Naturally fractured rocks contain most of the world's petroleum reserves.This significant amount of oil can be recovered efficiently by gas assisted gravity drainage(GAGD).Although,GAGD is known as one of the most...Naturally fractured rocks contain most of the world's petroleum reserves.This significant amount of oil can be recovered efficiently by gas assisted gravity drainage(GAGD).Although,GAGD is known as one of the most effective recovery methods in reservoir engineering,the lack of available simulation and mathematical models is considerable in these kinds of reservoirs.The main goal of this study is to provide efficient and accurate methods for predicting the GAGD recovery factor using data driven techniques.The proposed models are developed to relate GAGD recovery factor to the various parameters including model height,matrix porosity and permeability,fracture porosity and permeability,dip angle,viscosity and density of wet and non-wet phases,injection rate,and production time.In this investigation,by considering the effective parameters on GAGD recovery factor,three different efficient,smart,and fast models including artificial neural network(ANN),least square support vector machine(LSSVM),and multi-gene genetic programming(MGGP)are developed and compared in both fractured and homogenous porous media.Buckinghamπtheorem is also used to generate dimensionless numbers to reduce the number of input and output parameters.The efficiency of the proposed models is examined through statistical analysis of R-squared,RMSE,MSE,ARE,and AARE.Moreover,the performance of the generated MGGP correlation is compared to the traditional models.Results demonstrate that the ANN model predicts the GAGD recovery factor more accurately than the LSSVM and MGGP models.The maximum R^(2)of 0.9677 and minimum RMSE of 0.0520 values are obtained by the ANN model.Although the MGGP model has the lowest performance among the other used models(the R2 of 0.896 and the RMSE of 0.0846),the proposed MGGP correlation can predict the GAGD recovery factor in fractured and homogenous reservoirs with high accuracy and reliability compared to the traditional models.Results reveal that the employed models can easily predict GAGD recovery factor without requiring complicate governing equations or running complex and time-consuming simulation models.The approach of this research work improves our understanding about the most significant parameters on GAGD recovery and helps to optimize the stages of the process,and make appropriate economic decisions.展开更多
Based on practices of CO_(2) flooding tests in China and abroad,the recovery factor of carbon dioxide capture,utilization in displacing oil and storage(CCUS-EOR)in permanent sequestration scenario has been investigate...Based on practices of CO_(2) flooding tests in China and abroad,the recovery factor of carbon dioxide capture,utilization in displacing oil and storage(CCUS-EOR)in permanent sequestration scenario has been investigated in this work.Under the background of carbon neutrality,carbon dioxide injection into geological bodies should pursue the goal of permanent sequestration for effective carbon emission reduction.Hence,CCUS-EOR is an ultimate development method for oil reservoirs to maximize oil recovery.The limit recovery factor of CCUS-EOR development mode is put forward,the connotation differences between it and ultimate recovery factor and economically reasonable recovery factor are clarified.It is concluded that limit recovery factor is achievable with mature supporting technical base for the whole process of CCUS-EOR.Based on statistics of practical data of CO_(2) flooding projects in China and abroad such as North H79 block CO_(2) flooding pilot test at small well spacing in Jilin Oilfield etc.,the empirical relationship between the oil recovery factor of miscible CO_(2) flooding and cumulative CO_(2) volume injected is obtained by regression.Combined with the concept of oil production rate multiplier of gas flooding,a reservoir engineering method calculating CO_(2) flooding recovery factor under any miscible degree is established by derivation.It is found that when the cumulative CO_(2) volume injected is 1.5 times the hydrocarbon pore volume(HCPV),the relative deviation and the absolute difference between the recovery percentage and the limit recovery factor are less than 5%and less than 2.0 percentage points respectively.The limit recovery factor of CCUS-EOR can only be approached by large pore volume(PV)injection based on the technology of expanding swept volume.It needs to be realized from three aspects:large PV injection scheme design,enhancing miscibility degree and continuously expanding swept volume of injected CO_(2).展开更多
Suspended sediment concentrations in the Middle Yangtze River(MYR)reduced greatly after the Three Gorges Project operation,causing the composition of bed material to coarsen continuously.However,little is known about ...Suspended sediment concentrations in the Middle Yangtze River(MYR)reduced greatly after the Three Gorges Project operation,causing the composition of bed material to coarsen continuously.However,little is known about the non-equilibrium transport of graded suspended sediment owing to different bed material compositions(BMCs)along the MYR,and it is necessary to determine the magnitude of recovery factor.Using the Markov stochastic process in conjunction with the hiding-exposure effect of non-uniform bed-material,a new formula is proposed for calculating the recovery factor including the effect of different BMCs,and it is incorporated into the non-equilibrium transport equation to simulate the recovery processes of suspended load in both sand-gravel bed and sand bed reaches of the MYR.The results show that:(i)the recovery rate of graded sediment concentrations at Zhicheng was slower than that at Shashi during the period 2003-2007;(ii)the mean recovery factors of the coarse,medium,and fine sediment fractions in the ZhichengShashi reach were 0.152,0.0012,and 0.0005,respectively,and the coarse sediment recovered up to the maximum sediment concentration of 0.138 kg/m3over a distance of 15 km;and(iii)the results of the new formula that can consider the effect of bed material composition are in general agreement with the field observations,and the spatial and temporal delay effects are inversely related to particle size and BMC.Consequently,the BMC effect on the nonequilibrium sediment transport in different reaches of the MYR needs to be considered for higher simulation accuracy.展开更多
A novel type curve is presented for oil recovery factor prediction suitable for gas flooding by innovatively introducing the equivalent water-gas cut to replace the water cut,comprehensively considering the impact of ...A novel type curve is presented for oil recovery factor prediction suitable for gas flooding by innovatively introducing the equivalent water-gas cut to replace the water cut,comprehensively considering the impact of three-phase flow(oil,gas,water),and deriving the theoretical equations of gas flooding type curve based on Tong’s type curve.The equivalent water-gas cut is the ratio of the cumulative underground volume of gas and water production to the total underground volume of produced fluids.Field production data and the numerical simulation results are used to demonstrate the feasibility of the new type curve and verify the accuracy of the prediction results with field cases.The new type curve is suitable for oil recovery factor prediction of both water flooding and gas flooding.When a reservoir has no gas injected or produced,the gas phase can be ignored and only the oil and water phases need to be considered,in this case,this gas flooding type curve returns to the Tong’s type curve,which can evaluate the oil recovery factor of water flooding.For reservoirs with equivalent water-gas cuts of 60%-80%,the regression method of the new type curve works well in predicting the oil recovery factor.For reservoirs with equivalent water-gas cuts higher than 80%,both the regression and assignment methods of the new type curve can accurately predict the oil recovery factor of gas flooding.展开更多
Oil recovery factor is one of the most important parameters in the development process of oil reservoir,especially in the low-permeability reservoir.In general,the determination of recovery factor can be obtained eith...Oil recovery factor is one of the most important parameters in the development process of oil reservoir,especially in the low-permeability reservoir.In general,the determination of recovery factor can be obtained either experimentally or numerically.Experimental method is often timeconsuming and expensive,while numerical method has been always confined to narrow range of application or relatively large error.Recently,an intelligent method has been proven as an efficient tool to model the complex and nonlinear phenomena.In this work,an intelligent model based on support vector machine in combination with the particle swarm optimization(PSO-SVM)technique was established to predict oil recovery factor in the low-permeability reservoir.Input variables of the proposed PSO-SVM model with the aid of a grey correlation analysis method are permeability,well spacing density,production-injection well ratio,porosity,effective thickness,crude oil viscosity and output parameter is oil recovery factor of low-permeability reservoir.The accuracy and reliability of the proposed model were evaluated through 34 data sets collected in the open literature and compared with PSO-BP neural network,empirical method from Oil and Gas Company.The results indicated that the PSO-SVM model gives the best results with average absolute relative deviation(AARD)of 3.79%,while AARDs for the PSO-BP neural network and empirical method are 9.18%and 10.0%,respectively.Furthermore,outlier detection was used on the basis of whole data sets to definite the valid domains of PSO-SVM and PSO-BP models by detecting the probable doubtful recovery factor data in the low-permeability reservoir.展开更多
