Fractal model of spontaneous imbibition in low-permeability reservoirs coupled with heterogeneity of pore seepage channels and threshold pressure

Spontaneous imbibition(SI)is an important mechanism for enhancing oil recovery in low-permeability reservoirs.Due to the strong heterogeneity,and the non-Darcy flow,the construction of SI model for lowpermeability reservoirs is extremely challenging.Commonly,traditional SI models based on single or averaged capillary tortuosity ignore the influence of heterogeneity of pore seepage channels and the threshold pressure(TP)on imbibition.Therefore,in this work,based on capillary model and fractal theory,a mathematical model of characterizing SI considering heterogeneity of pore seepage channels is established.On this basis,the threshold pressure was introduced to determine the pore radius at which the wetted phase can displace oil.The proposed new SI model was verified by imbibition experimental data.The study shows that for weakly heterogeneous cores with permeability of 0-1 m D,the traditional SI model can characterize the imbibition process relatively accurately,and the new imbibition model can increase the coefficient of determination by 1.05 times.However,traditional model has serious deviations in predicting the imbibition recovery for cores with permeability of 10-50 m D.The new SI model coupling with heterogeneity of pore seepage channels and threshold pressure effectively solves this problem,and the determination coefficient is increased from 0.344 to 0.922,which is increased by2.68 times.For low-permeability reservoirs,the production of the oil in transitional pores(0.01-0.1μm)and mesopores(0.1-1μm)significantly affects the imbibition recovery,as the research shows that when the heterogeneity of pore seepage channels is ignored,the oil recovery in transitional pores and mesopores decreases by 7.54%and 4.26%,respectively.Sensitivity analysis shows that increasing interfacial tension,decreasing contact angle,oil-water viscosity ratio and threshold pressure will increase imbibition recovery.In addition,there are critical values for the influence of these factors on the imbibition recovery,which provides theoretical support for surfactant optimization.

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.

Quantitative characterization of shale pore connectivity and controlling factors using spontaneous imbibition combined with nuclear magnetic resonance T_(2)and T_(1)-T_(2)

Shale oil can be extracted from shale by using interconnected pore networks.The migration of hydrocarbon molecules within the shale is controlled by pore connectivity.However,assessing the pore connectivity of shale oil reservoirs is uncommon.To characterize pore connectivity and clarify its controlling factors,this study used spontaneous imbibition(SI)combined with nuclear magnetic resonance(NMR)T_(2)and T_(1)-T_(2)technologies on shale oil reservoirs selected from the Shahejie Formation in the Dongying Sag,Bohai Bay Basin.According to the findings,the SI processes of shales include fast-rising,slow-rising,and stable stages.The fast-rising stage denotes pore connectivity.The shales studied have poor connectivity,with lower imbibition slopes and connected porosity ratios,but large effective tortuosity.During the SI process,micropores have the highest imbibition saturation,followed by mesopores and macropores.Furthermore,n-dodecane ingested into micropores appears primarily as adsorbed,whereas n-dodecane appears primarily as free states in mesopores and macropores during the SI process.The pore connectivity of the shales under study is primarily controlled by inorganic minerals.Quartz and feldspar develop large and regular pores,resulting in better pore connectivity,whereas clay minerals and calcite with plenty of complex intragranular pores do not.Organic matter negatively influences pore connectivity because the dissolution of calcite by organic acid produced during hydrocarbon generation leads to a more complex and heterogeneous pore structure.This study sheds light on the pore connectivity and controlling factors of the shale oil reservoir and aids in the understanding of shale oil mobility.

