The mechanisms of thermal solidification agent promoting steam diversion in heavy oil reservoirs

At high cycles of steam huff&puff,oil distribution in reservoirs becomes stronger heterogeneity due to steam channeling.Thermal solidification agent can be used to solve this problem.Its solution is a lowviscosity liquid at normal temperature,but it can be solidified above 80℃.The plugging degree is up to 99%at 250℃.The sweep efficiency reaches 59.2%,which is 7.3%higher than pure steam injection.In addition,simultaneous injection of viscosity reducer and/or nitrogen foams can further enhance oil recovery.The mechanism of this technology depends on its strong plugging ability,which changes the flowing pattern of steam to effectively mobilize remaining oil.Viscosity reducer and nitrogen foams further expand the sweep range and extends the effective period.Therefore,thermal solidification agent can plug steam channeling paths and adjust steam flowing direction to significantly enhance oil recovery at high cycles of steam huff&puff.

Impacts of proppant distribution on development of tight oil reservoirs with threshold pressure gradient

Field evidence indicates that proppant distribution and threshold pressure gradient have great impacts on well productivity.Aiming at the development of unconventional oil reservoirs in Triassic Chang-7 Unit,Ordos Basin of China,we presented an integrated workflow to investigate how(1)proppant placement in induced fracture and(2)non-linear flow in reservoir matrix would affect well productivity and fluid flow in the reservoir.Compared with our research before(Yue et al.,2020),here we extended this study into the development of multi-stage fractured horizontal wells(MFHWs)with large-scale complicated fracture geometry.The integrated workflow is based on the finite element method and consists of simulation models for proppant-laden fluid flow,fracture flow,and non-linear seepage flow,respectively.Simulation results indicate that the distribution of proppant inside the induced cracks significantly affects the productivity of the MFHW.When we assign an idealized proppant distribution instead of the real distribution,there will be an overestimation of 44.98%in daily oil rate and 30.63%in cumulative oil production after continuous development of 1000 days.Besides,threshold pressure gradient(TPG)also significantly affects the well performance in tight oil reservoirs.If we simply apply linear Darcy’s law to the reservoir matrix,the overall cumulative oil production can be overrated by 77%after 1000 days of development.In general,this research provides new insights into the development of tight oil reservoirs with TPG and meanwhile reveals the significance of proppant distribution and non-linear fluid flow in the production scenario design.

The effects of various factors on spontaneous imbibition in tight oil reservoirs

Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imbibition within the reservoir. Several variables influence the eventual recovery rate within this procedure, including slickwater composition, formation temperature, degree of reservoir fracture development, and the reservoir characteristics. Nonetheless, the underlying mechanisms governing these influences remain relatively understudied. In this investigation, using the Chang-7 block of the Changqing Oilfield as the study site, we employ EM-30 slickwater fracturing fluid to explore the effects of the drag-reducing agent concentration, imbibition temperature, core permeability, and core fracture development on spontaneous imbibition. An elevated drag-reducing agent concentration is observed to diminish the degree of medium and small pore utilization. Furthermore, higher temperatures and an augmented permeability enhance the fluid flow properties, thereby contributing to an increased utilization rate across all pore sizes. Reduced fracture development results in a lower fluid utilization across diverse pore types. This study deepens our understanding of the pivotal factors affecting spontaneous imbibition in tight reservoirs following fracturing. The findings act as theoretical, technical, and scientific foundations for optimizing fracturing strategies in tight oil reservoir transformations.

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.

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.