Well-known oil recovery factor estimation techniques such as analogy,volumetric calculations,material balance,decline curve analysis,hydrodynamic simulations have certain limitations.Those techniques are time-consumin...Well-known oil recovery factor estimation techniques such as analogy,volumetric calculations,material balance,decline curve analysis,hydrodynamic simulations have certain limitations.Those techniques are time-consuming,and require specific data and expert knowledge.Besides,though uncertainty estimation is highly desirable for this problem,the methods above do not include this by default.In this work,we present a data-driven technique for oil recovery factor(limited to water flooding)estimation using reservoir parameters and representative statistics.We apply advanced machine learning methods to historical worldwide oilfields datasets(more than 2000 oil reservoirs).The data-driven model might be used as a general tool for rapid and completely objective estimation of the oil recovery factor.In addition,it includes the ability to work with partial input data and to estimate the prediction interval of the oil recovery factor.We perform the evaluation in terms of accuracy and prediction intervals coverage for several tree-based machine learning techniques in application to the following two cases:(1)using parameters only related to geometry,geology,transport,storage and fluid properties,(2)using an extended set of parameters including development and production data.For both cases,the model proved itself to be robust and reliable.We conclude that the proposed data-driven approach overcomes several limitations of the traditional methods and is suitable for rapid,reliable and objective estimation of oil recovery factor for hydrocarbon reservoir.展开更多
The double-network prepared with an in-situ monomer gel and a fast-crosslinked Cr(III) gel is introduced to develop a thixotropic and high-strength gel (THSG), which is found to have many advantages over the tradition...The double-network prepared with an in-situ monomer gel and a fast-crosslinked Cr(III) gel is introduced to develop a thixotropic and high-strength gel (THSG), which is found to have many advantages over the traditional gels. The THSG gel demonstrates remarkable thermal stability, and no syneresis is observed after 12 months with high salinity brine (95,500 mg/L). Moreover, the SEM and XRD results indicate that the gel is intercalated into the lamellar structures of Na-MMT, where the gel can form a uniform and compact structure. In addition, the THSG gel has an excellent swelling behavior, even in the high salinity brine. In the slim tube experiments, the THSG gel exhibits high rupture pressure and improves blocking capacity after being ruptured. The core flooding results show that a layer of gel filter cake is formed on the face of the fracture, which may be promoted by a high matrix permeability, a small aperture fracture, and a high injection rate. After the gel treatment, the fracture can be completely blocked by the THSG gel. It is found that a high incremental oil recovery (65.3%) can be achieved when the fracture was completely blocked, compared to 40.2% if the gel is ruptured. Although the swelling of ruptured gel can improve oil recovery, part of the injected brine may be channeled through the gel-filled fractures, resulting in a decrease in the sweep efficiency. Therefore, the improved blocking ability by gel swelling (e.g., in fresh water) may be less efficient to contribute to an enhancement of oil recovery. It is also found that the pressure gradient and residual resistance factor to water (Frrw) are higher if the matrix is less permeable, indicating that the fractured reservoir with lower matrix permeability may require a higher gel strength for treatment. The findings of this study may provide novel insights on designing robust double network gels for water shutoff in fractured reservoirs.展开更多
Based on the exploration and development achievements of the Sulige Gasfield in the Ordos Basin,tight sandstone gas yield has been increased essentially in China.Recovery enhancement is always the core subject in rese...Based on the exploration and development achievements of the Sulige Gasfield in the Ordos Basin,tight sandstone gas yield has been increased essentially in China.Recovery enhancement is always the core subject in researches.In this paper,the development history of the Sulige Gasfield was reviewed focusing on the technological progress in single well production enhancement.Then,the technical ideas on and countermeasures for transforming the traditional development modes and increasing recovery factor were discussed.It is shown that the development technologies in the evaluation and the production enhancement and stabilization of giant tight sandstone gas reservoirs are changed progressively.The fast increase of gas production in this field is made possible by well location arrangement technology based on sweep spot screening,horizontal well development technology,well type and well pattern optimization technology,fast drilling technology,reservoir stimulation technology,drainage gas recovery technology and integrated construction mode.And finally,the technical ideas of recovery enhancement during the 13th Five-Year Plan were proposed in nine aspects,including gas field development,planning and evaluation technology based on single-well life cycle analysis;dynamic evaluation and infilling technology for mixed well patterns targeting recovery enhancement;one-shot recovery enhancement technology for a new areal pattern area with integrated multiple well patterns and multiple series of strata;reserve evaluation model based on risk and benefit evaluation;gas-well precise management technology with multi-dimensional matrix;potential tapping technology for low production and low efficiency wells;novel wellsite environmental protection technology;surface process based on integrated equipments;and C_(3)^(+)mixed hydrocarbon recovery technology.It provides technically reliable support for the development of tight sandstone gas reservoirs in the Sulige Gasfield during the 13th Five-Year Plan.展开更多
The current in the production and living of people, there are more and more demand for oil and gas energy, in such cases, the need to fundamentally effectively do a good job in the development of oil and gas fields an...The current in the production and living of people, there are more and more demand for oil and gas energy, in such cases, the need to fundamentally effectively do a good job in the development of oil and gas fields and harvest at the same time in the process of practice to fully grasp all kinds of factors affect recovery efficiency of oil and gas field development, and then to handle, tangible and fundamentally improve the development of oil and gas field recovery. Combined with this situation, this paper focuses on the analysis of various factors affecting oil and gas field development and recovery factors and relevant measures.展开更多
There are various issues for CO_(2)flooding and storage in Shengli Oilfield,which are characterized by low light hydrocarbon content of oil and high miscible pressure,strong reservoir heterogeneity and low sweep effic...There are various issues for CO_(2)flooding and storage in Shengli Oilfield,which are characterized by low light hydrocarbon content of oil and high miscible pressure,strong reservoir heterogeneity and low sweep efficiency,gas channeling and difficult whole-process control.Through laboratory experiments,technical research and field practice,the theory and technology of CO_(2)high pressure miscible flooding and storage are established.By increasing the formation pressure to 1.2 times the minimum miscible pressure,the miscibility of the medium-heavy components can be improved,the production percentage of oil in small pores can be increased,the displacing front developed evenly,and the swept volume expanded.Rapid high-pressure miscibility is realized through advanced pressure flooding and energy replenishment,and technologies of cascade water-alternating-gas(WAG),injection and production coupling and multistage chemical plugging are used for dynamic control of flow resistance,so as to obtain the optimum of oil recovery and CO_(2)storage factor.The research results have been applied to the Gao89-Fan142 in carbon capture,utilization and storage(CCUS)demonstration site,where the daily oil production of the block has increased from 254.6 t to 358.2 t,and the recovery degree is expected to increase by 11.6 percentage points in 15 years,providing theoretical and technical support for the large-scale development of CCUS.展开更多