Performance comparison of novel chemical agents in improving oil recovery from tight sands through spontaneous imbibition

Tight sands are abundant in nanopores leading to a high capillary pressure and normally a low fluid injectivity.As such,spontaneous imbibition might be an effective mechanism for improving oil recovery from tight sands after fracturing.The chemical agents added to the injected water can alter the interfacial properties,which could help further enhance the oil recovery by spontaneous imbibition.This study explores the possibility of using novel chemicals to enhance oil recovery from tight sands via spontaneous imbibition.We experimentally examine the effects of more than ten different chemical agents on spontaneous imbibition,including a cationic surfactant(C12 TAB),two anionic surfactants(0242 and 0342),an ionic liquid(BMMIM BF4),a high pH solution(NaBO2),and a series of house-made deep eutectic solvents(DES3-7,9,11,and 14).The interfacial tensions(IFT)between oil phase and some chemical solutions are also determined.Experimental results indicate that both the ionic liquid and cationic surfactant used in this study are detrimental to spontaneous imbibition and decrease the oil recovery from tight sands,even though cationic surfactant significantly decreases the oil-water IFT while ionic liquid does not.The high pH NaBO2 solution does not demonstrate significant effect on oil recovery improvement and IFT reduction.The anionic surfactants(O242 and O342)are effective in enhancing oil recovery from tight sands through oil-water IFT reduction and emulsification effects.The DESs drive the rock surface to be more water-wet,and a specific formulation(DES9)leads to much improvement on oil recovery under counter-current imbibition condition.This preliminary study would provide some knowledge about how to optimize the selection of chemicals for improving oil recovery from tight reservoirs.

Enhanced oil recovery from carbonate reservoirs by spontaneous imbibition of low salinity water

An experimental study was performed to investigate the impact of low salinity water on wettability alteration in carbonate core samples from southern Iranian reservoirs by spontaneous imbibition. In this paper, the effect of temperature, salinity,permeability and connate water were investigated by comparing the produced hydrocarbon curves. Contact angle measurements were taken to confirm the alteration of surface wettability of porous media. Oil recovery was enhanced by increasing the dilution ratio of sea water, and there existed an optimum dilution ratio at which the highest oil recovery was achieved. In addition, temperature had a very significant impact on oil recovery from carbonate rocks. Furthermore, oil recovery from a spontaneous imbibition process was directly proportional to the permeability of the core samples. The presence of connate water saturation inside the porous media facilitated oil production significantly. Also, the oil recovery from porous media was highly dependent on ion repulsion/attraction activity of the rock surface which directly impacts on the wettability conditions. Finally, the highest ion attraction percentage was measured for sodium while there was no significant change in pH for all experiments.

Spontaneous imbibition characteristics of shale oil reservoir under the influence of osmosis

The spontaneous imbibition(SI)process in shale oil reservoirs is not only infuenced by capillary force,but also by the osmotic pressure between the fracturing fuid and formation water in the nanopores media.In this study,experimental methods are used to investigate the mechanisms of osmosis in the SI,taking into account the presence of initial formation water in shale oil reservoirs.To investigate the efect of osmosis,SI experiments were performed on the fne-grained felsic shale of the Qikou sag of Dagang oilfeld.Low-feld NMR testers and high-precision electronic balances are utilized for the measuring of oil–water migration.The results show that,when Sw≠0,high-salinity fuid SI can be divided into four stages:initial imbibition stage,drainage stage,secondary imbibition stage and stationary stage;when Sw=0,there is no drainage stage of high-salinity fuid SI;when Sw≠0 or Sw=0,low-salinity fuid SI can be called the“osmosis-enhanced SI”;and we have found that“newly formed pores or microfractures”as well as reducing salinity can promote SI.This article presents a systematic study of SI of shale oil reservoirs under the infuence of osmosis,which provide useful information for reservoir numerical simulation and development program design.

Enhancing the spontaneous imbibition rate of water in oil-wet dolomite rocks through boosting a wettability alteration process using carbonated smart brines

