Experimental investigation of oil recovery during water imbibition

Capillary imbibition and gravity are the main forces acting in fractured reservoirs. The cores used in the laboratory are usually short while experimental investigation of the gravity forces requires long samples. Therefore an experimental study has been carried out on a long core with the length of 116 cm surrounded with a simulated fracture. Kerosene and a synthetic oil with a density very close to brine have been chosen in order to distinguish the capillary and gravity effects during the water oil displacement. After doing many carefully conducted tests at different rates, it is clear that the process is significantly influenced by gravity. The second part of the study involved experiments on the long core surrounded with a simulated fracture where the flow processes are dominated by either co-current or counter-current imbibition. We changed the recovery mechanism from co-current to counter-current by changing the boundary conditions from an advancing fracture water level to an immersion-type mechanism. Our co-current and counter-current experiments on a tall block showed that counter-current imbibition has lower recovery than co-current imbibition. A wettability study was done after cutting the core into many pieces and aging the pieces in crude oil. Different wettability states were obtained by applying different aging times. The cores with different wettability index were subjected to immersion-type experiment. The results showed that more water wet conditions gave higher oil recovery.     

Wettability alteration and spontaneous imbibition in oil-wet carbonate formations

Alkaline/surfactant flooding has been widely tested for its ability to improve oil recovery, but little effort has been made toward understanding the controlling mechanisms and variables. This paper investigates the effect of electrolyte concentration, surfactant concentration and water/oil ratio on wettability, phase behavior, and displacement from a narrow gap. Wettability of calcite can be altered to about intermediate-wet to preferentially water-wet with alkaline/surfactant systems. Anionic surfactant adsorption can be significantly reduced in the presence of sodium carbonate.     

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.     

Wettability alteration and oil recovery by spontaneous imbibition of smart water and surfactants into carbonates

Naturally fractured carbonate reservoirs have very low oil recovery efficiency owing to their wettability and tightness of matrix. However, smart water can enhance oil recovery by changing the wettability of the carbonate rock surface from oilwet to water-wet, and the addition of surfactants can also change surface wettability. In the present study, the effects of a solution of modified seawater with some surfactants, namely C_(12) TAB,SDS, and TritonX-100(TX-100), on the wettability of carbonate rock were investigated through contact angle measurements. Oil recovery was studied using spontaneous imbibition tests at 25, 70, and 90 °C, followed by thermal gravity analysis to measure the amount of adsorbed material on the carbonate surface. The results indicated that Ca~(2+),Mg~(2+),and SO_4~2-. ions may alter the carbonate rock wettability from oil-wet to water-wet, with further water wettability obtained at higher concentrations of the ions in modified seawater. Removal of NaCl from the imbibing fluid resulted in a reduced contact angle and significantly enhanced oil recovery. Low oil recoveries were obtained with modified seawater at 25 and 70 °C, but once the temperature was increased to 90 °C, the oil recovery in the spontaneous imbibition experiment increased dramatically. Application of smart water with C_(12) TAB surfactant at 0.1 wt%changed the contact angle from 161° to 52° and enhanced oil recovery to 72%, while the presence of the anionic surfactant SDS at 0.1 wt% in the smart water increased oil recovery to 64.5%. The TGA analysis results indicated that the adsorbed materials on the carbonate surface were minimal for the solution containing seawater with C_(12) TAB at 0.1 wt%(SW + CTAB(0.1 wt%)). Based on the experimental results, a mechanism was proposed for wettability alteration of carbonate rocks using smart water with SDS and C_(12) TAB surfactants.     

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.     