São Paulo State has witnessed CO_(2)storage-based investigations considering the availability of suitable geologic structures and proximity to primary CO_(2)source sinks related to bioenergy and carbon capture an...São Paulo State has witnessed CO_(2)storage-based investigations considering the availability of suitable geologic structures and proximity to primary CO_(2)source sinks related to bioenergy and carbon capture and storage(BECCS)activities.The current study presents the hydrocarbon viability evaluations and CO_(2)storage prospects,focusing on the sandstone units of the Rio Bonito Formation.The objective is to apply petrophysical evaluations with geochemical inputs in predicting future hydrocarbon(gas)production to boost CO_(2)storage within the study location.The study used data from eleven wells with associated wireline logs(gamma ray,resistivity,density,neutron,and sonic)to predict potential hydrocarbon accumulation and fluid mobility in the investigated area.Rock samples(shale and carbonate)obtained from depths>200 m within the study location have shown bitumen presence.Organic geochemistry data of the Rio Bonito Formation shale beds suggest they are potential hydrocarbon source rocks and could have contributed to the gas accumulations within the sandstone units.Some drilled well data,e.g.,CB-1-SP and TI-1-SP,show hydrocarbon(gas)presence based on the typical resistivity and the combined neutron-density responses at depths up to 3400 m,indicating the possibility of other hydrocarbon members apart from the heavy oil(bitumen)observed from the near-surface rocks samples.From the three-dimensional(3-D)model,the free fluid indicator(FFI)is more significant towards the southwest and southeast of the area with deeper depths of occurrence,indicating portions with reasonable hydrocarbon recovery rates and good prospects for CO_(2)injection,circulation and permanent storage.However,future studies based on contemporary datasets are required to establish the hydrocarbon viability further,foster gas production events,and enhance CO_(2)storage possibilities within the region.展开更多
Water invasion is a common phenomenon in gas reservoirs with active edge-and-bottom aquifers.Due to high reservoir heterogeneity and production parameters,carbonate gas reservoirs feature exploitation obstacles and lo...Water invasion is a common phenomenon in gas reservoirs with active edge-and-bottom aquifers.Due to high reservoir heterogeneity and production parameters,carbonate gas reservoirs feature exploitation obstacles and low recovery factors.In this study,combined core displacement and nuclear magnetic resonance(NMR)experiments explored the reservoir gas−water two-phase flow and remaining microscopic gas distribution during water invasion and gas injection.Consequently,for fracture core,the water-phase relative permeability is higher and the co-seepage interval is narrower than that of three pore cores during water invasion,whereas the water-drive recovery efficiency at different invasion rates is the lowest among all cores.Gas injection is beneficial for reducing water saturation and partially restoring the gas-phase relative permeability,especially for fracture core.The remaining gas distribution and the content are related to the core properties.Compared with pore cores,the water invasion rate strongly influences the residual gas distribution in fracture core.The results enhance the understanding of the water invasion mechanism,gas injection to resume production and the remaining gas distribution,so as to improve the recovery factors of carbonate gas reservoirs.展开更多
Since the implementation of several pilot production tests were in natural gas hydrate(NGH) reservoirs in terrestrial and marine settings, the study of NGH has entered a new stage of technological development for indu...Since the implementation of several pilot production tests were in natural gas hydrate(NGH) reservoirs in terrestrial and marine settings, the study of NGH has entered a new stage of technological development for industrial exploitation. Prior to the industrial exploitation of any given NGH reservoir, the economic feasibility should be examined. The first step of economic evaluation of a NGH reservoir is to know whether its resource amount meets the requirement for industrial exploitation. Unfortunately, few relevant studies have been conducted in this regard. In this study, the net present value(NPV) method is employed to estimate the economic critical resources required for the industrial exploitation of NGHs under different production scenarios. Sensitivity analysis is also performed in order to specify the effects of key factors, such as the number of production wells, gas price, technological improvement and tax incentive, on the economic critical resources. The results indicate that China requires the lowest economic critical resource for a NGH reservoir to be industrially exploited, ranging from 3.62 to 24.02 billion m3 methane. Changes in gas price and tax incentives also play significant roles in affecting the threshold and timeline for the industrial exploitation of NGH.展开更多
The problem of water coning into the Tarim fractured sandstone gas reservoirs becomes one of the major concerns in terms of productivity, increased operating costs and environmental effects. Water coning is a phenomen...The problem of water coning into the Tarim fractured sandstone gas reservoirs becomes one of the major concerns in terms of productivity, increased operating costs and environmental effects. Water coning is a phenomenon caused by the imbalance between gravity and viscous forces around the completion interval. There are several controllable and uncontrollable parameters influencing this problem. In order to simulate the key parameters affecting the water coning phenomenon, a model was developed to represent a single well with an underlying aquifer using the fractured sandstone gas reservoir data of the A-Well in Dina gas fields.The parametric study was performed by varying six properties individually over a representative range. The results show that matrix permeability, well penetration(especially fracture permeability), vertical-to-horizontal permeability ratio, aquifer size and gas production rate have considerable effect on water coning in the fractured gas reservoirs. Thus, investigation of the effective parameters is necessary to understand the mechanism of water coning phenomenon. Simulation of the problem helps to optimize the conditions in which the breakthrough of water coning is delayed.展开更多
Given the rise in oil productivity from conventional and unconventional resources in Canada using Enhanced Oil Recovery (EOR), the need to understand and characterize these techniques, for the purpose of recovery opti...Given the rise in oil productivity from conventional and unconventional resources in Canada using Enhanced Oil Recovery (EOR), the need to understand and characterize these techniques, for the purpose of recovery optimization, has taken a prominent role in resource management. Chemical flooding has proved to be one of the most efficient EOR techniques. This study investigated the potential of employing Ionic Liquids (ILs) as alternative chemical agents for improving oil recovery. There is very little attention paid to employing this technique as well as few experimental and simulation studies. Consequently, very limited data are available. Since pilot and field studies are relatively expensive and time consuming, a numerical simulation study using CMG-STARS simulator was utilized to explore the efficiency of employing 1-Ethyl-3-Methyl-Imidazolium Acetate ([EMIM][Ac]) and 1-Benzyl-3-meth- limidazolium chloride ([BenzMIM][Cl]) with respect to improving medium oil recovery. Eight different lab-scale sandpack flooding experiments were selected to develop a numerical model to obtain the history matching of the experimental flooding results using CMG-CMOST. We observed that the main challenge was tuning the relative permeability curves to achieve a successful match for the oil recovery factor. Finally, a sensitivity study was performed to examine the effect of the chemical injection rate, the chemical concentration, the slug size, and the initiation time on oil recovery. The results showed a noticeable increase in the oil RF when injecting IL compared to conventional waterflooding.展开更多
Description is given to preparation of three ionic liquid surfactants containing amine functional groups, characterization of their functional groups using the infrared spectrometer, determination of their surface ten...Description is given to preparation of three ionic liquid surfactants containing amine functional groups, characterization of their functional groups using the infrared spectrometer, determination of their surface tension and the oil displacement test in this paper to investigate the effect of alkane branch chains with different carbon numbers on the surface tension and the displacement efficiency. The result shows that, the surfactants exhibit the structural characteristic of the ionic liquid as the characteristic absorption peaks occur on C-N and C-H of the imidazole rings at the wave numbers of 1338cm-1, 1234em-1, 1465crn-1 and 3142cm-1, respectively. The surface tension isothermal curves and the oil displacem ent test proved that the ionic liquid imidazole surfactants with shorter-chain groups are more active on surface, with the minimal surface tension up to 32.5 mN/m, and led to higher displacement efficiency, increasing by 3.3% at the concentration of 1000mg/L compared with the water flooding.展开更多
