Spontaneous imbibition

Amott-Harvey Indices, in which spontaneous imbibition of, individually, water and oil compared with the maxima possible under forced (pressure) imbibition. These are used to calculate water (WI) and oil (OI) indices reflecting degrees of wettability between neutral and strongly wetting. 

Jadhunandan, R, Morrow, N.R., 1991. Spontaneous imbibition of water by crude oil/brine/rock systems. In Situ 15 (4), 319-345. 

Zhang, P., Tweheyo, M.T., Austad, T., 2007a. Wettability alteration and improved oil recovery by spontaneous imbibition of seawater into chalk Impact of the potential determining ions Ca % Mg, and SO/. Colloids and Surfaces A Physicochemical Engineering Aspects 301, 199-208. 

In the course of measuring imbibition capillary pressures, Morrow (20) also determined residual non-wetting phase saturations as a function of the intrinsic contact angle. For systems which spontaneously imbibe, he found that the residual oil values in- creased as the intrinsic contact angle was increased from 0° to 62°, the limit at which spontaneous imbibition occurs. Therefore, for systems which imbibe, the best recovery should be obtained from strongly water-wet systems. 

Oil-bearing sedimentary rocks are frequently classified as either water-wet or oil-wet porous media, although categories of intermediate and mixed wettabilities are sometimes also set up. Wettability refers variously to spontaneous imbibition of water or oil, to the shapes of the curves of the relative permeabilities versus saturation (fraction of pore volume occupied by a given fluid) or to an apparent contact angle, i.e. the visually observed angle of intersection of a water-oil meniscus with a smooth surface of the rock or of an ostensibly equivalent solid material. 

Amott-Harvey. The wettability test devised by Amott [13] and its modification, the Amott-Harvey Relative Displacement Index (RDI) [14] are the most common quantitative measures of wettability employed for porous media by the oil industry. It relies on measurements of the saturation changes produced by spontaneous imbibition for both water. 

Spontaneous Imbibition Index. The Spontaneous Imbibition Index (SII), as a quantifiable measure of wettability to one fluid component, was defined by Spinier [17] as the ratio of measured spontaneous water imbibition to highly water-wet spontaneous imbibition, ASws-ww ... 

Although SII has only been defined in terms of water imbibition, an analogous definition could be made for oil imbibition. Many of the problems that apply to the Amott indices also apply to SII, but the denominator of SII, once determined for a specific rock type, simplifies the determination of wettability to measurements of spontaneous imbibition. 

Imbibition Rate. Spontaneous imbibition rate has long been considered only a qualitative measure of wettability because the rate is dependent upon fluid and rock properties in addition to wettability. Ma [J5], however, defined a method of quantifying wettability from the rate of spontaneous imbibition using the area under the imbibition curve as a measure of the work of displacement that results from the decrease in surface free energy. Wettability is defined as the ratio of pseudo-work of spontaneous imbibition, W, to the pseudo-work of spontaneous imbibition for strongly water-wet imbibition, Ws ww ... 

Summary. The Amott, USBM, Spontaneous Imbibition Index, imbibition rate, and capillary pressure are all displacement methods applicable to porous media and the possible evaluation of wettability alteration by surfactants. However, these methods must be complemented by more fundamental studies using contact angles or adhesion studies (Wilhelmy), etc. to meld the understanding of surface interactions with the macroscopic displacement of fluids. To comprehend how a surfactant alters the contact angle on a flat surface provides only part of the information to predict how the surfactant will interact in porous media. To measure only the fluid displacement in porous media provides little information on surface interactions. NMR and/or cryomicroscopy could help span this gap. Cryomicroscopy can directly look at pore surfaces, but for the moment, it is difficult and time consuming to use. Both techniques provide more of a qualitative measure of wettability than quantitative, but they are tools that can complement and help bridge between more fundamental measurements and quantitative displacement methods. 

Austad et al. [76] conducted imbibition tests in outcrop chalk that had been aged in crude oil to achieve desired wettabilities. Chalk characterized as nearly oil-wet because of a slow spontaneous imbibition rate, saw a dramatic increase in the countercurrent imbibition rate and in oil recovery when the imbibition water contained 1 weight % dodecyltri-methylammonium bromide surfactant (cationic). This was attributed to a change in wettability to a more water-wet state. The increase in the countercurrent imbibition rate indicated that the loss of capillary forces expected for the decrease in interfacial tension from the surfactant was overcome by the increase in capdlary forces from the wettability change. 