Discussion on the sweep efficiency of hybrid steam-chemical process in heavy oil reservoirs: An experimental study

Non-condensable gas(NCG),foam and surfactant are the three commonly-used additives in hybrid steam-chemical processes for heavy oil reservoirs.Their application can effectively control the steam injection profile and increase the sweep efficiency.In this paper,the methods of microscale visualized experiment and macroscale 3D experiment are applied to systematically evaluate the areal and vertical sweep efficiencies of different hybrid steam-chemical processes.First,a series of static tests are performed to evaluate the effect of different additives on heavy oil properties.Then,by a series of tests on the microscale visualized model,the areal sweep efficiencies of a baseline steam flooding process and different follow-up hybrid EOR processes are obtained from the collected 2D images.Specifically,they include the hybrid steam-N_(2)process,hybrid steam-N2/foam process,hybrid steam-surfactant process and hybrid steam-N2/foam/surfactant process(N2/foam slug first and steam-surfactant co-injection then).From the results of static tests and visualized micromodels,the pore scale EOR mechanisms and the difference between them can be discussed.For the vertical sweep efficiencies,a macroscale 3D experiment of steam flooding process and a follow-up hybrid EOR process is conducted.Thereafter,combing the macroscale 3D experiment and laboratory-scaled numerical simulation,the vertical and overall sweep efficiencies of different hybrid steam-chemical processes are evaluated.Results indicate that compared with a steam flooding process,the areal sweep efficiency of a hybrid steam-N2process is lower.It is caused by the high mobility ratio in a steam-N2-heavy oil system.By contrast,the enhancement of sweep efficiency by a hybrid steam-N2/foam/surfactant process is the highest.It is because of the high resistance capacity of NCG foam system and the performance of surfactant.Specifically,a surfactant can interact with the oil film in chief zone and reduce the interfacial energy,and thus the oil droplets/films formed during steam injection stage are unlocked.For NCG foam,it can plug the chief steam flow zone and thus the subsequent injected steam is re-directed.Simultaneously,from the collected 2D images,it is also observed that the reservoir microscopic heterogeneity can have an important effect on their sweep efficiencies.From the 3D experiment and laboratory-scaled numerical simulation,it is found that a N2/foam slug can increase the thermal front angle by about 150 and increase the vertical sweep efficiency by about 26%.Among the four processes,a multiple hybrid EOR process(steam-N2/foam/surfactant process) is recommended than the other ones.This paper provides a novel method to systematically evaluate the sweep efficiency of hybrid steam-chemical process and some new insights on the mechanisms of sweep efficiency enhancement are also addressed.It can benefit the expansion of hybrid steam-chemical processes in the post steamed heavy oil reservoirs.

Necessity and feasibility of improving the residual resistance factor of polymer flooding in heavy oil reservoirs

The efficiency of water flooding in heavy oil reservoirs would be improved by increasing the viscosity of the displacing phase, but the sweep efficiency is not of significance due to the low mobility of the vicious oil. On the basis of mobility control theory, increasing the residual resistance factor not only reduces the water-oil mobility ratio but also decreases the requirement for viscosity enhancement of the polymer solution. The residual resistance factor caused by hydrophobic associating polymer solution is higher than that caused by polyacrylamide solution in brine containing high concentrations of calcium and magnesium ions. The results of numerical simulations show that the polymer flooding efficiency improved by increasing the residual resistance factor is far better than that by only increasing solution viscosity. The recovery factor of heavy oil reservoirs （70 mPa·s） can be enhanced by hydrophobic associating polymer solution of high residual resistance factor （more than 3） and high effective viscosity （24 mPa·s）. Therefore, increasing the residual resistance factor of the polymer solution not only decreases the requirement for the viscosity of polymer solution injected into heavy oil reservoirs but also is favorable to enhanced oil recovery during polymer flooding.

Enhancement of the imbibition recovery by surfactants in tight oil reservoirs

Hydraulic fracturing technology can significantly increase oil production from tight oil formations, but performance data show that production declines rapidly. In the long term, it is necessary to increase the development efficiency of block matrix, surfactant-aided imbibition is a potential way. The current work aimed to explain comprehensively how surfactants can enhance the imbibition rate. Laboratory experiments were performed to investigate the effects of wettability, interfacial tension(IFT), and relative permeability as the key parameters underlying surfactant solution imbibition. Two different types of surfactants, sodium dodecyl sulfate and polyethylene glycol octylphenol ether, at varied concentrations were tested on reservoir rocks. Experimental results showed that the oil recovery rate increased with increased wettability alteration and IFT and decreased residual oil saturation. A mechanistic simulator developed in previous studies was used to perform parametric analysis after successful laboratory-scale validation. Results were proven by parametric studies. This study,which examined the mechanism and factors influencing surfactant solution imbibition, can improve understanding of surfactant-aided imbibition and surfactant screening.

