project(2017ZX05037-004).
文摘Shale gas wells frequently suffer from liquid loading and insufficient formation pressure in the late stage of production.To address this issue,an intelligent production optimization method for low pressure and low productivity shale gas well is proposed.Based on the artificial intelligence algorithms,this method realizes automatic production and monitoring of gas well.The method can forecast the production performance of a single well by using the long short-term memory neural network and then guide gas well production accordingly,to fulfill liquid loading warning and automatic intermittent production.Combined with adjustable nozzle,the method can keep production and pressure of gas wells stable automatically,extend normal production time of shale gas wells,enhance automatic level of well sites,and reach the goal of refined production management by making production regime for each well.Field tests show that wells with production regime optimized by this method increased 15%in estimated ultimate reserve(EUR).Compared with the development mode of drainage after depletion recovery,this method is more economical and can increase and stabilize production effectively,so it has a bright application prospect.
基金support from Enterprise Innovation and Development Joint Fund of National Natural Science Foundation of China"Enrichment regularity and development mechanism of deep marine shale gas(U19B600303)"SINOPEC Science and Technology Department Project"Research on Precision Characterization of Shale Pore and Fluid Dynamic Monitoring Technology(P20059-8)"。
文摘Developing mathematical models for high Knudsen number(Kn)flow for isotopic gas fractionation in tight sedimentary rocks is still challenging.In this study,carbon isotopic reversals(δ^(13)C_(1)>δ^(13)C_(2))were found for four Longmaxi shale samples based on gas degassing experiments.Gas in shale with higher gas content exhibits larger reversal.Then,a mathematical model was developed to simulate the carbon isotopic reversals of methane and ethane.This model is based on these hypotheses:(i)diffusion flow is dominating during gas transport process;(ii)diffusion coefficients are nonlinear depending on concentration gradient.Our model not only shows a good agreement with isotopic reversals,but also well predicts gas production rates by selecting appropriate exponents m and m^(*) of gas pressure gradient,where m is for ^(12)C and m^(*)is for ^(13)C.Moreover,the(m−m^(*))value has a positive correlation with fractionation level.(m1−m1^(*))of methane are much higher than that of ethane.Finally,the predicted carbon isotopic reversal magnitude(δ^(13)C_(1)−δ^(13)C_(2))exhibits a positive relationship with total gas content since gas in shale with higher gas content experiences a more extensive high Kn number diffusion flow.As a result,our model demonstrates an impressive agreement with the experimental carbon isotopic reversal data.
基金supported by the Science Foundation for Young Scientists of National Natural Science Foundation of China,“Study on the Diversion and Distribution Mechanisms of Proppant for“Multi-Stage And Multi-Cluster”Fracturing by Shale Horizontal Well”(Grant No.51604050)the Chongqing Science and Technology Innovation Project for People's Livelihood,“Research&Development of Instruments for Evaluating the Migration and Distribution of Proppant for“Multi-Stage And Multi-Cluster”Fracturing by Shale Horizontal Well”(Grant No.cstc2016shmszx90003).
