Effect of Drilling Fluids on Rock Surface Properties

Abstract

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.

Formation Damage due to Drilling and Fracturing Fluids and Its Solution for Tight Naturally Fractured Sandstone Reservoirs

“…However, depending on their droplet sizes, emulsions therein can invade reservoir rock and plug pores/pore throats, resulting in diminished hydrocarbon production [7][8][9]; moreover, surfactants which are added for generating emulsions can be adsorbed on rock surface and alter the wettability, which may also cause formation damage [7,10]. Besides the emulsions, suspended solids in the inverted emulsion, which is added for hindering leak-off, may also plug pores/pore throats; and this can make the formation damage even worse [8,11].…”

Wetting alteration of mica surfaces with polyethoxylated amine surfactants

“…Bobek et al (1958) and Amott (1959) both observed that oil-based muds make cores more oil-wet. Since then numerous studies have focused on the wetting effects of muds, their filtrates, or components of oil-based muds (Thomas et al, 1984;Gant and Anderson, 1988;Ballard and Dawe, 1988;Cuiec, 1989;Menezes et al, 1989;Yan et al, 1993;McCaffery et al, 2002;Skalli, 2003). Menezes et al (1989) examined the effects of commercial blends of surfactants on the wettability of quartz surfaces.…”

Wettability and Prediction of Oil Recovery From Reservoirs Developed With Modern Drilling and Completion Fluids

“…One approach to using SBM contaminated cores is to clean the cores and restore to the original reservoir wetting conditions by re-exposure to reservoir fluids. The efficacy of cleaning processes has been studied for WBM and OBM-contaminated cores (e.g., Anderson, 1986;Cuiec, 1989), but studies of cleaning SBM-contaminated cores are limited (McCaffery et al, 2002). Gant and Anderson (1988) tested many common cleaning solvents and combinations of solvents for cleaning cores contaminated with invert emulsion oil-based muds.…”