Laboratory to field scale assessment for EOR applicability in tight oil reservoirs

Tight oil reservoirs are contributing a major role to fulfill the overall crude oil needs,especially in the US.However,the dilemma is their ultra-tight permeability and an uneconomically short-lived primary recovery factor.Therefore,the application of EOR in the early reservoir development phase is considered effective for fast-paced and economical tight oil recovery.To achieve these objectives,it is imperative to determine the optimum EOR potential and the best-suited EOR application for every individual tight oil reservoir to maximize its ultimate recovery factor.Since most of the tight oil reservoirs are found in wide spatial source rock with complex and compacted pores and poor geophysical properties yet they hold high saturation of good quality oil and therefore,every single percent increase in oil recovery from such huge reservoirs potentially provide an additional million barrels of oil.Hence,the EOR application in such reservoirs is quite essential.However,the physical understanding of EOR applications in different circumstances from laboratory to field scale is the key to success and similarly,the fundamental physical concepts of fluid flow-dynamics under confinement conditions play an important role.This paper presents a detailed discussion on laboratory-based experimental achievements at micro-scale including fundamental concepts under confinement environment,physics-based numerical studies,and recent actual field piloting experiences based on the U.S.unconventional plays.The objective of this paper is to discuss all the critical reservoir rock and fluid properties and their contribution to reservoir development through massive multi-staged hydraulic fracture networks and the EOR applications.Especially the CO_(2)and produced hydrocarbon gas injection through single well-based huff-n-puff operational constraints are discussed in detail both at micro and macro scale.

Numerical simulation of hydraulic fracture propagation in tight oil reservoirs by volumetric fracturing

Volumetric fracturing is a primary stimulation technology for economical and effective exploitation of tight oil reservoirs. The main mechanism is to connect natural fractures to generate a fracture network system which can enhance the stimulated reservoir volume. By using the combined finite and discrete element method, a model was built to describe hydraulic fracture propagation in tight oil reservoirs. Considering the effect of horizontal stress difference, number and spacing of perforation clus- ters, injection rate, and the density of natural fractures on fracture propagation, we used this model to simulate the fracture propagation in a tight formation of a certain oil- field. Simulation results show that when the horizontal stress difference is lower than 5 MPa, it is beneficial to form a complex fracture network system. If the horizontal stress difference is higher than 6 MPa, it is easy to form a planar fracture system; with high horizontal stress differ- ence, increasing the number of perforation clusters is beneficial to open and connect more natural fractures, and to improve the complexity of fracture network and the stimulated reservoir volume （SRV）. As the injection rate increases, the effect of volumetric fracturing may be improved; the density of natural fractures may only have a great influence on the effect of volume stimulation in a low horizontal stress difference.

Research into polymer injection timing for Bohai heavy oil reservoirs

Polymer flooding has been proven to effectively improve oil recovery in the Bohai Oil Field. However, due to high oil viscosity and significant formation heterogeneity, it is necessary to further improve the displacement effectiveness of polymer flooding in heavy oil reservoirs in the service life of offshore platforms. In this paper, the effects of the water/oil mobility ratio in heavy oil reservoirs and the dimensionless oil productivity index on polymer flooding effectiveness were studied utilizing rel- ative permeability curves. The results showed that when the water saturation was less than the value, where the water/oil mobility ratio was equal to 1, polymer flooding could effectively control the increase of fractional water flow, which meant that the upper limit of water/oil ratio suitable for polymer flooding should be the value when the water/oil mobility ratio was equal to 1. Mean while, by injecting a certain volume of water to create water channels in the reservoir, the polymer flooding would be the most effective in improving sweep efficiency, and lower the fractional flow of water to the value corresponding to △Jmax. Considering the service life of the platform and the polymer mobility control capacity, the best polymer injection timing for heavy oil reservoirs was optimized. It has been tested for reservoirs with crude oil viscosity of 123 and 70 mPa s, the optimum polymer flooding effec- tiveness could be obtained when the polymer floods were initiated at the time when the fractional flow of water were 10 % and 25 %, respectively. The injection timing range for polymer flooding was also theoretically analyzed for the Bohai Oil Field utilizing which provided methods for effectiveness. relative permeability curves, improving polymer flooding