Surfactant induced reservoir wettability alteration: Recent theoretical and experimental advances in enhanced oil recovery

Reservoir wettability plays an important role in various oil recovery processes.The origin and evolution of reservoir wettability were critically reviewed to better understand the complexity of wettability due to interactions in crude oil-brine-rock system,with introduction of different wetting states and their influence on fluid distribution in pore spaces.The effect of wettability on oil recovery of waterflooding was then summarized from past and recent research to emphasize the importance of wettability in oil displacement by brine.The mechanism of wettability alteration by different surfactants in both carbonate and sandstone reservoirs was analyzed,concerning their distinct surface chemistry,and different interaction patterns of surfactants with components on rock surface.Other concerns such as the combined effect of wettability alteration and interfacial tension (IFT) reduction on the imbibition process was also taken into account.Generally,surfactant induced wettability alteration for enhanced oil recovery is still in the stage of laboratory investigation.The successful application of this technique relies on a comprehensive survey of target reservoir conditions,and could be expected especially in low permeability fractured reservoirs and forced imbibition process.     

Wettability alterations due to aging in crude oil; wettability and Cryo-ESEM analyses

Several studies of fluid distribution and wettability on the pore scale have been reported, but to our knowledge, none of them have attempted to obtain quantitative measurements. In this paper, quantitative wettability results from Cryo Environmental Scanning Electron Microscopy (Cryo-ESEM) are reported and compared to wettability measurements with traditional methods. The wetting properties of sandstone cores, aged in crude oil, have been investigated using the combined Amott/USBM method. The results show that with increasing aging time, the wetting properties changed from water wet to mixed wetting. Pieces of the same cores have then been analyzed using an Electroscan 2020 ESEM with an attached Cryo unit. Combined with Energy Dispersive X-ray Spectroscopy (EDS), these analyses have given images of the surface, showing the liquid distribution and which phase is contacting the mineral surface.The combination of these methods has proved that using a Cryo-ESEM to investigate wetting properties can give very valuable information although the results are somewhat scattered. Compared to the traditional wetting analyses, this method also gives us an image of the liquid distribution, which is a very valuable input for pore network simulation. It is shown that there is a good agreement between the fraction of the pore walls that are contacted with brine and the Amott/USBM index. A new index based on ESEM data is proposed, with the same range as the Amott–Harvey index.Cryo-ESEM avoids two problems encountered in other SEM methods. First, there is no possibility of a coating layer showing up in the element analyses, since these samples are uncoated. Secondly, the same sample can easily be reexamined by simply refracturing.     

The effect of nanoparticles on wettability alteration for enhanced oil recovery: micromodel experimental studies and CFD simulation

The applications of nanotechnology in oilfields have attracted the attention of researchers to nanofluid injection as a novel approach for enhanced oil recovery. To better understand the prevailing mechanisms in such new displacement scenarios, micromodel experiments provide powerful tools to visually observe the way that nanoparticles may mobilize the trapped oil. In this work, the effect of silicon oxide nanoparticles on the alteration of wettability of glass micromodels was investigated in both experimental and numerical simulation approaches. The displacement experiments were performed on the original water-wet and imposed oil-wet (after aging in stearic acid/n-heptane solution) glass micromodels. The results of injection of nanofluids into the oil-saturated micromodels were then compared with those of the water injection scenarios. The flooding scenarios in the micromodels were also simulated numerically with the computational fluid dynamics (CFD) method. A good agreement between the experimental and simulation results was observed. An increase of 9% and 13% in the oil recovery was obtained by nanofluid flooding in experimental tests and CFD calculations, respectively.     

Recent advances in application of nanotechnology in chemical enhanced oil recovery: Effects of nanoparticles on wettability alteration,interfacial tension reduction,and flooding