An outstanding issue in the oil and gas industry is how to evaluate quantitatively the influences of water production on production per-formance of gas wells.Based on gasewater flow theories,therefore,a new method was...An outstanding issue in the oil and gas industry is how to evaluate quantitatively the influences of water production on production per-formance of gas wells.Based on gasewater flow theories,therefore,a new method was proposed in this paper to evaluate quantitatively the production performance of water-producing gas wells by using gas&water relative permeability curves after a comparative study was conducted thoroughly.In this way,quantitative evaluation was performed on production capacity,gas production,ultimate cumulative gas production and recovery factor of water-producing gas wells.Then,a case study was carried out of the tight sandstone gas reservoirs with strong heterogeneity in the Sulige gas field,Ordos Basin.This method was verified in terms of practicability and reliability through a large amount of calculation based on the actual production performance data of various gas wells with different volumes of water produced.Finally,empirical formula and charts were established for water-producing gas wells in this field to quantitatively evaluate their production capacity,gas production,ultimate cumulative gas production and recovery factor in the conditions of different wateregas ratios.These formula and charts provide technical support for the field application and dissemination of the method.Study results show that water production is serious in the west of this field with wateregas ratio varying in a large range.If the average wateregas ratio is 1.0(or 2.0)m^(3)/10^(4) m^(3),production capacity,cumulative gas pro-duction and recovery factor of gas wells will be respectively 24.4%(or 40.2%),24.4%(or 40.2%)and 17.4%(or 33.2%).展开更多
In order to find an economic and effective water control method for horizontal wells in deep sea bottom-water gas reservoirs,we prepared modified coated gravel.Based on this,wear resistance,temperature resistance and ...In order to find an economic and effective water control method for horizontal wells in deep sea bottom-water gas reservoirs,we prepared modified coated gravel.Based on this,wear resistance,temperature resistance and water plugging capacity(WPC)tests were carried out on the coated gravel.Then,experiments were carried out using the 3D simulation device for the development of large-scale bottom-water gas reservoirs to compare the development effects of horizontal wells packed with conventional gravel and coated gravel in deepsea bottom-water gas reservoirs.And the following research results were obtained.First,the upper limit of temperature resistance of the gravel coating is 240℃ and the gravel packing speed can reach 4.48 m/s,which is 8 times the average flow velocity of gravel packing in actual open hole sections.Second,as the permeability of the coated gravel packing layer increases,its WPC gets weak.When the permeability is lower than 1500 mD and the displacement pressure difference is lower than 0.6 MPa,the WPC of the coated gravel packing layer is between 0.17 and 0.68.Third,the coated gravel layer functions as gas permeability and water plugging,so the horizontal well technology with coated gravel packing can reduce the flow capacity of water phase breaking into the dominant flow passage,so as to delay the rise of water production of gas well and prolong the gas production time.In this way,the gas recovery factor of bottom-water gas reservoir can be increased effectively.In conclusion,this technology has the function of spontaneous selective water plugging,i.e.,“water plugging in case of water and gas permeability in case of gas”,and its technical and economic advantages are remarkable,which can provide a new idea for the water-control development of deepsea bottom-water gas reservoirs.展开更多
After nearly 60 years of development,many old gasfields in the Sichuan Basin have come to middleelate development stages with low pressure and low yield,and some are even on the verge of abandonment,but there are plen...After nearly 60 years of development,many old gasfields in the Sichuan Basin have come to middleelate development stages with low pressure and low yield,and some are even on the verge of abandonment,but there are plenty remaining gas resources still undeveloped.Analysis shows that gasfields which have the conditions for the secondary development are faced with many difficulties.For example,it is difficult to produce low permeable reserves and to unset the hydraulic seal which is formed by active formation water.In this paper,therefore,the technical route and selection conditions of old gasfields for the secondary development were comprehensively elaborated with its definition as the beginning.Firstly,geological model forward modeling and production performance inversion characteristic curve diagnosis are performed by using the pressure normalization curve and the identification and quantitative description method for multiple sets of storageeseepage body of complex karst fractureecavity systems is put forward,after the multiple storageeseepage body mode of fractureecavity systems is established.Combined with the new occurrence mode of gas and water in U-shape pipes,a new calculation technology for natural gas reserves of multiple fractureecavity systems with strong water invasion is developed.Secondly,a numerical model of poreecavityefracture triple media is built,and simulation and result evaluation technology for the production pattern of“drainage by horizontal wells+gas production by vertical wells”in bottom-water fracture and cavity gas reservoirs with strong water invasion is developed.Thirdly,the geological model of gas reservoirs is reconstructed with the support of the integration technologies which are formed based onfine gas reservoir description.Low permeable reserves of gas reservoirs are evaluated based on each classification.The effective producing ratio is increased further by using the technologies of well pattern optimization,horizontal-well geosteering and staged acid fracturing.And fourthly,overall simulation,optimization and prediction technology for regional pipeline net-works is developed by building a multi-node multi-link gas transmission pipeline network model.Application shows that this technology plays an important role in productivity construction,recovery factor improvement,production decline delay and production stabilization of old gasfields.展开更多
The purpose of this experimental study is to evaluate the feasibility and oil recovery efficiency of continuous N_(2) injection in a multi-well fractured-cavity reservoir.In this study,the similar criterion of physica...The purpose of this experimental study is to evaluate the feasibility and oil recovery efficiency of continuous N_(2) injection in a multi-well fractured-cavity reservoir.In this study,the similar criterion of physical simulation was firstly discussed.In order to reveal the mechanism of remaining oil startup and production performance characteristic by continuous N_(2) injection,a visualized twodimensional fractured-cavity model and a three-dimensional pressure resistant model were designed and fabricated respectively based on the similar theory.And the 2D visualized physical experiments and 3D physical experiments were performed with the simulated oil and brine reservoir samples in Tahe oilfield.Four groups of experiments in 2D and 3D model were performed,each of which included bottom water depletion driving,water injection and N_(2) injection.The 2D visualized experiments indicated the main mechanism of N_(2) developing remaining oil was to occupy the high position and replace the attic oil due to gravitational differentiation.Furthermore,both the 2D and 3D experiments demonstrated that higher oil recovery factor could be achieved if N_(2) was injected through high positional wells.The 3D physical model is closer to the real reservoir condition,so the production performance can reflect the real field production process.This paper confirmed the efficiency of continuous N2 flooding in the light oil saturated fractured-cavity reservoir.展开更多
文摘Naturally fractured rocks contain most of the world's petroleum reserves.This significant amount of oil can be recovered efficiently by gas assisted gravity drainage(GAGD).Although,GAGD is known as one of the most effective recovery methods in reservoir engineering,the lack of available simulation and mathematical models is considerable in these kinds of reservoirs.The main goal of this study is to provide efficient and accurate methods for predicting the GAGD recovery factor using data driven techniques.The proposed models are developed to relate GAGD recovery factor to the various parameters including model height,matrix porosity and permeability,fracture porosity and permeability,dip angle,viscosity and density of wet and non-wet phases,injection rate,and production time.In this investigation,by considering the effective parameters on GAGD recovery factor,three different efficient,smart,and fast models including artificial neural network(ANN),least square support vector machine(LSSVM),and multi-gene genetic programming(MGGP)are developed and compared in both fractured and homogenous porous media.Buckinghamπtheorem is also used to generate dimensionless numbers to reduce the number of input and output parameters.The efficiency of the proposed models is examined through statistical analysis of R-squared,RMSE,MSE,ARE,and AARE.Moreover,the performance of the generated MGGP correlation is compared to the traditional models.Results demonstrate that the ANN model predicts the GAGD recovery factor more accurately than the LSSVM and MGGP models.The maximum R^(2)of 0.9677 and minimum RMSE of 0.0520 values are obtained by the ANN model.Although the MGGP model has the lowest performance among the other used models(the R2 of 0.896 and the RMSE of 0.0846),the proposed MGGP correlation can predict the GAGD recovery factor in fractured and homogenous reservoirs with high accuracy and reliability compared to the traditional models.Results reveal that the employed models can easily predict GAGD recovery factor without requiring complicate governing equations or running complex and time-consuming simulation models.The approach of this research work improves our understanding about the most significant parameters on GAGD recovery and helps to optimize the stages of the process,and make appropriate economic decisions.
