This paper describes experimental studies of spontaneous imbibition of oil by water in a low-permeability outcrop chalk. At constant and high interfacial tension (IFT), the importance of capillary forces and the existence of a predominantly countercurrent mechanism were established. Additional experiments were performed to investigate the influence of length and of various boundary conditions. In another investigation, we modified the IFT at the sample boundary by using pairs of conjugate phases of the n-hexane/ethanol/brine ternary system. Final recovery increased when IFT was lowered. We give a numerical interpretation for this last result.

To emphasize the occurrence of non-water-wet reservoirs, a literature review of this topic is made followed by a description of our findings concerning the evaluation of the wettability of some 20 reservoirs from Europe, North Africa and the Middle East. Then this paper describes various experimental contributions to the understanding of rock/crude-oil interactions which are responsible for the occurrence of such reservoirs. The major role of heavy fractions, especially asphaltenes, has been shown in various ways, whereas low-boiling-point cuts (< 350 °C) were not able to induce wettability changes. Moreover, it appears that, among intermediate fractions of a crude oil, some may change the surface properties of rocks, depending on the type of rock. Our research also confirms that various pure-acid and basic-organic compounds with low molecular weight are not able to induce wettability changes in various kinds of porous media.

We have investigated the interactions between organic acids and a calcite powder by adsorption from an organic phase (benzoic acid and lauric acid in toluene) and from an aqueous phase (benzoic acid and lauric sodium salt. In addition to the experimental study, ab initio quantum chemistry calculations were performed for cluster models, simulating the interactions of molecules with calcite surface sites. At the toluene/calcite interface, acids chemisorb on surface calcium ions, replacing surface hydroxyls resulting from the previous surface hydration by water. This surface saponification phenomenon was predicted by ab initio calculations and confirmed by spectroscopic techniques. The adsorbed acids conferred a hydrophobic character to calcite, with the higher contact angles in water for the longest alkyl chains in the organic acid. At the water/calcite interface, organic acids do not displace water. As electrostatic forces determine the stability of thin water films between calcite and crude oils at reservoir conditions, from our calculations, we deduce that when crude oil fills the biggest pores of the reservoir rock, oil/calcite interfaces appear where the adsorption of organic acids can change the wettability to oil-wet. By contrast, the mineral should remain water-wet at places where the capillary pressure has not been able to thin the aqueous phase beyond a critical value at which the film would collapse. This can occur even if the aqueous phase contains dissolved organic acids transferred from crude oil. Mixed wettability patterns might therefore be related to the spatial distribution of pore sizes. Our results support the latter conclusion in the specific case of organic acids with calcite. P. 889

Summary This paper discusses the wettability change induced by contact between porous media and drilling fluids and the possibility of eliminating such alterations by cleaning. Three porous media were studied (sandstone, shaly sandstone, and carbonate), as well as various drilling fluids (oil-and water-based). Initially strongly water-wet (hydrophilic) and initially neutral rock/oil/brine systems were evaluated. Wettability was estimated by a test based on spontaneous and forced displacement experiments. The results show that all the oil-based drilling fluids used induce a wellability change inasmuch as the rock is initially water-wet. The rock surface properties are observed to be affected at a distance greater than 0.6 in. [greater than 1.5 cm] from the rock/drilling-fluid interface. Cleaning procedures with toluene and methanol circulations can return the rock surface to the original wettability state, but the permeability remains affected. Water-based drilling fluids made no appreciable change in the wettability of the three initially highly hydrophilic porous media. Introduction Some fluids used for core drilling, completion, and workover damage the reservoir rock properties in the near-hole vicinity because of the creation of an emulsion, the hydration of clays, the migration of fines from the formation, the precipitation of salts, the modification of wettability, etc. Likewise, solids present in such fluids may penetrate into the porous medium and reduce flow possibilities. The productivity of production wells may be affected for one or several of these reasons. The same damage may occur in reservoir-rock samples taken for the purpose of performing laboratory experiments. The changes in the wettability parameter in such a case are particularly important because of the major role played by this parameter during experiments to determine capillary pressure, relative permeabilities, and displacement