Most fractured carbonate oil reservoirs have oil-wet rocks.Therefore,the process of imbibing water from the fractures into the matrix is usually poor or basically does not exist due to negative capillary pressure.To achieve appropriate ultimate oil recovery in these reservoirs,a water-based enhanced oil recovery method must be capable of altering the wettability of matrix blocks.Previous studies showed that carbonated water can alter wettability of carbonate oil-wet rocks toward less oil-wet or neutral wettability conditions,but the degree of modification is not high enough to allow water to imbibe spontaneously into the matrix blocks at an effective rate.In this study,we manipulated carbonated brine chemistry to enhance its wettability alteration features and hence to improve water imbibition rate and ultimate oil recovery upon spontaneous imbibition in dolomite rocks.First,the contact angle and interfacial tension(IFT)of brine/crude oil systems were measured for several synthetic brine samples with different compositions.Thereafter,two solutions with a significant difference in WAI(wettability alteration index)but approximately equal brine/oil IFT were chosen for spontaneous imbibition experiments.In the next step,spontaneous imbibition experiments at ambient and high pressures were conducted to evaluate the ability of carbonated smart water in enhancing the spontaneous imbibition rate and ultimate oil recovery in dolomite rocks.Experimental results showed that an appropriate adjustment of the imbibition brine(i.e.,carbonated smart water)chemistry improves imbibition rate of carbonated water in oil-wet dolomite rocks as well as the ultimate oil recovery.

Mechanism of active silica nanofluids based on interface-regulated effect during spontaneous imbibition

The ultra-low permeability reservoir is regarded as an important energy source for oil and gas resource development and is attracting more and more attention.In this work,the active silica nanofuids were prepared by modifed active silica nanoparticles and surfactant BSSB-12.The dispersion stability tests showed that the hydraulic radius of nanofuids was 58.59 nm and the zeta potential was−48.39 mV.The active nanofuids can simultaneously regulate liquid-liquid interface and solid-liquid interface.The nanofuids can reduce the oil/water interfacial tension(IFT)from 23.5 to 6.7 mN/m,and the oil/water/solid contact angle was altered from 42°to 145°.The spontaneous imbibition tests showed that the oil recovery of 0.1 wt%active nanofuids was 20.5%and 8.5%higher than that of 3 wt%NaCl solution and 0.1 wt%BSSB-12 solution.Finally,the efects of nanofuids on dynamic contact angle,dynamic interfacial tension and moduli were studied from the adsorption behavior of nanofuids at solid-liquid and liquid-liquid interface.The oil detaching and transporting are completed by synergistic efect of wettability alteration and interfacial tension reduction.The fndings of this study can help in better understanding of active nanofuids for EOR in ultra-low permeability reservoirs.

The enhancement of performance and imbibition effect of slickwater-based fracturing fluid by using MoS_(2)nanosheets

Slickwater-based fracturing fluid has recently garnered significant attention as the major fluid for volumetric fracturing;however,lots of challenges and limitations such as low viscosity,poor salt tolerance,and possible formation damage hinder the application of the conventional simple slickwater-based fracturing fluid.In addition,nanomaterials have proven to be potential solutions or improvements to a number of challenges associated with the slickwater.In this paper,molybdenum disulfide(MoS_(2))nanosheets were chemically synthesized by hydrothermal method and applied to improve the performance of conventional slickwater-based fracturing fluid.Firstly,the microstructure characteristics and crystal type of the MoS_(2)nanosheets were analyzed by SEM,EDS,TEM,XPS,and Raman spectroscopy techniques.Then,a series of evaluation experiments were carried out to compare the performance of MoS_(2)nanosheet-modified slickwater with the conventional slickwater,including rheology,drag reduction,and sand suspension.Finally,the enhanced imbibition capacity and potential mechanism of the nanosheet-modified slickwater were systematically investigated.The results showed that the self-synthesized MoS_(2)nanosheets displayed a distinct ultrathin flake-like morphology and a lateral size in the range of tens of nanometers.In the nano-composites,each MoS_(2)nanosheet plays the role of cross-linking point,so as to make the spatial structure of the entire system more compact.Moreover,nanosheet-modified slickwater demonstrates more excellent properties in rheology,drag reduction,and sand suspension.The nanosheet-modified slickwater has a higher apparent viscosity after shearing 120 min under 90℃ and 170 s^(−1).The maximum drag reduction rate achieved 76.3%at 20℃,and the sand settling time of proppants with different mesh in the nano-composites was prolonged.Spontaneous imbibition experiments showed that the gel-breaking fluid of nanosheet-modified slickwater exhibited excellent capability of oil-detaching,and increase the oil recovery to∼35.43%.By observing and analyzing the interfacial behavior of MoS_(2)nanosheets under stimulated reservoir conditions,it was found that the presence of an interfacial tension gradient and the formation of a climbing film may play an essential role in the spontaneous imbibition mechanism.This work innovatively uses two-dimensional MoS_(2)nanosheets to modify regular slickwater and confirms the feasibility of flake-like nanomaterials to improve the performance of slickwater.The study also reveals the underlying mechanism of enhanced imbibition efficiency of the nano-composites.