基金Supported by CNPC Science and Technology Project(kt2022-8-202021ZZ01).
文摘Based on practices of CO_(2) flooding tests in China and abroad,the recovery factor of carbon dioxide capture,utilization in displacing oil and storage(CCUS-EOR)in permanent sequestration scenario has been investigated in this work.Under the background of carbon neutrality,carbon dioxide injection into geological bodies should pursue the goal of permanent sequestration for effective carbon emission reduction.Hence,CCUS-EOR is an ultimate development method for oil reservoirs to maximize oil recovery.The limit recovery factor of CCUS-EOR development mode is put forward,the connotation differences between it and ultimate recovery factor and economically reasonable recovery factor are clarified.It is concluded that limit recovery factor is achievable with mature supporting technical base for the whole process of CCUS-EOR.Based on statistics of practical data of CO_(2) flooding projects in China and abroad such as North H79 block CO_(2) flooding pilot test at small well spacing in Jilin Oilfield etc.,the empirical relationship between the oil recovery factor of miscible CO_(2) flooding and cumulative CO_(2) volume injected is obtained by regression.Combined with the concept of oil production rate multiplier of gas flooding,a reservoir engineering method calculating CO_(2) flooding recovery factor under any miscible degree is established by derivation.It is found that when the cumulative CO_(2) volume injected is 1.5 times the hydrocarbon pore volume(HCPV),the relative deviation and the absolute difference between the recovery percentage and the limit recovery factor are less than 5%and less than 2.0 percentage points respectively.The limit recovery factor of CCUS-EOR can only be approached by large pore volume(PV)injection based on the technology of expanding swept volume.It needs to be realized from three aspects:large PV injection scheme design,enhancing miscibility degree and continuously expanding swept volume of injected CO_(2).
基金the National Natural Science Foundation of China(Grant Nos.51725902,52009095,U2040215,U2240206,and 52109098)supported partly by the Postdoctoral Research Foundation of China(Grant No.BX2021228)Natural Science Foundation of Hubei Province(Grant No.2021CFA029)。
文摘Suspended sediment concentrations in the Middle Yangtze River(MYR)reduced greatly after the Three Gorges Project operation,causing the composition of bed material to coarsen continuously.However,little is known about the non-equilibrium transport of graded suspended sediment owing to different bed material compositions(BMCs)along the MYR,and it is necessary to determine the magnitude of recovery factor.Using the Markov stochastic process in conjunction with the hiding-exposure effect of non-uniform bed-material,a new formula is proposed for calculating the recovery factor including the effect of different BMCs,and it is incorporated into the non-equilibrium transport equation to simulate the recovery processes of suspended load in both sand-gravel bed and sand bed reaches of the MYR.The results show that:(i)the recovery rate of graded sediment concentrations at Zhicheng was slower than that at Shashi during the period 2003-2007;(ii)the mean recovery factors of the coarse,medium,and fine sediment fractions in the ZhichengShashi reach were 0.152,0.0012,and 0.0005,respectively,and the coarse sediment recovered up to the maximum sediment concentration of 0.138 kg/m3over a distance of 15 km;and(iii)the results of the new formula that can consider the effect of bed material composition are in general agreement with the field observations,and the spatial and temporal delay effects are inversely related to particle size and BMC.Consequently,the BMC effect on the nonequilibrium sediment transport in different reaches of the MYR needs to be considered for higher simulation accuracy.
基金Supported by the National Natural Science Foundation of China(51974268)the Sichuan Province Science and Technology Program(2019YJ0423)。
文摘A novel type curve is presented for oil recovery factor prediction suitable for gas flooding by innovatively introducing the equivalent water-gas cut to replace the water cut,comprehensively considering the impact of three-phase flow(oil,gas,water),and deriving the theoretical equations of gas flooding type curve based on Tong’s type curve.The equivalent water-gas cut is the ratio of the cumulative underground volume of gas and water production to the total underground volume of produced fluids.Field production data and the numerical simulation results are used to demonstrate the feasibility of the new type curve and verify the accuracy of the prediction results with field cases.The new type curve is suitable for oil recovery factor prediction of both water flooding and gas flooding.When a reservoir has no gas injected or produced,the gas phase can be ignored and only the oil and water phases need to be considered,in this case,this gas flooding type curve returns to the Tong’s type curve,which can evaluate the oil recovery factor of water flooding.For reservoirs with equivalent water-gas cuts of 60%-80%,the regression method of the new type curve works well in predicting the oil recovery factor.For reservoirs with equivalent water-gas cuts higher than 80%,both the regression and assignment methods of the new type curve can accurately predict the oil recovery factor of gas flooding.
基金This work was supported by National Natural Science Foundation of China(No.51404205)Open Fund(PLN 1207)of State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation(Southwest Petroleum University)Innovation team project of Sichuan Provincial Department of Education(No.16TD0010).