efficiency, all of which are indispensable for making production forecasts. The problem of the representativity of samples used in the laboratory may thus occur. Research showing that the wettability of rock/fluid systems is modified as the result of contamination by various drilling fluids dates from the late 1950's. But for some 30 years, many changes have occurred in the composition of drilling muds, especially with regard to oil-based muds, and little laboratory research has been done recently on the topic under consideration. Our research concentrated on evaluating the wettability change obtained as the result of contact between three porous media having different natures and drilling fluids-five oil-based and five water-based fluids. For the oil-based fluids, the analysis included both highly hydrophilic samples and samples with neutral or intermediate wettability. The change in wettability at a distance of 0.6 in. [1.5 cm] from the solid/drilling-mud contact surface was also evaluated. For water-based drilling fluids, experiments were performed solely with samples that were originally highly hydrophilic. Likewise, when great changes in wettability were observed, cleaning by solvents was performed to try to restore the original wettability. Experimental Rocks. A pure sandstone (Fontainebleau sandstone), a shaly sand-stone (Vosges sandstone), and a carbonate (Rouffach limestone), all three taken from outcrops, were used. Their mineralogical compositions, as well as their porosities and permeabilities, are given in Table 1. Fluids. The composition of the five oil-based drilling fluids is given in Table 2, while that of the five water-based drilling fluids is given in Table 3. The brine used was 30 g/L of NaCl. The oils used were Soltrol 130 refined oil (at 68deg.F [20deg.C], density was 57.17deg.API [0.75 g/cm3) and viscosity was 1.6 cp [1.6 mPa-s]) and a crude oil from southern France (at 68deg.F [20deg.C], density was 20.32deg.API [0.932 g/cm3) and viscosity was 450 cp [450 mPas]). The latter oil contained 10.6 wt % asphaltenes and 6.9 wt % resins. It also had an acid number of 0.5 mg KOH/G and a base number of 1.8 mg KOH/g. Preparation of Samples. Samples 1.6 in. [4 cm] in diameter and 2.2 in. [5.5 cm] long were cut from blocks of the three porous media. To simulate the case of highly hydrophilic reservoir rocks before contact with mud, the samples were prepared by saturation with brine followed by refined Soltrol oil flooding to establish initial oil and brine saturations, Soi and Swi. To simulate the case of originally less-hydrophilic reservoirs, flooding by refined oil was replaced with flooding by crude oil. Then the samples considered were "aged" in this same oil for 10 days at 176deg.F [80deg.C] under pressure. Samples 2.75 in. [7.0 cm] in diameter and 3.35 in. [8.5 cm] long were also cut out and saturated with brine and refined oil. As we will see below, they were used for studying the penetration of the mud constituents beyond the rock/mud contact surface. Contamination by Drilling Fluids. After initial oil and brine saturations were established (and after aging in crude oil for the simulation of less hydrophilic reservoirs), the samples were placed in a cell containing the drilling fluid previously heated to 176deg.F [80deg.C] and homogenized according to API Specification 13A. Then, with the samples submerged in the drilling fluid, the temperature was maintained at 176deg.F [80deg.C), and a pressure of [10 bar 106 Pa] was established on the mud phase for about 10 hours. Finally, the temperature was reduced to 68deg.F [20deg.C) and the pressure to atmospheric pressure for 10 days. This treatment roughly aimed to simulate possible contamination conditions of reservoir rock samples during coring and storage before being used in the laboratory. After being aged in the oil- or water-based drilling fluid, samples 1.6 in. [4.0 cm] in diameter were rinsed lightly with refined oil to remove any solid deposits present on the surface before the evaluation of their wettability. After being aged in the oil-based drilling fluid, samples 2.75 in. [7.0 cm) in diameter were cut out with Soltrol 130 as the bit lubricant to remove 0.6 in. [1.5 cm] of matter from all their faces (Fig. 1). This operation reduced them to the size of the preceding samples. The wettability was then evaluated. An identical treatment was performed by submerging the samples in the diesel oil used as the oil base for preparing the oil-based drilling fluids, to be able to separate the possible influence of diesel oil from the influence of the other ingredients. Evaluation of Wettability. The wettability was evaluated by a test very similar to the one proposed by Amott. The variant used is described in the Appendix (see also Refs. 4 and I 1). This type of test is considered one of the most reliable ways of evaluating wettability in the petroleum profession. For samples containing crude oil, we checked to see that no asphaltene precipitation occurred during the Soltrol 130/crude-oil contact. During previous research the maximum deviation of the wettability index around the average value was evaluated for sample batches having identical or very similar characteristics. The following results were obtained.