Secondary oil recovery by spontaneous imbibition of water into low-permeable fractured chalk is a well accepted method to improve the oil recovery from water- to mixed-wet rock material [2], Normally, this process is driven by capillary forces, and it may seem a little strange to lower the capillary forces by adding surfactants to the injected water. In the same way as the viscous forces will mobilize capillary trapped water-flooded oil, the gravity forces may be active in displacing the oil by spontaneous imbibition at low IFT [3]. A crossover from a capillary forced spontaneous imbibition (counter-current flow) to a gravity forced imbibition (cocurrent flow) is observed by decreasing the IFT. The status and recent advances in the research in this area will be included in this presentation as well. 

Displacement of Oil hy Spontaneous Imbibition of Aqueous Surfactant Solution... 

Recovery factors from oil reservoirs with use of surfactants and water injection with surfactants can be affected strongly by the rate and level of spontaneous imbibition. Improved oil recovery from low permeability rock may consequently be possible by decreasing the capillary to gravity force ratio, i.e. decrease Mb and Q. This could be done by decreasing IFT between oil and water if the displacement rate does not end up too slow for commercial use. In the following sections, displacement of oU by spontaneous imbibition at high and low IFT are considered for each wettability state water-wet, mixed-wet and oil-wet. 

Figure 20. Oil production as function of time in spontaneous imbibition experiments with and without the cationic surfactant present. (Reproduced with permission from reference 92, copyright 1997 SPE.)...

Spontaneous imbibition of aqueous surfactant solution into low-permeable oil saturated chalk material is complex due to the presence of different forces, i.e. capillary, gravity, and surface tension gradients. In general, it is not recommended to add surfactants to the injection water for a water-wet system. For mixed-wet to oil-wet systems, a properly designed surfactant system may in some cases improve the imbibition of water. In this case, more work is needed to understand the imbibition mechanism. 

Penetration of water into hydrophobic capillaries is retarded or becomes impossible when advancing contact angle exceeds 90°. Wetting of a hydro-phobic surface may be improved by adsorption of surfactant molecules, which are directed with polar groups towards the water phase. Thus, an increase in surfactant concentration leads to gradual decrease of contact angles accelerating spontaneous imbibition. 

Let us consider the spontaneous imbibition of a surfactant solution into a hydrophobic capillary taking into account the possibility of the eventual passing of some surfactant molecules through the meniscus interface to the nonwetted portion of the capillary (Fig. 15). C x,t) and a. x,t) are the local surfactant concentrations (in g/cm ) of the solution inside the capillary and on the capillary surface (in adsorbed state), respectively. A constant surfactant concentration, C(0,t) = Co = constant, is maintained at the capillary inlet. First, the case Co < Cc, where Cc is the CMC, will be considered. 

Equation (19) under the conditions (23) and (24) has a solution only if Cm = constant, which corresponds to / = K j t, the law of spontaneous imbibition. The following mass-balance condition on the moving meniscus surface will be used in this case ... 

Then, at the same concentration Co, a spontaneous imbibition of surfactant solution into the capillary was examined. The linear a-b part of the graph in Fig. 22 corresponds to imbibition at a constant value of advancing contact... 

FIG. 22 Rates of spontaneous imbibition of syntamide-5 solution (Co = 0.1 wt%) into horizontally oriented hydrophobed quartz capillary, r = 6 pm, 0a = 96° against water. The part a-c of the capillary was previously equilibrated with the solution. The regions c-d and d-e-f relate to nonequilibrated parts of the capillary. Rates of forced imbibition were measured at pressure differences 1.3 N/m (part d-e) and 2.6 N/m (part e-f). 

Spontaneous imbibition of microemulsions into hydrophobed capillaries occurs at much higher rates (K = 0.1-1 cm/s ). Under these conditions complete wetting of the capillary surface is realized [23]. 

The results obtained lead to the conclusion that three mechanisms of penetration of nonionic surfactant solutions into hydrophobic capillaries are possible. The first takes place at a high concentration of surfactant, Q > Q. Spontaneous imbibition advances at a high rate but is limited to some finite length Iq, which depends on Q, r, and Gi. The second mechanism is realized when Co< Q. The rate of penetration in this case is much lower, being controlled by the reduced concentration, Cm = constant, near the meniscus. At still lower concentration of bulk solution Cq, the diffusion mechanism of penetration takes place in thin capillaries. The rate of penetration is determined here by the surface diffusion of surfactant molecules in advance of the meniscus. 

Recent laboratory studies have demonstrated the potential utility of borates as alkaline agents in chemical enhanced oil recovery. Compared with existing alkalis, sodium metaborate has an unusually high tolerance toward the hardness ions, Ca + and Mg +, paving the way for the implementation of alkali-surfactant-polymer floods for the large number of high-hardness saline carbonate reservoirs. In the absence of surfactants, borate solutions exhibit a strong tendency for spontaneous imbibition, or uptake into oil-wet or mixed-wet carbonate cores, with consequently improved recovery of oil compared with solutions of other salts and alkalis. 

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