Chemical methods of enhanced oil recovery (CEOR) are applied for improving oil recovery from different kinds of oil reservoirs due to their ability for modifying some crucial parameters in porous media, such as mobility ratio (M), wettability, spreading behavior of chemical solutions on rock surface and the interfacial tension (IFT) between water and oil. Few decades ago, the surfactant and polymer flooding were the most common CEOR methods have been applied for producing the remained hydrocarbon after primary and secondary recovery techniques. Recently, more attention has been focused on the potential applications of the nanotechnology in enhanced oil recovery (EOR). For this purpose, many studies reported that nanoparticles (NPs) have promising roles in CEOR processes due to their ability in changing oil recovery mechanisms and unlocking the trapped oil in the reservoir pore system. This paper presents a comprehensive and up-to-date review of the latest studies about various applications of nanoparticles (NPs) within the surfactant (S), polymer (P), surfactant-polymer (SP), alkaline-surfactant-polymer (ASP) and low salinity waterflooding processes, which exhibits the way for researchers who are interested in investigating this technology. The review covers the effects of nanoparticles on wettability alteration, interfacial tension reduction and oil recovery improvement, and discusses the factors affecting the rock/fluid interaction behavior in porous media through the nanofluid flooding.     

Drainage and imbibition relative permeabilities at near miscible conditions

The changes in gas and oil relative permeabilities as miscibility is approached are of particular importance in multi-contact miscible displacements. These changes are a function of the detailed phase behaviour of the fluids and their physical properties as well as the properties of the porous medium itself.In this work, we investigate the behaviour of two-phase drainage and imbibition relative permeability curves of four, different, equilibrated fluid pairs from a three component, two-phase system (cyclohexene, isopropyl alcohol and water) that exhibits a critical point at ambient conditions. The tie-lines of these fluid pairs are at varying distances from the system's critical point. Equilibrium phase compositions and interfacial tensions (IFT) were determined for each of the four fluid pairs. Dynamic displacements were then performed in a linear two dimensional, bead-pack. Unsteady state, drainage and imbibition relative permeabilities were determined for the various pre-equilibrated mixtures. The experimental results show a clear change in relative permeability as the fluid pairs approach the critical point. As the interfacial tension decreases the non-wetting phase relative permeability increases more rapidly than the wetting phase relative permeability and hysteresis becomes less important.Two correlations [Coats, K.H., 1980. An equation of state compositional model: SPE J, 20 (5): 363-376.; Whitson, C.H., and Fevang, Ø., 1997. Generalized pseudo pressure well treatment in reservoir simulation. In Proc., IBC Conference on Optimization of Gas Condensate Fields.], commonly used to model the changes in relative permeability with interfacial tension, and the development of miscibility, were compared with the experimental data. The Coats correlation, which uses a single adjustable parameter to model the changes in both relative permeabilities and residual oil saturation as a direct function of the IFT, yielded an unacceptable match to the experimentally determined fractional flow. However the Whitson–Fevang correlation, which relates the changes in relative permeability to the capillary number using two adjustable weighting functions, presents a satisfactory match.     

In situ wettability distribution and wetting stability in outcrop chalk aged in crude oil

This paper reports an investigation of in situ wettability distribution and wetting stability of moderately water-wet and nearly neutral-wet outcrop chalk cores, aged in crude oil at elevated temperature.In this paper, in situ wettability measurements by magnetic resonance imaging (MRI) tomography are shown to give Amott indices that agree well with the standard wettability indices based on average saturations. The in situ method provides information concerning Amott index distribution radially and along the length of the core plugs.Applying multidirectional crude oil flooding during aging, uniform wettability distributions, both radially and axially, were obtained.Tests of wetting stability confirmed that stable wettability alterations for repeated waterfloods and Amott tests were established. The results showed that the core plugs should not be dried or cleaned because this will render the core plugs strongly water-wet. Stable wettability conditions were measured for cores subjected to storage in brine at 90 °C.     

Experimental determination of the matrix-to-fracture transfer functions for oil recovery by water imbibition

