Experimental Investigation on Condensate Revaporization During Gas Injection Development in Fractured Gas Condensate Reservoirs

The gas field in the Bohai Bay Basin is a fractured metamorphic buried-hill reservoir with dual-media characteristics. The retrograde vaporization mechanism observed in this type of gas condensate reservoir differs significantly from that observed in sand gas condensate reservoirs. However, studies on improving the recovery of fractured gas condensate reservoirs are limited;thus, the impact of retrograde vaporization on condensate within fractured metamorphic buried-hill reservoirs remains unclear. To address this gap, a series of gas injection experiments are conducted in pressure-volume-temperature(PVT) cells and long-cores to investigate the retrograde vaporization effect of condensate using different gas injection media in fractured gas condensate reservoirs. We analyze the variation in condensate volume, gas-to-oil ratio, and condensate recovery during gas injection and examine the influence of various gas injection media(CO_(2), N_(2), and dry gas) under different reservoir properties and varying gas injection times. The results demonstrate that the exchange of components between injected gas and condensate significantly influences condensate retrograde vaporization in the formation. Compared with dry gas injection and N_(2) injection,CO_(2) injection exhibits a superior retrograde vaporization effect. At a CO_(2) injection volume of 1 PV, the percentage shrinkage volume of condensate is 13.82%. Additionally, at the maximum retrograde condensation pressure, CO_(2) injection can increase the recovery of condensate by 22.4%. However, the condensate recovery is notably lower in fractured gas condensate reservoirs than in homogeneous reservoirs, owing to the creation of dominant gas channeling by fractures, which leads to decreased condensate recovery. Regarding gas injection timing, the effect of gas injection at reservoir pressure on improving condensate recovery is superior to that of gas injection at the maximum retrograde condensation pressure. This research provides valuable guidance for designing gas injection development plans and dynamic tracking adjustments for fractured gas condensate reservoirs.

Evaluation of Well Spacing for Primary Development of Fractured Horizontal Wells in Tight Sandstone Gas Reservoirs

Methods for horizontal well spacing calculation in tight gas reservoirs are still adversely affected by the complexity of related control factors,such as strong reservoir heterogeneity and seepage mechanisms.In this study,the stress sensitivity and threshold pressure gradient of various types of reservoirs are quantitatively evaluated through reservoir seepage experiments.On the basis of these experiments,a numerical simulation model(based on the special seepage mechanism)and an inverse dynamic reserve algorithm(with different equivalent drainage areas)were developed.The well spacing ranges of Classes I,II,and III wells in the Q gas field are determined to be 802–1,000,600–662,and 285–400 m,respectively,with their average ranges as 901,631,and 342.5 m,respectively.By considering both the pairs of parallel well groups and series well groups as examples,the reliability of the calculation results is verified.It is shown that the combination of the two models can reduce errors and provide accurate results.

A multi-mechanism numerical simulation model for CO_(2)-EOR and storage in fractured shale oil reservoirs

Under the policy background and advocacy of carbon capture,utilization,and storage(CCUS),CO_(2)-EOR has become a promising direction in the shale oil reservoir industry.The multi-scale pore structure distribution and fracture structure lead to complex multiphase flow,comprehensively considering multiple mechanisms is crucial for development and CO_(2) storage in fractured shale reservoirs.In this paper,a multi-mechanism coupled model is developed by MATLAB.Compared to the traditional Eclipse300 and MATLAB Reservoir Simulation Toolbox(MRST),this model considers the impact of pore structure on fluid phase behavior by the modified Peng—Robinson equation of state(PR-EOS),and the effect simultaneously radiate to Maxwell—Stefan(M—S)diffusion,stress sensitivity,the nano-confinement(NC)effect.Moreover,a modified embedded discrete fracture model(EDFM)is used to model the complex fractures,which optimizes connection types and half-transmissibility calculation approaches between non-neighboring connections(NNCs).The full implicit equation adopts the finite volume method(FVM)and Newton—Raphson iteration for discretization and solution.The model verification with the Eclipse300 and MRST is satisfactory.The results show that the interaction between the mechanisms significantly affects the production performance and storage characteristics.The effect of molecular diffusion may be overestimated in oil-dominated(liquid-dominated)shale reservoirs.The well spacing and injection gas rate are the most crucial factors affecting the production by sensitivity analysis.Moreover,the potential gas invasion risk is mentioned.This model provides a reliable theoretical basis for CO_(2)-EOR and sequestration in shale oil reservoirs.