文摘Oil recovery factor is one of the most important parameters in the development process of oil reservoir,especially in the low-permeability reservoir.In general,the determination of recovery factor can be obtained either experimentally or numerically.Experimental method is often timeconsuming and expensive,while numerical method has been always confined to narrow range of application or relatively large error.Recently,an intelligent method has been proven as an efficient tool to model the complex and nonlinear phenomena.In this work,an intelligent model based on support vector machine in combination with the particle swarm optimization(PSO-SVM)technique was established to predict oil recovery factor in the low-permeability reservoir.Input variables of the proposed PSO-SVM model with the aid of a grey correlation analysis method are permeability,well spacing density,production-injection well ratio,porosity,effective thickness,crude oil viscosity and output parameter is oil recovery factor of low-permeability reservoir.The accuracy and reliability of the proposed model were evaluated through 34 data sets collected in the open literature and compared with PSO-BP neural network,empirical method from Oil and Gas Company.The results indicated that the PSO-SVM model gives the best results with average absolute relative deviation(AARD)of 3.79%,while AARDs for the PSO-BP neural network and empirical method are 9.18%and 10.0%,respectively.Furthermore,outlier detection was used on the basis of whole data sets to definite the valid domains of PSO-SVM and PSO-BP models by detecting the probable doubtful recovery factor data in the low-permeability reservoir.
基金The work of Evgeny Burnaev in Sections was supported by Ministry of Science and Higher Education grant No.075-10-2021-068.
文摘Well-known oil recovery factor estimation techniques such as analogy,volumetric calculations,material balance,decline curve analysis,hydrodynamic simulations have certain limitations.Those techniques are time-consuming,and require specific data and expert knowledge.Besides,though uncertainty estimation is highly desirable for this problem,the methods above do not include this by default.In this work,we present a data-driven technique for oil recovery factor(limited to water flooding)estimation using reservoir parameters and representative statistics.We apply advanced machine learning methods to historical worldwide oilfields datasets(more than 2000 oil reservoirs).The data-driven model might be used as a general tool for rapid and completely objective estimation of the oil recovery factor.In addition,it includes the ability to work with partial input data and to estimate the prediction interval of the oil recovery factor.We perform the evaluation in terms of accuracy and prediction intervals coverage for several tree-based machine learning techniques in application to the following two cases:(1)using parameters only related to geometry,geology,transport,storage and fluid properties,(2)using an extended set of parameters including development and production data.For both cases,the model proved itself to be robust and reliable.We conclude that the proposed data-driven approach overcomes several limitations of the traditional methods and is suitable for rapid,reliable and objective estimation of oil recovery factor for hydrocarbon reservoir.
基金financial support from the Major Scientific and Technological Projects of CNPC under Grant(ZD2019-183-007)is gratefully acknowledge.
文摘The double-network prepared with an in-situ monomer gel and a fast-crosslinked Cr(III) gel is introduced to develop a thixotropic and high-strength gel (THSG), which is found to have many advantages over the traditional gels. The THSG gel demonstrates remarkable thermal stability, and no syneresis is observed after 12 months with high salinity brine (95,500 mg/L). Moreover, the SEM and XRD results indicate that the gel is intercalated into the lamellar structures of Na-MMT, where the gel can form a uniform and compact structure. In addition, the THSG gel has an excellent swelling behavior, even in the high salinity brine. In the slim tube experiments, the THSG gel exhibits high rupture pressure and improves blocking capacity after being ruptured. The core flooding results show that a layer of gel filter cake is formed on the face of the fracture, which may be promoted by a high matrix permeability, a small aperture fracture, and a high injection rate. After the gel treatment, the fracture can be completely blocked by the THSG gel. It is found that a high incremental oil recovery (65.3%) can be achieved when the fracture was completely blocked, compared to 40.2% if the gel is ruptured. Although the swelling of ruptured gel can improve oil recovery, part of the injected brine may be channeled through the gel-filled fractures, resulting in a decrease in the sweep efficiency. Therefore, the improved blocking ability by gel swelling (e.g., in fresh water) may be less efficient to contribute to an enhancement of oil recovery. It is also found that the pressure gradient and residual resistance factor to water (Frrw) are higher if the matrix is less permeable, indicating that the fractured reservoir with lower matrix permeability may require a higher gel strength for treatment. The findings of this study may provide novel insights on designing robust double network gels for water shutoff in fractured reservoirs.
基金Project supported by the National Major Scientific and Technological Project,“Demonstration Project of Large Low-permeability Lithologic-stratigraphic Oil and Gas Reservoirs in Ordos Basin”(Grant No.2011ZX05044)the CNPC Scientific Research and Technical Development Project,“Major Engineering Technologies for Development of Tight Gas Reservoirs”(Grant No.2012E-1306).
文摘Based on the exploration and development achievements of the Sulige Gasfield in the Ordos Basin,tight sandstone gas yield has been increased essentially in China.Recovery enhancement is always the core subject in researches.In this paper,the development history of the Sulige Gasfield was reviewed focusing on the technological progress in single well production enhancement.Then,the technical ideas on and countermeasures for transforming the traditional development modes and increasing recovery factor were discussed.It is shown that the development technologies in the evaluation and the production enhancement and stabilization of giant tight sandstone gas reservoirs are changed progressively.The fast increase of gas production in this field is made possible by well location arrangement technology based on sweep spot screening,horizontal well development technology,well type and well pattern optimization technology,fast drilling technology,reservoir stimulation technology,drainage gas recovery technology and integrated construction mode.And finally,the technical ideas of recovery enhancement during the 13th Five-Year Plan were proposed in nine aspects,including gas field development,planning and evaluation technology based on single-well life cycle analysis;dynamic evaluation and infilling technology for mixed well patterns targeting recovery enhancement;one-shot recovery enhancement technology for a new areal pattern area with integrated multiple well patterns and multiple series of strata;reserve evaluation model based on risk and benefit evaluation;gas-well precise management technology with multi-dimensional matrix;potential tapping technology for low production and low efficiency wells;novel wellsite environmental protection technology;surface process based on integrated equipments;and C_(3)^(+)mixed hydrocarbon recovery technology.It provides technically reliable support for the development of tight sandstone gas reservoirs in the Sulige Gasfield during the 13th Five-Year Plan.
文摘The current in the production and living of people, there are more and more demand for oil and gas energy, in such cases, the need to fundamentally effectively do a good job in the development of oil and gas fields and harvest at the same time in the process of practice to fully grasp all kinds of factors affect recovery efficiency of oil and gas field development, and then to handle, tangible and fundamentally improve the development of oil and gas field recovery. Combined with this situation, this paper focuses on the analysis of various factors affecting oil and gas field development and recovery factors and relevant measures.
基金Supported by the Sinopec"Ten Dragon"Major ProjectKey Research Projects of Sinopec(P22180)。
文摘There are various issues for CO_(2)flooding and storage in Shengli Oilfield,which are characterized by low light hydrocarbon content of oil and high miscible pressure,strong reservoir heterogeneity and low sweep efficiency,gas channeling and difficult whole-process control.Through laboratory experiments,technical research and field practice,the theory and technology of CO_(2)high pressure miscible flooding and storage are established.By increasing the formation pressure to 1.2 times the minimum miscible pressure,the miscibility of the medium-heavy components can be improved,the production percentage of oil in small pores can be increased,the displacing front developed evenly,and the swept volume expanded.Rapid high-pressure miscibility is realized through advanced pressure flooding and energy replenishment,and technologies of cascade water-alternating-gas(WAG),injection and production coupling and multistage chemical plugging are used for dynamic control of flow resistance,so as to obtain the optimum of oil recovery and CO_(2)storage factor.The research results have been applied to the Gao89-Fan142 in carbon capture,utilization and storage(CCUS)demonstration site,where the daily oil production of the block has increased from 254.6 t to 358.2 t,and the recovery degree is expected to increase by 11.6 percentage points in 15 years,providing theoretical and technical support for the large-scale development of CCUS.