Unique determination of the parameters of the triple-exponential matrix-to-fracture transfer functions is of profound importance to accurately simulate waterflooding and determine sweep efficiency in naturally fractured reservoirs. To accomplish this task, two novel approaches are investigated. Firstly, to our knowledge, the first attempt is made to facilitate not only the function values and their derivative, but also the integral to uniquely determine the transfer function parameters from a suite of in-house imbibition data. Secondly, a random number-based algorithm is applied to uniquely compute the parameters, and its results are compared to those generated through a conventional, nonlinear optimization method using spreadsheet software. The inclusion of the random component helps alleviate the inherent tendency of parametric optimization type algorithms to converge to that possible solution, predefined through the guessed values assigned to the parameters as starting values.Through precisely and more importantly uniquely determining the parameters of the matrix-to-fracture transfer function, experimental imbibition data can be correctly matched and better transposed to field applications. The presented approach of simultaneous correlation of the function and its derivative and integral provides an effective method to scale from laboratory experiments to field applications. Comparative studies presented in this paper delineate the outstanding advantages of the presented approach over the previous and frequently utilized function correlation approaches, which do not generally yield unique determination of transfer function parameters. With the help of a mathematically sound, uniquely defined model, a variety of issues pertaining to spontaneous imbibition can be addressed and resulting problems remedied. One such area of application is underbalanced drilling, where precise and advance knowledge of a formation's imbibition behavior would allow for optimized design and minimized formation damage. Another area is exploitation from naturally fractured reservoirs, in the presence of a strong water drive or a waterflood. Detailed understanding of the mechanisms governing matrix, fracture, and fluid interactions will result in optimized development and exploitation strategies.     

渗吸置换提高原油采收率研究进展

渗吸置换作用已逐渐成为非常规油藏和低渗、特低渗裂缝性油藏提高原油采收率的一种重要方式,大量裂缝的存在及细小孔隙发育为渗吸作用的发生创造了有利条件。首先,基于毛细管压力与重力对渗吸的贡献程度,对渗吸模式进行分类;而后,主要聚焦于影响渗吸的各类因素,详细阐述如储层类型、孔渗物性、边界条件、流体(包括原油与渗吸液体)性质等因素对渗吸的影响规律及作用机制,总结了目前使用的研究渗吸的各种实验手段;最后,根据渗吸作用的研究进展,探讨在实验条件确定、黏土水化影响、界面张力优化和渗吸模式选择等方面所面临的问题,并对这些问题的研究前景进行展望。      

鄂尔多斯盆地长7段页岩油渗吸驱油现象初探

鄂尔多斯盆地长7段陆相页岩油储层孔渗小,连通性差,通过单纯的水驱作用难以采出,盆地页岩油的开发主要通过大规模体积压裂增加油水置换面积进而增加采收率.开发实践与室内实验证明,储层流体与井筒流体之间存在渗吸置换现象,且通过油水渗吸置换采出的页岩油占比为15％～40％,为页岩油的有效开发提供了新的思路.通过岩心外边界敞开实验...     

Spontaneous imbibition for mixed-wettability states in sandstones induced by adsorption from crude oil

Wettability control by methods that are of practical relevance to oil recovery is an ongoing problem in wettability research. The preparation of mixed-wettability cores by adsorption from an asphaltic crude oil at elevated temperature and pressure has been investigated. After aging, crude oil was displaced by flow of decalin, an intermediate solvent that was compatible with the crude oil with respect to asphaltene precipitation but not likely to cause undue desorption of polar components of crude oil from pore walls. The decalin was in turn removed by flow of refined oil.In tests of the stability of the induced wetting states obtained by this approach, imbibition measurements were repeated for up to six cycles of imbibition and drainage. In most cases, wettability changed slightly towards water wetness after the first cycle, but there was comparatively little or no change for further cycles of spontaneous imbibition and forced drainage. Factors in preparation of mixed-wet cores such as the volume of decalin used to flush crude oil from the core and the temperature of flushing were investigated during the course of development of the experimental procedures. Once established, the induced wetting states were stable with respect to further flushing with decalin and also to flushing with toluene, a stronger solvent for asphaltenes.In experiments on displacement of brine by high viscosity refined oils, the initial water saturation of mixed wet cores could be readily reduced to much lower values than the water saturation that was present at the time of aging. However, in contrast to the drastic reduction in imbibition rate for cores aged at low water saturation, low initial water saturation obtained by this means had very little effect on subsequent spontaneous imbibition. This observation is consistent with the concept of mixed wettability postulated by Salathiel (1973) [JPT (1973) 12616] that the distribution of water at the time of aging controls the distribution of adsorbed components of crude oil.     