A review of reservoir damage during hydraulic fracturing of deep and ultra-deep reservoirs

Deep and ultra-deep reservoirs have gradually become the primary focus of hydrocarbon exploration as a result of a series of significant discoveries in deep hydrocarbon exploration worldwide.These reservoirs present unique challenges due to their deep burial depth(4500-8882 m),low matrix permeability,complex crustal stress conditions,high temperature and pressure(HTHP,150-200℃,105-155 MPa),coupled with high salinity of formation water.Consequently,the costs associated with their exploitation and development are exceptionally high.In deep and ultra-deep reservoirs,hydraulic fracturing is commonly used to achieve high and stable production.During hydraulic fracturing,a substantial volume of fluid is injected into the reservoir.However,statistical analysis reveals that the flowback rate is typically less than 30%,leaving the majority of the fluid trapped within the reservoir.Therefore,hydraulic fracturing in deep reservoirs not only enhances the reservoir permeability by creating artificial fractures but also damages reservoirs due to the fracturing fluids involved.The challenging“three-high”environment of a deep reservoir,characterized by high temperature,high pressure,and high salinity,exacerbates conventional forms of damage,including water sensitivity,retention of fracturing fluids,rock creep,and proppant breakage.In addition,specific damage mechanisms come into play,such as fracturing fluid decomposition at elevated temperatures and proppant diagenetic reactions at HTHP conditions.Presently,the foremost concern in deep oil and gas development lies in effectively assessing the damage inflicted on these reservoirs by hydraulic fracturing,comprehending the underlying mechanisms,and selecting appropriate solutions.It's noteworthy that the majority of existing studies on reservoir damage primarily focus on conventional reservoirs,with limited attention given to deep reservoirs and a lack of systematic summaries.In light of this,our approach entails initially summarizing the current knowledge pertaining to the types of fracturing fluids employed in deep and ultra-deep reservoirs.Subsequently,we delve into a systematic examination of the damage processes and mechanisms caused by fracturing fluids within the context of hydraulic fracturing in deep reservoirs,taking into account the unique reservoir characteristics of high temperature,high pressure,and high in-situ stress.In addition,we provide an overview of research progress related to high-temperature deep reservoir fracturing fluid and the damage of aqueous fracturing fluids to rock matrix,both artificial and natural fractures,and sand-packed fractures.We conclude by offering a summary of current research advancements and future directions,which hold significant potential for facilitating the efficient development of deep oil and gas reservoirs while effectively mitigating reservoir damage.

Hydrocarbon gas huff-n-puff optimization of multiple horizontal wells with complex fracture networks in the M unconventional reservoir

The oil production of the multi-fractured horizontal wells(MFHWs) declines quickly in unconventional oil reservoirs due to the fast depletion of natural energy. Gas injection has been acknowledged as an effective method to improve oil recovery factor from unconventional oil reservoirs. Hydrocarbon gas huff-n-puff becomes preferable when the CO_(2) source is limited. However, the impact of complex fracture networks and well interference on the EOR performance of multiple MFHWs is still unclear. The optimal gas huff-n-puff parameters are significant for enhancing oil recovery. This work aims to optimize the hydrocarbon gas injection and production parameters for multiple MFHWs with complex fracture networks in unconventional oil reservoirs. Firstly, the numerical model based on unstructured grids is developed to characterize the complex fracture networks and capture the dynamic fracture features.Secondly, the PVT phase behavior simulation was carried out to provide the fluid model for numerical simulation. Thirdly, the optimal parameters for hydrocarbon gas huff-n-puff were obtained. Finally, the dominant factors of hydrocarbon gas huff-n-puff under complex fracture networks are obtained by fuzzy mathematical method. Results reveal that the current pressure of hydrocarbon gas injection can achieve miscible displacement. The optimal injection and production parameters are obtained by single-factor analysis to analyze the effect of individual parameter. Gas injection time is the dominant factor of hydrocarbon gas huff-n-puff in unconventional oil reservoirs with complex fracture networks. This work can offer engineers guidance for hydrocarbon gas huff-n-puff of multiple MFHWs considering the complex fracture networks.