基金sponsored by Fundação de Amparoa Pesquisa do Estado de São Paulo(FAPESP)(2014/50279-4,2020/15230-5,2021/06158-1)Shell Brasil.
文摘São Paulo State has witnessed CO_(2)storage-based investigations considering the availability of suitable geologic structures and proximity to primary CO_(2)source sinks related to bioenergy and carbon capture and storage(BECCS)activities.The current study presents the hydrocarbon viability evaluations and CO_(2)storage prospects,focusing on the sandstone units of the Rio Bonito Formation.The objective is to apply petrophysical evaluations with geochemical inputs in predicting future hydrocarbon(gas)production to boost CO_(2)storage within the study location.The study used data from eleven wells with associated wireline logs(gamma ray,resistivity,density,neutron,and sonic)to predict potential hydrocarbon accumulation and fluid mobility in the investigated area.Rock samples(shale and carbonate)obtained from depths>200 m within the study location have shown bitumen presence.Organic geochemistry data of the Rio Bonito Formation shale beds suggest they are potential hydrocarbon source rocks and could have contributed to the gas accumulations within the sandstone units.Some drilled well data,e.g.,CB-1-SP and TI-1-SP,show hydrocarbon(gas)presence based on the typical resistivity and the combined neutron-density responses at depths up to 3400 m,indicating the possibility of other hydrocarbon members apart from the heavy oil(bitumen)observed from the near-surface rocks samples.From the three-dimensional(3-D)model,the free fluid indicator(FFI)is more significant towards the southwest and southeast of the area with deeper depths of occurrence,indicating portions with reasonable hydrocarbon recovery rates and good prospects for CO_(2)injection,circulation and permanent storage.However,future studies based on contemporary datasets are required to establish the hydrocarbon viability further,foster gas production events,and enhance CO_(2)storage possibilities within the region.
基金Project(2016ZX05017)supported by the China National Science and Technology Major Project
文摘Water invasion is a common phenomenon in gas reservoirs with active edge-and-bottom aquifers.Due to high reservoir heterogeneity and production parameters,carbonate gas reservoirs feature exploitation obstacles and low recovery factors.In this study,combined core displacement and nuclear magnetic resonance(NMR)experiments explored the reservoir gas−water two-phase flow and remaining microscopic gas distribution during water invasion and gas injection.Consequently,for fracture core,the water-phase relative permeability is higher and the co-seepage interval is narrower than that of three pore cores during water invasion,whereas the water-drive recovery efficiency at different invasion rates is the lowest among all cores.Gas injection is beneficial for reducing water saturation and partially restoring the gas-phase relative permeability,especially for fracture core.The remaining gas distribution and the content are related to the core properties.Compared with pore cores,the water invasion rate strongly influences the residual gas distribution in fracture core.The results enhance the understanding of the water invasion mechanism,gas injection to resume production and the remaining gas distribution,so as to improve the recovery factors of carbonate gas reservoirs.
基金the financial support provided by the Guangdong Major Project of Basic and Applied Basic Research(Grant No.2020B0301030003)supported by the Department of Science and Technology of Guangdong Province,as well as project(DD20221703)supported by the China Geological Survey。
文摘Since the implementation of several pilot production tests were in natural gas hydrate(NGH) reservoirs in terrestrial and marine settings, the study of NGH has entered a new stage of technological development for industrial exploitation. Prior to the industrial exploitation of any given NGH reservoir, the economic feasibility should be examined. The first step of economic evaluation of a NGH reservoir is to know whether its resource amount meets the requirement for industrial exploitation. Unfortunately, few relevant studies have been conducted in this regard. In this study, the net present value(NPV) method is employed to estimate the economic critical resources required for the industrial exploitation of NGHs under different production scenarios. Sensitivity analysis is also performed in order to specify the effects of key factors, such as the number of production wells, gas price, technological improvement and tax incentive, on the economic critical resources. The results indicate that China requires the lowest economic critical resource for a NGH reservoir to be industrially exploited, ranging from 3.62 to 24.02 billion m3 methane. Changes in gas price and tax incentives also play significant roles in affecting the threshold and timeline for the industrial exploitation of NGH.
基金Project(50150503-12)supported by National Science and Technology Major Program of the Ministry of Science and Technology of ChinaProject(2010E-2103)supported by Research on Key Technology in Tarim Oilfield Exploration and Development,China
文摘The problem of water coning into the Tarim fractured sandstone gas reservoirs becomes one of the major concerns in terms of productivity, increased operating costs and environmental effects. Water coning is a phenomenon caused by the imbalance between gravity and viscous forces around the completion interval. There are several controllable and uncontrollable parameters influencing this problem. In order to simulate the key parameters affecting the water coning phenomenon, a model was developed to represent a single well with an underlying aquifer using the fractured sandstone gas reservoir data of the A-Well in Dina gas fields.The parametric study was performed by varying six properties individually over a representative range. The results show that matrix permeability, well penetration(especially fracture permeability), vertical-to-horizontal permeability ratio, aquifer size and gas production rate have considerable effect on water coning in the fractured gas reservoirs. Thus, investigation of the effective parameters is necessary to understand the mechanism of water coning phenomenon. Simulation of the problem helps to optimize the conditions in which the breakthrough of water coning is delayed.
文摘Given the rise in oil productivity from conventional and unconventional resources in Canada using Enhanced Oil Recovery (EOR), the need to understand and characterize these techniques, for the purpose of recovery optimization, has taken a prominent role in resource management. Chemical flooding has proved to be one of the most efficient EOR techniques. This study investigated the potential of employing Ionic Liquids (ILs) as alternative chemical agents for improving oil recovery. There is very little attention paid to employing this technique as well as few experimental and simulation studies. Consequently, very limited data are available. Since pilot and field studies are relatively expensive and time consuming, a numerical simulation study using CMG-STARS simulator was utilized to explore the efficiency of employing 1-Ethyl-3-Methyl-Imidazolium Acetate ([EMIM][Ac]) and 1-Benzyl-3-meth- limidazolium chloride ([BenzMIM][Cl]) with respect to improving medium oil recovery. Eight different lab-scale sandpack flooding experiments were selected to develop a numerical model to obtain the history matching of the experimental flooding results using CMG-CMOST. We observed that the main challenge was tuning the relative permeability curves to achieve a successful match for the oil recovery factor. Finally, a sensitivity study was performed to examine the effect of the chemical injection rate, the chemical concentration, the slug size, and the initiation time on oil recovery. The results showed a noticeable increase in the oil RF when injecting IL compared to conventional waterflooding.