Summary We have investigated the interactions between organic acids and a calcite powder by adsorption from an organic phase (benzoic acid and lauric acid in toluene) and from an aqueous phase (benzoic acid and lauric sodium salt). In addition to the experimental study, ab initio quantum chemistry calculations were performed for cluster models, simulating the interactions of molecules with calcite surface sites. At the toluene/calcite interface, acids chemisorb on surface calcium ions, replacing surface hydroxyls resulting from the previous surface hydration by water. This surface saponification phenomenon was predicted by ab initio calculations and confirmed by spectroscopic techniques. The adsorbed acids conferred a hydrophobic character to calcite, with the higher contact angles in water for the longest alkyl chains in the organic acid. At the water/calcite interface, organic acids do not displace water. Our results support the possible existence of mixed wettability patterns, related to spatial distribution of pore sizes, in the specific case of organic acids with calcite. Introduction The wettability of reservoirs is an important parameter when evaluating oil recovery processes.1 Most of the carbonate reservoirs are considered oil-wet or mixed-wet, even if it is generally assumed that a pure carbonate rock is originally strongly water-wet. This wettability change is assigned to the adsorption of some crude oil compounds, mainly with carboxylic charged ends, on the mineral surface. Two mechanisms can be proposed depending on water film stability:diffusion of acid molecules through the water film anddirect adsorption from the bulk organic phase. In order to evaluate these two possibilities, the adsorption of benzoic acid and lauric acid on calcite has been investigated, using ab initio quantum chemistry calculations and adsorption at solid/liquid interface from an organic phase (toluene) and from an aqueous phase. The techniques used are thermogravimetry, infrared diffuse reflection, and thermal analysis linked to a mass spectrometer. Wettability changes induced by adsorption were evaluated by contact angle measurements. Materials and Methods Materials. The carbonate used in this study is a synthetic, pure, and well-crystallized calcite powder, provided by Rho?ne-Poulenc Chemicals (Calofort U.). Its specific surface area, determined by nitrogen adsorption, according to Villiéras' method,2 is 23.8 m2/g. The powder was kept in an oven at 105°C. The average density of surface calcium ions was evaluated to 28.1 Å2, according to Donnay-Harker morphology.3,4 The adsorbates, benzoic and lauric acids, were provided by Aldrich, with purities higher than 99.5%. Lauric sodium salt was synthesized from lauric acid and caustic soda.5 Adsorption experiments were carried out in two qualities of toluene and in pure water:toluene Rectapur (Prolabo) which contains 211 ppm of water at 99+% purity,toluene HPLC (Aldrich) which contains only 60 ppm of water, at 99.8% purity. Methods. Ab initio calculations: a first-principles quantum chemistry method was used to compute adsorption enthalpies or binding energies: the density functional theory, as implemented in DMOL V.300.3 The isolated molecular models, or bound complex geometries were first optimized at the local density approximation level (VWN), and then the gradient corrections (Becke 88+Lin-Yang-Parr) were applied to energies. These calculations required up to several weeks on a Silicon Graphics Power Indigo 2 R8K workstation. Calcite surface charge was measured with a Sephy zetaphoremeter II, where particles displacement speed is determined by analysis and comparison of successive images taken during application of a given voltage between two electrodes. This electrophoretic mobility is directly related to the zeta potential, via the Smoluchowski equation. Measurements were performed from 1 g L?1 calcite suspension using pure water or brines with different salinities: 0.01 M NaCl, 0.01 M NaCl 2, and 0.1 M NaCl. Suspensions were stirred by magnetic agitation during one night and pH was modified by addition of 0.01 M NaOH or HCl solutions. Adsorption isotherms were carried out in a batch with 2 g of calcite in 100 cm 3 for toluene and 0.5 g of calcite in 200 cm3 for water. Equilibration time was 7 days for both solvents. Solid/liquid separation was then carried out using 0.45 ?m Millipore filters. Concentration of adsorbates in water was determined using UV spectroscopy (Spectrophotometer UV 5260 from Beckman) for benzoic acid and total carbon measurement for lauric acid. Adsorbed amounts onto the mineral surface were also measured by thermogravimetry which allowed the tracking of weight loss due to the thermal desorption of adsorbed molecules.6 The sample was put in a crucible and heated at 10°C/min, under helium, up to 900°C, using a Setaram TAG24 thermobalance. Diffuse reflectance infrared Fourier transform spectroscopy (DRIFTS) was used to determine the state of adsorbed organic acids on the mineral surface,7 using an IFS55 Brucker spectrometer. The influence of adsorption on wettability was evaluated by contact angle (?) measurements on compacted powder. 1-cm-diam pellets were made with 100 mg of treated powder under pressure (200 kPa cm?2). The pure water drop profile was recorded in purified dodecane and the contact angle was calculated using a G40 KRUSS goniometer.