Study on the Impact of Massive Refracturing on the Fracture Network in Tight Oil Reservoir Horizontal Wells

Class III tight oil reservoirs have low porosity and permeability,which are often responsible for low production rates and limited recovery.Extensive repeated fracturing is a well-known technique to fix some of these issues.With such methods,existing fractures are refractured,and/or new fractures are created to facilitate communication with natural fractures.This study explored how different refracturing methods affect horizontal well fracture networks,with a special focus on morphology and related fluid flow changes.In particular,the study relied on the unconventional fracture model(UFM).The evolution of fracture morphology and flow field after the initial fracturing were analyzed accordingly.The simulation results indicated that increased formation energy and reduced reservoir stress differences can promote fracture expansion.It was shown that the length of the fracture network,the width of the fracture network,and the complexity of the fracture can be improved,the oil drainage area can be increased,the distance of oil and gas seepage can be reduced,and the production of a single well can be significantly increased.

Extended finite element-based cohesive zone method for modeling simultaneous hydraulic fracture height growth in layered reservoirs

In this study,a fully coupled hydromechanical model within the extended finite element method(XFEM)-based cohesive zone method(CZM)is employed to investigate the simultaneous height growth behavior of multi-cluster hydraulic fractures in layered porous reservoirs with modulus contrast.The coupled hydromechanical model is first verified against an analytical solution and a laboratory experiment.Then,the fracture geometry(e.g.height,aperture,and area)and fluid pressure evolutions of multiple hydraulic fractures placed in a porous reservoir interbedded with alternating stiff and soft layers are investigated using the model.The stress and pore pressure distributions within the layered reservoir during fluid injection are also presented.The simulation results reveal that stress umbrellas are easily to form among multiple hydraulic fractures’tips when propagating in soft layers,which impedes the simultaneous height growth.It is also observed that the impediment effect of soft layer is much more significant in the fractures suppressed by the preferential growth of adjoining fractures.After that,the combined effect of in situ stress ratio and fracturing spacing on the multi-fracture height growth is presented,and the results elucidate the influence of in situ stress ratio on the height growth behavior depending on the fracture spacing.Finally,it is found that the inclusion of soft layers changes the aperture distribution of outmost and interior hydraulic fractures.The results obtained from this study may provide some insights on the understanding of hydraulic fracture height containment observed in filed.

A Novel Fracturing Fluid with High-Temperature Resistance for Ultra-Deep Reservoirs

Ultra-deep reservoirs play an important role at present in fossil energy exploitation.Due to the related high temperature,high pressure,and high formation fracture pressure,however,methods for oil well stimulation do not produce satisfactory results when conventional fracturing fluids with a low pumping rate are used.In response to the above problem,a fracturing fluid with a density of 1.2~1.4 g/cm^(3)was developed by using Potassium formatted,hydroxypropyl guanidine gum and zirconium crosslinking agents.The fracturing fluid was tested and its ability to maintain a viscosity of 100 mPa.s over more than 60 min was verified under a shear rate of 1701/s and at a temperature of 175℃.This fluid has good sand-carrying performances,a low viscosity after breaking the rubber,and the residue content is less than 200 mg/L.Compared with ordinary reconstruction fluid,it can increase the density by 30%~40%and reduce the wellhead pressure of 8000 m level reconstruction wells.Moreover,the new fracturing fluid can significantly mitigate safety risks.