文摘Description is given to preparation of three ionic liquid surfactants containing amine functional groups, characterization of their functional groups using the infrared spectrometer, determination of their surface tension and the oil displacement test in this paper to investigate the effect of alkane branch chains with different carbon numbers on the surface tension and the displacement efficiency. The result shows that, the surfactants exhibit the structural characteristic of the ionic liquid as the characteristic absorption peaks occur on C-N and C-H of the imidazole rings at the wave numbers of 1338cm-1, 1234em-1, 1465crn-1 and 3142cm-1, respectively. The surface tension isothermal curves and the oil displacem ent test proved that the ionic liquid imidazole surfactants with shorter-chain groups are more active on surface, with the minimal surface tension up to 32.5 mN/m, and led to higher displacement efficiency, increasing by 3.3% at the concentration of 1000mg/L compared with the water flooding.
基金Project supported by National Major Science and Technology Project“Effective techniques for commercial production of low-permeability low-abundance sandstone gas reservoirs”(Grant No.2011ZX05015-001).
文摘An outstanding issue in the oil and gas industry is how to evaluate quantitatively the influences of water production on production per-formance of gas wells.Based on gasewater flow theories,therefore,a new method was proposed in this paper to evaluate quantitatively the production performance of water-producing gas wells by using gas&water relative permeability curves after a comparative study was conducted thoroughly.In this way,quantitative evaluation was performed on production capacity,gas production,ultimate cumulative gas production and recovery factor of water-producing gas wells.Then,a case study was carried out of the tight sandstone gas reservoirs with strong heterogeneity in the Sulige gas field,Ordos Basin.This method was verified in terms of practicability and reliability through a large amount of calculation based on the actual production performance data of various gas wells with different volumes of water produced.Finally,empirical formula and charts were established for water-producing gas wells in this field to quantitatively evaluate their production capacity,gas production,ultimate cumulative gas production and recovery factor in the conditions of different wateregas ratios.These formula and charts provide technical support for the field application and dissemination of the method.Study results show that water production is serious in the west of this field with wateregas ratio varying in a large range.If the average wateregas ratio is 1.0(or 2.0)m^(3)/10^(4) m^(3),production capacity,cumulative gas pro-duction and recovery factor of gas wells will be respectively 24.4%(or 40.2%),24.4%(or 40.2%)and 17.4%(or 33.2%).
基金Project supported by Scientific and Technological Project of CNOOC(China)Limited“Study on Key Drilling and Completion Technologies for Deepwater Development Well”(No.:CNOOC-KJ 135 ZDXM 05 LTD 01 SHENHAI 2016).
文摘In order to find an economic and effective water control method for horizontal wells in deep sea bottom-water gas reservoirs,we prepared modified coated gravel.Based on this,wear resistance,temperature resistance and water plugging capacity(WPC)tests were carried out on the coated gravel.Then,experiments were carried out using the 3D simulation device for the development of large-scale bottom-water gas reservoirs to compare the development effects of horizontal wells packed with conventional gravel and coated gravel in deepsea bottom-water gas reservoirs.And the following research results were obtained.First,the upper limit of temperature resistance of the gravel coating is 240℃ and the gravel packing speed can reach 4.48 m/s,which is 8 times the average flow velocity of gravel packing in actual open hole sections.Second,as the permeability of the coated gravel packing layer increases,its WPC gets weak.When the permeability is lower than 1500 mD and the displacement pressure difference is lower than 0.6 MPa,the WPC of the coated gravel packing layer is between 0.17 and 0.68.Third,the coated gravel layer functions as gas permeability and water plugging,so the horizontal well technology with coated gravel packing can reduce the flow capacity of water phase breaking into the dominant flow passage,so as to delay the rise of water production of gas well and prolong the gas production time.In this way,the gas recovery factor of bottom-water gas reservoir can be increased effectively.In conclusion,this technology has the function of spontaneous selective water plugging,i.e.,“water plugging in case of water and gas permeability in case of gas”,and its technical and economic advantages are remarkable,which can provide a new idea for the water-control development of deepsea bottom-water gas reservoirs.
基金supported by the Scientific Rescarch Project of PetroChina Explonation&Production Company“Overall Plan of PetroChina Southwest Oil&Gas Field Company for Secondary Development of Gas Fields”(No.20100305-04).
文摘After nearly 60 years of development,many old gasfields in the Sichuan Basin have come to middleelate development stages with low pressure and low yield,and some are even on the verge of abandonment,but there are plenty remaining gas resources still undeveloped.Analysis shows that gasfields which have the conditions for the secondary development are faced with many difficulties.For example,it is difficult to produce low permeable reserves and to unset the hydraulic seal which is formed by active formation water.In this paper,therefore,the technical route and selection conditions of old gasfields for the secondary development were comprehensively elaborated with its definition as the beginning.Firstly,geological model forward modeling and production performance inversion characteristic curve diagnosis are performed by using the pressure normalization curve and the identification and quantitative description method for multiple sets of storageeseepage body of complex karst fractureecavity systems is put forward,after the multiple storageeseepage body mode of fractureecavity systems is established.Combined with the new occurrence mode of gas and water in U-shape pipes,a new calculation technology for natural gas reserves of multiple fractureecavity systems with strong water invasion is developed.Secondly,a numerical model of poreecavityefracture triple media is built,and simulation and result evaluation technology for the production pattern of“drainage by horizontal wells+gas production by vertical wells”in bottom-water fracture and cavity gas reservoirs with strong water invasion is developed.Thirdly,the geological model of gas reservoirs is reconstructed with the support of the integration technologies which are formed based onfine gas reservoir description.Low permeable reserves of gas reservoirs are evaluated based on each classification.The effective producing ratio is increased further by using the technologies of well pattern optimization,horizontal-well geosteering and staged acid fracturing.And fourthly,overall simulation,optimization and prediction technology for regional pipeline net-works is developed by building a multi-node multi-link gas transmission pipeline network model.Application shows that this technology plays an important role in productivity construction,recovery factor improvement,production decline delay and production stabilization of old gasfields.
基金The authors wish to thank the National Natural Science Foundation of China(NO.51174216)State Key Science&Technology Project of China(NO.2011ZX05009-004 and NO.2011ZX05052)for their financial support to carry out this research.The insightful and constructive comments of the anonymous reviewers are also gratefully acknowledged.
文摘The purpose of this experimental study is to evaluate the feasibility and oil recovery efficiency of continuous N_(2) injection in a multi-well fractured-cavity reservoir.In this study,the similar criterion of physical simulation was firstly discussed.In order to reveal the mechanism of remaining oil startup and production performance characteristic by continuous N_(2) injection,a visualized twodimensional fractured-cavity model and a three-dimensional pressure resistant model were designed and fabricated respectively based on the similar theory.And the 2D visualized physical experiments and 3D physical experiments were performed with the simulated oil and brine reservoir samples in Tahe oilfield.Four groups of experiments in 2D and 3D model were performed,each of which included bottom water depletion driving,water injection and N_(2) injection.The 2D visualized experiments indicated the main mechanism of N_(2) developing remaining oil was to occupy the high position and replace the attic oil due to gravitational differentiation.Furthermore,both the 2D and 3D experiments demonstrated that higher oil recovery factor could be achieved if N_(2) was injected through high positional wells.The 3D physical model is closer to the real reservoir condition,so the production performance can reflect the real field production process.This paper confirmed the efficiency of continuous N2 flooding in the light oil saturated fractured-cavity reservoir.