Oxidization characteristics and thermal miscible flooding of high pressure air injection in light oil reservoirs

Physical modeling,numerical simulation and field case analysis were carried out to find out the subsurface thermal oxidation state,thermal oxidation front characteristics and production dynamic characteristics of high pressure air injection thermal oxidation miscible flooding technology.The lighter the composition and the lower the viscosity of the crude oil,the lower the fuel consumption and the combustion temperature are.The thermal oxidation front of light oil and volatile oil can advance stably,and a medium-temperature thermal oxidation stable displacement state can be formed in the light oil reservoir under high pressure conditions.With strong thermal gasification and distillation,light oil and volatile oil are likely to form a single phase zone of gasification and distillation with thermal flue gas at the high-temperature and high-pressure heat front,finally,an air-injection thermal miscible front.In light oil reservoirs,the development process of high-pressure air-injection thermal miscible flooding can be divided into three stages:boosting pressure stage,low gas-oil ratio and high-efficiency stable production stage and high gas-oil ratio production stage.Approximately 70%of crude oil is produced during the boosting pressure stage and low gas-oil ratio high-efficiency and stable production stage.

A novel approach of tight oil reservoirs stimulation based on fracture controlling optimization and design

To deal with the stress interference caused by simultaneous propagation of multiple fractures and the wettability reversal and physical property changes of the reservoir caused by fracturing fluid getting in during large-volume fracturing of tight oil reservoirs through a horizontal well, a non-planar 3D fracture growth model was built, wettability reversal characterizing parameters and change of relative permeability curve were introduced to correct the production prediction model of fractured horizontal well, a fracturing design optimization software(Fr Smart) by integrating geological and engineering data was developed, and a fracturing design optimization approach for tight oil reservoirs based on fracture control was worked out. The adaptability of the method was analyzed and the fracture parameters of horizontal wells in tight oil reservoirs were optimized. The simulation results show that fracturing technology based on fracture control is suitable for tight oil reservoirs, and by optimizing fracture parameters, this technology makes it possible to produce the maximum amount of reserves in the well-controlled unit of unconventional reservoirs. The key points of fracturing design optimization based on fracture control include increasing lateral length of and reducing the row spacing between horizontal wells, increasing perforation clusters in one stage to decrease the spacing of neighboring fractures, and also avoiding interference of old and new fracturing wells. Field tests show that this technology can increase single well production and ultimate recovery. Using this technology in developing unconventional resources such as tight oil reservoirs in China will enhance the economics significantly.

Quantitative investigation of nanofluid imbibition in tight oil reservoirs based on NMR technique