文摘In this paper,a large-scale experimental system was established to identify the migration and distribution laws of complex fracture proppant in shale reservoir volume fracturing.With this system,the effects of secondary fracture angle,fluid displacement,proppant concentration and size,fracturing fluid viscosity and other factors on the migration and distribution of proppant were tested,and the migration and distribution of proppant in primary/secondary fractures were analyzed.The following results were obtained.First,the fluid flow pattern in fractures transforms gradually from laminar flow into turbulent flow with the increase of fracture supporting height.Second,the migration modes of proppant in fractures mainly include suspended migration and gliding migration.Third,the distribution form of proppant in primary fractures before branching is related to secondary fracture angle,fluid displacement and proppant concentration and size,among which the fluid displacement is the most important factor.Fourth,the mass ratio of proppant in primary fractures after branching is proportional to the secondary fracture angle,fluid displacement,fracturing fluid viscosity and proppant concentration and size,and is inversely proportional to the flow ratio between secondary fractures and primary fractures.Fifth,the mass ratio of proppant in secondary fractures after branching is proportional to fluid displacement,fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures,and is inversely proportional to secondary fracture angle and proppant concentration and size.Sixth,the angle at the leading edge of proppant bank in the primary fractures after branching is proportional to the proppant concentration and size and the flow ratio between secondary fractures and primary fractures,but is inversely proportional to secondary fracture angle,fluid displacement and fracturing fluid viscosity.Seventh,the angle at the leading edge of proppant bank in the secondary fractures after branching is proportional to the secondary fracture angle and the proppant concentration and size,but is inversely proportional to the fluid displacement,fracturing fluid viscosity and flow ratio between secondary fractures and primary fractures.In conclusion,the research results can provide a theoretical support for proppant optimization and program design of shale reservoir volume fracturing.
基金Supported by the Petro China-Southwest Petroleum University Innovation Consortium Project(2020CX020104)Higher Education Innovative Talents Program(Plan 111)(D18016)Sichuan Collaborative Innovation Center for Shale Gas Resources and Environment SEC-2018-03)。
文摘Taking the Upper Ordovician Wufeng Formation to Lower Silurian Longmaxi Formation shale reservoirs in western Chongqing area as the study target,the argon ion polishing scanning electron microscope and nuclear magnetic resonance(NMR)experiments of different saturated wetting media were carried out.Based on the image processing technology and the results of gas desorption,the pore-fracture configuration of the shale reservoirs and its influence on gas-filled mechanism were analyzed.(1)The reservoir space includes organic pores,inorganic pores and micro-fractures and there are obvious differences between wells in the development characteristics of micro-fractures;the organic pores adjacent to the micro-fractures are poorly developed,while the inorganic pores are well preserved.(2)According to the type,development degree and contact relationship of organic pore and micro-fracture,the pore-fracture configuration of the shale reservoir is divided into four types.(3)Based on the differences in NMR T_(2) spectra of shale samples saturated with oil and water,an evaluation parameter of pore-fracture configuration was constructed and calculated.The smaller the parameter,the better the pore-fracture configuration is.(4)The shale reservoir with good pore-fracture configuration has well-developed organic pores,high porosity,high permeability and high gas content,while the shale reservoir with poor pore-fracture configuration has micro-fractures developed,which improves the natural gas conductivity and leads to low porosity and gas content of the reservoir.(5)Based on pore-fracture configuration,from the perspective of organic matter generating hydrocarbon,micro-fracture providing migration channel,three types of micro gas-filled models of shale gas were established.
基金Project supported by National Science and Technology Major Project“Demonstration Project of Fuling Shale Gas Development”(No.:2016ZX05060).
文摘For the sake of figuring out the influential mechanisms of structural characteristics on the productivity of shale gas wells,the structural characteristics of the Jiaoshiba Block in the Fuling shale gasfield,Sichuan Basin,were analyzed.Then,based on well test data of more than 190 horizontal wells,the effects of structures on shale gas well productivity were discussed systematically,and the main structural factors of different structural units in the Jiaoshiba Block that influence the productivity of shale gas wells were clarified.The following results were obtained.First,the structural units in the Jiaoshiba Block were obviously different in structural characteristics and their deformation strength is different.Second,the influence of structural characteristics on shale gas well productivity is directly manifested in gas-bearing property and fracturing effect.The stronger the structural deformation and the more developed the large faults and natural fractures,the more easily shale gas escapes and the poorer the gas bearing property will be,and vice versa.Third,The stronger the structural deformation,the more developed the fractures,the greater the burial depth and the higher the compressive stress of negative structures,the worse the fracturing effect will be,and vice versa.And fourth,Tectonics is the key factor controlling the difference of shale gas productivity between different structural units in the Jiaoshiba Block,but the main structural factors influencing the productivity are different in different structural units.