Countercurrent imbibition in low-permeability porous media: Nondiffusive behavior and implications in tight oil recovery

Countercurrent imbibition is an important mechanism for tight oil recovery,that is,water imbibes spontaneously from the fracture into the porous matrix while oil flows reversely into the fracture.Its significance over cocurrent imbibition and forced imbibition is highlighted when permeability reduces.We used the computed tomography(CT)scanning to measure the one-dimensional evolution of water saturation profile and countercurrent imbibition distance(CID)at different fluid pressures,initial water saturations,and permeability.Surprisingly,experiments show that CID evolution for tight reservoir cores dramatically deviates from the classical diffusive rule(i.e.,evolutes proportional to square root of time,t^(0.5)).At early stage,CID extends faster than t^(0.5)(super-diffusive);while at late stage,CID extends much slower than t^(0.5)(sub-diffusive).After tens of hours,the CID change becomes too slow to be practically efficient for tight oil recovery.This research demonstrates that this deviation from classic theory is a result of(1)a much longer characteristic capillary length than effective invasion depth,which eliminates full development of a classical displacement front;and(2)non-zero flow at low water saturation,which was always neglected for conventional reservoir and is amplified in sub-mili-Darcy rocks.To well depict the details of the imbibition front in this situation,we introduce non-zero wetting phase fluidity at low saturation into classical countercurrent imbibition model and conduct numerical simulations,which successfully rationalizes the non-diffusive behavior and fits experimental data.Our data and theory imply an optimum soaking time in tight oil recovery by countercurrent imbibition,beyond which increasing exposed fracture surface area becomes a more efficient enhanced oil recovery(EOR)strategy than soaking for longer time.

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.

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.

Pore scale numerical investigation of counter-current spontaneous imbibition in multi-scaled pore networks

The multi-scaled pore networks of shale or tight reservoirs are considerably different from the conventional sandstone reservoirs.After hydraulic fracturing treatment,the spontaneous imbibition process plays an important role in the productivity of the horizontal wells.Applying the color-gradient model of Lattice Boltzmann Method(LBM)accelerated with parallel computing,we studied the countercurrent spontaneous imbibition process in two kinds of pore structures with different interlacing distributions of large and small pores.The effect of geometry configuration of pore arrays with different pore-scale and the capillary number Ca on the mechanism of counter-current spontaneous imbibition as well as the corresponding oil recovery factor are studied.We found that the wetting phase tends to invade the small pore array under small Ca in both types of geometry configurations of different pore arrays of four pore arrays zones.The wetting phase also tends to invade the pore array near the inlet for injecting the wetting phase no matter if it is a large pore array or small pore array except for the situation when the Ca is large to a certain value.In this situation,the small pore arrays show resistance to the wetting phase,so the wetting phase doesn't invade the small pore near the inlet,but invades the large pore preferentially.Both the geometry configurations of different pore arrays and Ca have a significant effect on the oil recovery factor.This work will help to solve the doubt about the selectivity of the multi-scaled pores of the wetting phase and the role of pores with different sizes in imbibition and oil draining in countercurrent spontaneous imbibition processes.