Nanofluids have been effective chemical additives for enhanced oil recovery(EOR)in tight oil reservoirs due to their special properties.However,oil imbibition recoveries vary for different nanofluids.The oil/water distribution in rocks during imbibition using various nanofluids was less discussed in previous studies.In this study,we systematically examined the imbibition efficiencies of various nanofluids at60℃.Furthermore,the migration of nanofluids and oil distribution in the rock pores were monitored using nuclear magnetic resonance(NMR).The nanofluids were prepared by dispersing silica nanoparticles and five different types of surfactants i.e.,anionic-nonionic,anionic,nonionic,amphoteric and cationic surfactants in deionized(DI)water.Subsequently,interfacial tension(IFT)and contact angle measurements were conducted to reveal the underlying EOR mechanisms of various nanofluids.The experimental results showed that the EOR potential of the different types of nanofluids was in the order anionic-nonionic>anionic>nonionic>amphoteric>cationic>brine.Anionic-nonionic(sodium lauryl ether sulfate(SLES))and anionic(sodium dodecyl sulfonate(SDS))nanofluids exhibited excellent capability of wettability alteration,and increased oil recovery by 27.96%and 23.08%,respectively,compared to brine.The NMR results also showed that mesopores(0.1-1μm)were the dominant developed pores in the rocks,and contributed the most to imbibition efficiency.In addition,the imbibition of nanofluids initially took place in mesopores and micropores before moving into macropores.This study provides fundamental information on the selection of nanofluids for EOR in tight oil reservoirs.The study also improved the understanding of oil/water distribution during the imbibition of the proposed nanofluids.

Review of CO_(2)-kerogen interaction and its effects on enhanced oil recovery and carbon sequestration in shale oil reservoirs

Shale oil resources have proven to be quickly producible in large quantities and have recently revolutionized the oil and gas industry.The oil content in a shale oil formation includes free oil contained in pores and trapped oil in the organic material called kerogen.The latter can represent a significant portion of the total oil and yet pro-duction of shale oil currently targets only the free oil rather than the trapped oil in kerogen.Shale oil reservoirs also have a substantial capacity to store CO_(2)by dissolving it in kerogen.In this paper,recent progress in the research of CO_(2)-kerogen interaction and its applications in CO_(2)enhanced oil recovery and carbon sequestration in shale oil reservoirs are reviewed.The relevant topics reviewed for this relatively new area include charac-terization of organic matter,supercritical CO_(2)extraction of oil in shale,experimental and simulation study of CO_(2)-hydrocarbons counter-current diffusion in organic matter,recovery of oil in kerogen during CO_(2)huff‘n’puffprocess,and changes in microstructure of shale caused by CO_(2)-kerogen interaction.The results presented in this paper show that at reservoir conditions,supercritical CO_(2)can spontaneously replace the hydrocarbons from the organic matter of shale formations.This mass transfer process is the key to releasing organic oil saturation and maximizing the capacity of carbon storage of a shale oil reservoir.It also presents a concern of the structure change of organic materials for long term CO_(2)sequestration with shale or mudstone as the sealing rocks.

In-situ laboratory study on influencing factors of pre-SC-CO_(2) hybrid fracturing effect in shale oil reservoirs

Supercritical CO_(2)(SC-CO_(2)) fracturing, being a waterless fracturing technology, has garnered increasing attention in the shale oil reservoir exploitation industry. Recently, a novel pre-SC-CO_(2) hybrid fracturing method has been proposed, which combines the advantages of SC-CO_(2) fracturing and hydraulic fracturing. However, the specific impacts of different pre-SC-CO_(2) injection conditions on the physical parameters, mechanical properties, and crack propagation behavior of shale reservoirs remain unclear. In this study, we utilize a newly developed “pre-SC-CO_(2) injection → water-based fracturing” integrated experimental device. Through experimentation under in-situ conditions, the impact of pre-SC-CO_(2) injection displacement and volume on the shale mineral composition, mechanical parameters, and fracture propagation behavior are investigated. The findings of the study demonstrate that the pre-injection SC-CO_(2) leads to a reduction in clay and carbonate mineral content, while increasing the quartz content. The correlation between quartz content and SC-CO_(2) injection volume is positive, while a negative correlation is observed with injection displacement. The elastic modulus and compressive strength exhibit a declining trend, while Poisson's ratio shows an increasing trend. The weakening of shale mechanics caused by pre-injection of SC-CO_(2) is positively correlated with the injection displacement and volume.Additionally, pre-injection of SC-CO_(2) enhances the plastic deformation behavior of shale, and its breakdown pressure is 16.6% lower than that of hydraulic fracturing. The breakdown pressure demonstrates a non-linear downward trend with the gradual increase of pre-SC-CO_(2) injection parameters.Unlike hydraulic fracturing, which typically generates primary fractures along the direction of the maximum principal stress, pre-SC-CO_(2) hybrid fracturing leads to a more complex fracture network. With increasing pre-SC-CO_(2) injection displacement, intersecting double Y-shaped complex fractures are formed along the vertical axis. On the other hand, increasing the injection rate generates secondary fractures along the direction of non-principal stress. The insights gained from this study are valuable for guiding the design of pre SC-CO_(2) hybrid fracturing in shale oil reservoirs.