An Integrated Optimization Method for CO_(2) Pre-Injection during Hydraulic Fracturing in Heavy Oil Reservoirs

CO_(2) pre-injection during hydraulic fracturing is an important method for the development of medium to deep heavy oil reservoirs.It reduces the interfacial tension and viscosity of crude oil,enhances its flowability,maintains reservoir pressure,and increases reservoir drainage capacity.Taking the Badaowan Formation as an example,in this study a detailed three-dimensional geomechanical model based on static data from well logging interpretations is elaborated,which can take into account both vertical and horizontal geological variations and mechanical characteristics.A comprehensive analysis of the impact of key construction parameters on Pre-CO_(2) based fracturing(such as cluster spacing and injection volume),is therefore conducted.Thereafter,using optimized construction parameters,a non-structured grid for dynamic development prediction is introduced,and the capacity variations of different production scenarios are assessed.On the basis of the simulation results,reasonable fracturing parameters are finally determined,including cluster spacing,fracturing fluid volume,proppant concentration,and well spacing.

Formation damage mechanism and control strategy of the compound function of drilling fluid and fracturing fluid in shale reservoirs

For the analysis of the formation damage caused by the compound function of drilling fluid and fracturing fluid,the prediction method for dynamic invasion depth of drilling fluid is developed considering the fracture extension due to shale minerals erosion by oil-based drilling fluid.With the evaluation for the damage of natural and hydraulic fractures caused by mechanical properties weakening of shale fracture surface,fracture closure and rock powder blocking,the formation damage pattern is proposed with consideration of the compound effect of drilling fluid and fracturing fluid.The formation damage mechanism during drilling and completion process in shale reservoir is revealed,and the protection measures are raised.The drilling fluid can deeply invade into the shale formation through natural and induced fractures,erode shale minerals and weaken the mechanical properties of shale during the drilling process.In the process of hydraulic fracturing,the compound effect of drilling fluid and fracturing fluid further weakens the mechanical properties of shale,results in fracture closure and rock powder shedding,and thus induces stress-sensitive damage and solid blocking damage of natural/hydraulic fractures.The damage can yield significant conductivity decrease of fractures,and restrict the high and stable production of shale oil and gas wells.The measures of anti-collapse and anti-blocking to accelerate the drilling of reservoir section,forming chemical membrane to prevent the weakening of the mechanical properties of shale fracture surface,strengthening the plugging of shale fracture and reducing the invasion range of drilling fluid,optimizing fracturing fluid system to protect fracture conductivity are put forward for reservoir protection.

Exploring pore-scale production characteristics of oil shale after CO_(2) huff‘n’puff in fractured shale with varied permeability

Recent studies have indicated that the injection of carbon dioxide(CO_(2))can lead to increased oil recovery in fractured shale reservoirs following natural depletion.Despite advancements in understanding mass exchange processes in subsurface formations,there remains a knowledge gap concerning the disparities in these processes between the matrix and fractures at the pore scale in formations with varying permeability.This study aims to experimentally investigate the CO_(2) diffusion behaviors and in situ oil recovery through a CO_(2) huff‘n’puff process in the Jimsar shale oil reservoir.To achieve this,we designed three matrix-fracture models with different permeabilities(0.074 mD,0.170 mD,and 0.466 mD)and experimented at 30 MPa and 91℃.The oil concentration in both the matrix and fracture was monitored using a low-field nuclear magnetic resonance(LF-NMR)technique to quantify in situ oil recovery and elucidate mass-exchange behaviors.The results showed that after three cycles of CO_(2) huff‘n’puff,the total recovery degree increased from 30.28%to 34.95%as the matrix permeability of the core samples increased from 0.074 to 0.466 mD,indicating a positive correlation between CO_(2) extraction efficiency and matrix permeability.Under similar fracture conditions,the increase in matrix permeability further promoted CO_(2) extraction efficiency during CO_(2) huff‘n’puff.Specifically,the increase in matrix permeability of the core had the greatest effect on the extraction of the first-cycle injection in large pores,which increased from 16.42%to 36.64%.The findings from our research provide valuable insights into the CO_(2) huff‘n’puff effects in different pore sizes following fracturing under varying permeability conditions,shedding light on the mechanisms of CO_(2)-enhanced oil recovery in fractured shale oil reservoirs.