气润湿反转提高采收率实验研究

注气开采是三次采油的一种重要开发方式,在气驱水的过程中,气润湿反转可以使毛细管压力由气驱阻力变为动力,从而提高气驱油效率.用N2和CO2做气驱水实验,研究气润湿反转对提高采收率的影响.实验所用岩心为长庆油田的低渗透率岩心,所用气润湿反转剂属阳离子型氟化物.对气润湿反转前后的岩心做气驱水实验,绘出气润湿反转前后水的采出程...     

Wettability and morphology of mica surfaces after exposure to crude oil

Reservoir wettability is determined by interactions between crude oil and mineral surfaces, mediated by an aqueous phase. Contact angles between immiscible fluids have long been used as probes to assess the effective wetting condition of surfaces after exposure to brine and oil, but there is a limit to the amount of information that can be deduced from contact angles in such nonideal conditions.In this study, atomic force microscopy (AFM) has been used to observe mica surfaces treated with a series of crude oils that produce a wide range of wetting conditions—water-advancing contact angles on these surfaces vary from water-wet to oil-wet. In the most water-wet case, the only adsorbed features appear to be small, water-wet particles that are probably inorganic. All of the other oils deposited organic coatings, with varying thickness, morphology, and durability. Weakly water-wet systems exhibited many surface features, but the waitings tended to be unstable and to detach from the surface, especially during AFM scanning in water. The most oil-wet systems exhibited thick, stable organic coatings that were not disturbed by AFM scanning.     

凝析油气藏气湿反转解水锁的实验研究

气湿反转是目前解决油气藏水锁损害的有效方法之一.通过溶胶-凝胶法和氟烷基甲基丙烯酸共聚物Zonyl 8740的修饰,使岩心表面的润湿性发生了气湿反转.通过做接触角测量实验,发现溶胶的陈化时间、溶胶-凝胶处理时间、热处理温度、氟化浓度和氟化时间对岩心的浸润性有明显的影响.毛细管上升实验结果表明,用溶胶和Zonyl 8740处理后,气/水体系和油/气体系中的润湿性由优先液湿转变为气湿.利用扫描电子显微镜对处理岩心表面的形貌和能谱进行分析显示,用溶胶和Zonyl 8740共同处理岩心后,岩心表面具备了微细的粗糙结构和低表面能物质.岩心驱替实验结果表明,通过Zonyl 8740处理后,岩心中水的渗透率比未处理时增大了4倍.     

Adsorption kinetics and enhanced oil recovery by silica nanoparticles in sandstone

This study addresses adsorption kinetics of silica nanoparticles on sandstone mineral surfaces and Enhanced oil recovery (EOR) by nanoparticles. It was shown that nanoparticle adsorption on quartz which is the major constituent of sandstone reservoirs was best described as second order process. Both rate and equilibrium adsorption increases with salinity. However, salinity reduces Intraparticle diffusion while enhancing film diffusion. Spontaneous imbibition with nanoparticles dispersed in low salinity water showed higher incremental recovery which may be due to increased structural disjoining pressure. This was supported by surface forces analysis based on particle size and zeta potential measurements of the nanofluids.     

Wettability/spreading of alkanes at the water–gas interface at elevated temperatures and pressures

The Hamaker–Lifshitz theory is used to calculate the spreading coefficient of alkanes on water or brine at elevated temperatures and pressures. The dielectric polarizability at elevated temperature and pressure is estimated as a function of density through the Clausius–Mosotti equation. When complete data is not available, the wetting transition can be estimated from the refractive index at elevated temperatures and pressures. The spreading of alkanes on brine can also be estimated from the refractive index of the brine as a function of electrolyte concentration. The approach used here for alkanes is also used to estimate the conditions for the spreading of H₂S between water and sulfur.