Surface Loess Susceptibility Anomalies Directly Indicating Oil and Gas Reservoirs

It is a fact that the near surface loess has magnetic susceptibility anomalies in oil and gas areas. Why these anomalies occur and whether they have any significant value for the exploration of oil and gas reservoirs are questions that geophysicists are mostly concerned about and study. We analyze the cause of the formation of surface loess susceptibility anomalies in oil and gas areas, process the observations of the susceptibility of loess samples taken from an oil and gas area in western China with proper mathematical methods, and determine the background value of loess susceptibility. These results are used to determine oil and gas prospect areas with a numeric evaluation factor based on the susceptibility anomalies. Actual oil wells have verified that using the susceptibility anomalies to indicate the location of oil and gas reservoirs is valid.

A new method to optimize the fracture geometry of a frac-packed well in unconsolidated sandstone heavy oil reservoirs

The worldwide proven recoverable reserves of conventional oil are less than the amount of the heavy oil.Owing to weakly consolidated formation,sand production is an important problem encountered during oil production in heavy oil reservoirs,for which frac-pack technique is one of the most common treatments.Hence,how to obtain the optimal fracture geometry is the key to increasing well production and preventing sand.Due to the faultiness that current optimization of the fracture geometry only depends on well productivity,fracture-flow fraction was used to describe the contribution of the fracture collecting and conducting fluids from the reservoir.The higher the fracture-flow fraction,the more likely bilinear flow pattern occurs,thus leading to smaller flow resistance and better results in oil productivity and sand prevention.A reservoir numerical simulation model was established to simulate the long-term production dynamic of a fractured well in rectangular drainage areas.In order to reach the aim of increasing productivity meanwhile preventing sand,a new method based on Unified Fracture Design was developed to optimize the fracture geometry.For a specific reservoir and a certain amount of proppant injected to the target layer,there exits an optimal dimensionless fracture conductivity which corresponds to the maximum fracture-flow fraction,accordingly we can get the optimal fracture geometry.The formulas of the optimal fracture geometry were presented on square drainage area conditions,which are very convenient to apply.Equivalent Proppant Number was used to eliminate the impact of aspect ratios of rectangular drainage area,then,the same method to optimize the fracture geometry as mentioned for square drainage areas could be adopted too.

Using a Modified GOI Index(Effective Grid Containing Oil Inclusions)to Indicate Oil Zones in Carbonate Reservoirs

The GOI（grains containing oil inclusions） index is used to distinguish oil zones,oil-water zones and water zones in sandstone oil reservoirs.However,this method cannot be directly applied to carbonate rocks that may not have clear granular textures.In this paper we propose the Effective Grid Containing Oil Inclusions（EGOI） method for carbonate reservoirs.A microscopic view under10× ocular and 10 x objective is divided into 10×10 grids,each with an area of 0.0625 mm×0.0625 mm.An effective grid is defined as one that is cut（touched） by a stylolite,a healed fracture,a vein,or a pore-filling material.EGOI is defined as the number of effective grids containing oil inclusions divided by the total number of effective grids multiplied by 100%.Based on data from the Tarim Basin,the EGOI values indicative of the paleo-oil zones,oil-water zones,and water zones are 〉5%,1%-5%,and 〈1%,respectively.However,the oil zones in young reservoirs（charged in the Himalayan） generally have lower EGOI values,typically 3%-5%.

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.