页岩油藏渗吸驱油剂体系性能评价

由于页岩油藏的超低渗透率和复杂的孔隙结构,从页岩油储层中采油仍然是一个重大挑战。表面活性剂作为一种潜在的解决方案,通过降低界面张力和改变润湿性来提高非常规油藏的原油采收率。本研究旨在通过研究页岩油储层的自发渗吸行为,评价表面活性剂在页岩油藏中的应用潜力。结果表明,复配渗吸驱油体系0.15 wt%CA-90+0.15 wt%SDS,在地层条件下界面张力降低至1.03×10^(-2)mN/m;亲油岩心片润湿接触角降低了86°,岩石润湿性由油湿转变为水湿,毛管力由油渗吸驱油阻力转变为渗吸驱油动力;在含水率为70%时,乳状液黏度降低至23.4 mPa·s,其黏度接近原油黏度,但流动性更强,更有利于提高采收率;0.15 wt%CA-90和0.15 wt%SDS的动态吸附量分别为0.85和0.97 mg/g,具有较好的抗吸附能力,对页岩渗透率伤害率低于8%;滑溜水+复配体系的渗吸采收率可以达到31.27%,相比滑溜水体系中自发渗吸采收率(19.43%)提高了11.84%,渗吸驱油效率提高了60.94%,极大地提高了页岩油藏的采收率。

浅层水平缝油藏底部注水研究

延长东部油田主力油层平均中深670 m、平均渗透率0.3~0.5 mD,为特超低渗浅层油藏,油井压裂时易形成水平裂缝,致使注水开发过程中油井出现快速水淹,造成油井产量大幅下降,采收率低。针对这一问题,在对水平缝注水渗流特征、压裂水平缝油井水淹规律和底部注水机理研究的基础上,提出了底部注水开发方式,并应用渗透率变异系数、突进系数、级差3个参数综合表征水窜层位与非水窜层位特征,为底部注水选层提供依据;通过室内核磁共振在线测试及岩心流动驱替实验,结合油藏数值模拟和现场示踪剂测试等综合手段,对注水参数进行了优化。开展底部注水先导性试验的3个井组单井产油量由0.054 t/ d提高到0.179 t/ d,含水率由15%下降到10%,地层压力提高了0.18 MPa,预测最终采收率提高了2.1个百分点,取得了较好效果。研究表明,当渗透率变异系数<0.5、突进系数<1.5、渗透率级差<5,注入速度为0.06 mL/ min,注水压力7 MPa时,注水开发效果最好。底部注水能够有效解决浅层水平缝油藏注水开发效果不佳的问题,为同类油藏的高效注水开发提供了参考。

致密砂岩油藏纳米乳液渗吸增产作用机理

纳米乳液作为一种纳米级胶体分散体系,因其优异的界面性能以及提高采收率效果被广泛应用于非常规油藏开发。基于低能乳化法制备了水包油型纳米乳液体系,通过室内实验明确纳米乳液静态吸附性能、润湿反转性能以及自发渗吸的内在联系,并分析纳米乳液在致密砂岩油藏中的渗吸增产作用机理。实验结果表明:纳米乳液的平均粒径小于10nm,满足进入致密砂岩绝大部分孔喉的粒径要求,在致密孔喉内能充分扩散运移,从而扩大渗吸作用范围。纳米乳液的临界胶束质量分数为0.015%,能够有效降低油水界面张力至2 mN/m左右。纳米乳液的吸附等温线符合Langmuir吸附模型,其润湿反转机理以吸附机理为主。纳米乳液能够增溶原油,并通过乳化作用进一步分散原油,减小乳状液中油滴尺寸,减弱油滴通过孔喉时的贾敏效应,降低渗流阻力。岩心润湿性会影响渗吸采收率,随着岩心亲水性增强而增加,不同润湿性岩心自发渗吸时孔隙动用程度存在差异,加入纳米乳液能显著提高油湿岩心内小孔渗吸采收率。同时,增加纳米乳液浓度与边界开放程度可以提高渗吸采收率,这主要是由于致密砂岩自发渗吸受毛细管力主导,边界开放程度增加能够扩大纳米乳液接触面积,纳米乳液浓度增加能够增强润湿反转作用与乳化作用,从而增强自发渗吸效果。