Optimization of Gas-Flooding Fracturing Development in Ultra-Low Permeability Reservoirs

Ultra-low permeability reservoirs are characterized by small pore throats and poor physical properties, which areat the root of well-known problems related to injection and production. In this study, a gas injection floodingapproach is analyzed in the framework of numerical simulations. In particular, the sequence and timing of fracturechanneling and the related impact on production are considered for horizontal wells with different fracturemorphologies. Useful data and information are provided about the regulation of gas channeling and possible strategiesto delay gas channeling and optimize the gas injection volume and fracture parameters. It is shown that inorder to mitigate gas channeling and ensure high production, fracture length on the sides can be controlled andlonger fractures can be created in the middle by which full gas flooding is obtained at the fracture location in themiddle of the horizontal well. A Differential Evolution (DE) algorithm is provided by which the gas injectionvolume and the fracture parameters of gas injection flooding can be optimized. It is shown that an improvedoil recovery factor as high as 6% can be obtained.

Gas-Water Production of a Continental Tight-Sandstone Gas Reservoir under Different Fracturing Conditions

A numerical model of hydraulic fracture propagation is introduced for a representative reservoir(Yuanba continental tight sandstone gas reservoir in Northeast Sichuan).Different parameters are considered,i.e.,the interlayer stress difference,the fracturing discharge rate and the fracturing fluid viscosity.The results show that these factors affect the gas and water production by influencing the fracture size.The interlayer stress difference can effectively control the fracture height.The greater the stress difference,the smaller the dimensionless reconstruction volume of the reservoir,while the flowback rate and gas production are lower.A large displacement fracturing construction increases the fracture-forming efficiency and expands the fracture size.The larger the displacement of fracturing construction,the larger the dimensionless reconstruction volume of the reservoir,and the higher the fracture-forming efficiency of fracturing fluid,the flowback rate,and the gas production.Low viscosity fracturing fluid is suitable for long fractures,while high viscosity fracturing fluid is suitable for wide fractures.With an increase in the fracturing fluid viscosity,the dimensionless reconstruction volume and flowback rate of the reservoir display a non-monotonic behavior,however,their changes are relatively small.

Efficient production optimization for naturally fractured reservoir using EDFM

Naturally fractured reservoirs make important contributions to global oil and gas reserves and production.The modeling and simulation of naturally fractured reservoirs are different from conventional reservoirs as the existence of natural fractures.To address the development optimization problem of naturally fractured reservoirs,we propose an optimization workflow by coupling the optimization methods with the embedded discrete fracture model(EDFM).Firstly,the effective and superior performance of the workflow is verified based on the conceptual model.The stochastic simplex approximate gradient(StoSAG)algorithm,the ensemble optimization(EnOpt)algorithm,and the particle swarm optimization(PSO)algorithm are implemented for the production optimization of naturally fractured reservoirs based on the improved versions of the Egg model and the PUNQ-S3 model.The results of the two cases demonstrate the effectiveness of this optimization workflow by finding the optimal well controls which yield the maximum net present value(NPV).Compared to the initial well control guess,the final NPV obtained from the production optimization of fractured reservoirs based on all three optimization algorithms is significantly enhanced.Compared with the optimization results of the PSO algorithm,StoSAG and EnOpt have significant advantages in terms of final NPV and computational efficiency.The results also show that fractures have a significant impact on reservoir production.The economic efficiency of fractured reservoir development can be significantly improved by the optimization workflow.