基于压裂液自发吸入模型的页岩气压裂液滤失定量预测

非常规油气资源开发常使用水力压裂技术提高单井产量,然而压裂现场数据表明,大量压裂液会滞留在地层中导致压裂液的返排率较低,将对储层和地下水环境造成一定影响。为进一步研究压裂液滤失机理并准确预测压裂液滤失量,首先建立了由毛细管力作用引起的压裂液自发吸入模型,然后对压裂液滤失量进行定量计算,并在现场进行了验证。最后,引入无量纲吸入率参数分析了控制压裂液滤失的关键因素。研究结果表明:(1)页岩气水平井压裂施工中大约50%~95%的压裂液通过基质吸入,压裂液吸入量仅与吸入率参数、裂缝面积和吸收时间有关;(2)当润湿相黏度与非润湿相黏度之比超过阈值时,吸入率参数主要由岩石的孔径分布参数决定,流体黏度的影响非常有限;(3)当孔径分布参数介于0.5~0.7时,吸入率参数达到相对较高的值,即更多的压裂液被吸收到地层中;(4)当润湿相黏度与非润湿相黏度之比大于10,孔径分布参数小于0.8时,优化后的自吸模型具有较大的适用性;(5)由毛细管力机理引起的压裂液滤失量与实际储层观察到的滤失量相近,可认为页岩储层有足够的存储滤失液的能力,不会影响地下水层中的饮用水。结论认为,建立的压裂液自发吸入模型,能够准确预测页岩气水平井压裂液滤失量,为非常规油气的生产及环境保护提供了技术支撑。

页岩油渗吸机理及影响因素研究进展

综述了自发渗吸提高采收率机理,包括毛管力、电化学力等,论述了复杂程度不同的页岩渗吸机理模型进展,为数值模拟优化提供参考,总结了自发渗吸提高采收率的控制因素,包括储层岩石、流体性质、温度及压力的影响。指出了自发渗吸提高采收率存在问题及发展方向,为未来提高页岩油渗吸采收率提供理论基础。

致密储层孔隙结构对渗吸的影响研究进展

随着传统油气资源的逐渐枯竭,以致密油资源为代表的非常规油气资源在能源开发和利用方面具有越来越重要的地位。然而,相较于常规储层,致密油储层的孔隙结构非常复杂,其孔隙尺寸分布广泛、孔隙类型多样且孔喉发育,这些因素给致密油储层的开采提出了极大挑战。对致密油储层的孔隙结构及其自发渗吸机制进行深入研究对于提高致密油采收率具有非常重要的意义。基于此,通过文献调研,对致密油储层的孔隙结构和渗吸机理研究进行了综述,从孔隙结构的表征手段、致密油孔隙结构的研究进展、孔隙结构与致密油渗吸机理之间的影响机制等方面进行介绍,并对该领域的研究进展进行了总结和展望。该研究可为致密油储层原油开发提供了借鉴,助推致密油采收技术的发展。

液桥的动态界面特性对液-液自发渗吸的影响研究

在自然界和工业应用中,多孔介质中的多相流动现象普遍存在,如地下水流动、油气开采、非饱和颗粒材料等.在这些过程中,液桥的存在对多相流动产生显著影响.基于改进的液-液自发渗吸理论模型及改进流-固作用力格式的两组分Shan-Chen模型,研究了液桥的存在对毛细管内液-液自发渗吸的影响.结果表明:与不含液桥的渗吸过程相比,液桥的存在使得毛细管内产生3个界面,显著增大了系统的动态接触角,降低自发渗吸速度.随着润湿性的增强,液桥的存在使得界面动态变化特性增强的幅度更大.当液桥的黏度小于非润湿流体的黏度时,整个系统的动态接触角随着渗吸长度的增加而增强;若二者黏度相等,整个系统的动态接触角为一稳定值;而当液桥的黏度更大时,整个系统的动态接触角随着渗吸的进行逐渐减小.将模拟获得的实时动态接触角纳入至渗吸理论中,可以改善由液桥界面动态变化导致的渗吸长度的理论值与模拟结果间存在的偏差,并得到与模拟基本一致的结果.文章还利用模拟数据,系统地评价了Cox-Voinov模型对含有液桥以及不含液桥体系的渗吸过程中的界面动态变化特性及渗吸长度预测能力.