Simulation of the Production Performances of Horizontal Wells with a Fractured Shale Gas Reservoir

The production performances of a well with a shale gas reservoir displaying a complex fracture network are simulated.In particular,a micro-seismic cloud diagram is used to describe the fracture network,and accordingly,a production model is introduced based on a multi-scale flow mechanism.A finite volume method is then exploited for the integration of the model equations.The effects of apparent permeability,conductivity,Langmuir volume,and bottom hole pressure on gas well production are studied accordingly.The simulation results show that ignoring the micro-scale flow mechanism of the shale gas leads to underestimating the well gas production.It is shown that after ten years of production,the cumulative gas production difference between the two scenarios with and without considering the micro-scale flow mechanisms is 19.5%.The greater the fracture conductivity,the higher the initial gas production of the gas well and the cumulative gas production.The larger the Langmuir volume,the higher the gas production rate and the cumulative gas production.With the reduction of the bottom hole pressure,the cumulative gas production increases,but the growth rate gradually decreases.

Revolutionizing Tight Reservoir Production: A Novel Dual-Medium Unsteady Seepage Model for Optimizing Volumetrically Fractured Horizontal Wells

This study presents an avant-garde approach for predicting and optimizing production in tight reservoirs,employing a dual-medium unsteady seepage model specifically fashioned for volumetrically fractured horizontal wells.Traditional models often fail to fully capture the complex dynamics associated with these unconventional reservoirs.In a significant departure from these models,our approach incorporates an initiation pressure gradient and a discrete fracture seepage network,providing a more realistic representation of the seepage process.The model also integrates an enhanced fluid-solid interaction,which allows for a more comprehensive understanding of the fluid-structure interactions in the reservoir.This is achieved through the incorporation of improved permeability and stress coupling,leading to more precise predictions of reservoir behavior.The numerical solutions derived from the model are obtained through the sophisticated finite element method,ensuring high accuracy and computational efficiency.To ensure the model’s reliability and accuracy,the outcomes were tested against a real-world case,with results demonstrating strong alignment.A key revelation from the study is the significant difference between uncoupled and fully coupled volumetrically fractured horizontal wells,challenging conventional wisdom in the field.Additionally,the study delves into the effects of stress,fracture length,and fracture number on reservoir production,contributing valuable insights for the design and optimization of tight reservoirs.The findings from this study have the potential to revolutionize the field of tight reservoir prediction and management,offering significant advancements in petroleum engineering.The proposed approach brings forth a more nuanced understanding of tight reservoir systems and opens up new avenues for optimizing reservoir management and production.

Lost circulation material for abnormally high temperature and pressure fractured-vuggy carbonate reservoirs in Tazhong block, Tarim Basin, NW China

To effectively solve the problem of lost circulation and well kick frequently occurring during the drilling of abnormally high temperature and pressure fractured-vuggy reservoirs in the Tazhong block, a rigid particle material, GZD, with high temperature tolerance, high rigidity(> 8 MPa) and low abrasiveness has been selected based on geological characteristics of the theft zones in the reservoirs. Through static pressure sealing experiments, its dosage when used alone and when used in combination with lignin fiber, elastic material SQD-98 and calcium carbonate were optimized, and the formula of a new type(SXM-I) of compound lost circulation material with high temperature tolerance and high strength was formed. Its performance was evaluated by compatibility test, static sealing experiment and sand bed plugging experiment. The test results show that it has good compatibility with drilling fluid used commonly and is able to plug fractures and vugs, the sealed fractures are able to withstand the static pressure of more than 9 MPa and the cumulative leakage is 13.4 mL. The mud filtrate invasion depth is only 2.5 cm in 30 min when the sand bed is made of particles with sizes between 10 mesh and 20 mesh. Overall, with good sealing property and high temperature and high pressure tolerance, the lost circulation material provides strong technical support for the safety drilling in the block.

The application study on the multi-scales integrated prediction method to fractured reservoir description

In this paper,we implement three scales of fracture integrated prediction study by classifying it to macro-（ 1/4/λ）,meso-（ 1/100λ and 1/4λ） and micro-（ 1/100λ） scales.Based on the multi-scales rock physics modelling technique,the seismic azimuthal anisotropy characteristic is analyzed for distinguishing the fractures of meso-scale.Furthermore,by integrating geological core fracture description,image well-logging fracture interpretation,seismic attributes macro-scale fracture prediction and core slice micro-scale fracture characterization,an comprehensive multi-scale fracture prediction methodology and technique workflow are proposed by using geology,well-logging and seismic multi-attributes.Firstly,utilizing the geology core slice observation（Fractures description） and image well-logging data interpretation results,the main governing factors of fracture development are obtained,and then the control factors of the development of regional macro-scale fractures are carried out via modelling of the tectonic stress field.For the meso-scale fracture description,the poststack geometric attributes are used to describe the macro-scale fracture as well,the prestack attenuation seismic attribute is used to predict the meso-scale fracture.Finally,by combining lithological statistic inversion with superposed results of faults,the relationship of the meso-scale fractures,lithology and faults can be reasonably interpreted and the cause of meso-scale fractures can be verified.The micro-scale fracture description is mainly implemented by using the electron microscope scanning of cores.Therefore,the development of fractures in reservoirs is assessed by valuating three classes of fracture prediction results.An integrated fracture prediction application to a real field in Sichuan basin,where limestone reservoir fractures developed,is implemented.The application results in the study area indicates that the proposed multi-scales integrated fracture prediction method and the technique procedureare able to deal with the strong heterogeneity and multi-scales problems in fracture prediction.Moreover,the multi-scale fracture prediction technique integrated with geology,well-logging and seismic multi-information can help improve the reservoir characterization and sweet-spots prediction for the fractured hydrocarbon reservoirs.

Practice and knowledge of volumetric development of deep fractured-vuggy carbonate reservoirs in Tarim Basin, NW China

Different from the continental layered sandstone and fracture-pore carbonate reservoirs, the fractured-vuggy carbonate reservoirs in the Tarim Basin are mainly composed of fractured-vuggy bodies of different sizes and shapes. Based on years of study on the geological features, flow mechanisms, high-precision depiction and the recovery mode of fractured-vuggy bodies, the idea of “volumetric development” is proposed and put into practice. A “body by body” production methodology is established with respect to volumetric unit of fractures and vugs based on vuggy body’s spatial allocation and reserves. A variety of development wells, various technological methods, and multi-type injection media are used to develop this type of reservoirs in an all-around way. As a result, the resource and production structures of the Tahe oilfield are significantly improved and a highly efficient development is achieved.

Experiments on nitrogen assisted gravity drainage in fractured-vuggy reservoirs

Visual models of fractured-vuggy reservoirs were designed and manufactured to conduct experiments of nitrogen assisted gravity drainage(NAGD). The impacts of flooding pattern, gas injection rate, well type, and displacement direction(vertical or horizontal) on development performances and remaining oil distribution were studied. The results show that during NAGD, the sweep scope is decided by the connections between producer and reservoir, and the local sweep efficiency is decided by fracture-vuggy configuration. The homogenous fractured reservoir has higher oil recovery, and the bigger the aperture of fracture is, the higher the recovery. The main regions of remaining oil due to poor connectivity and gas-oil gravity difference include blind fractures and vugs below the connected fractures, the bottom of vugs, and the narrow and low-angle fractures. The accumulation of remaining oil in the bottom of reservoir is easily formed and controlled by the connections between producers and reservoir. The higher the gas injection rate and the stronger the fracture heterogeneity, the earlier the gas channeling and the lower the oil recovery of the producer will be.Horizontal wells have the best development effect, so horizontal well can be applied in fractured-vuggy reservoirs without bottom water.Producers should be preferentially drilled at low structural position. Gas channeling firstly occurs in the producer at high structural position, and it should be shut in timely to improve the utilization of injected gas.