A rotating-disk instrument was used to measure the dissolution rates of both calcite and dolomite rock samples in HCl solutions. The results of more than 60 experiments are reported in this paper. The effect of common acidizing additives on the rock dissolution rate is measured for different acids containing quaternary amines, polymer, surfactant, mutual solvent, iron-chelating additive, and dissolved iron. Measurements are made at 23 and 50°C for calcite and dolomite marble samples. Marble samples from Turkey, Greece, and Italy were analyzed to find suitable reference materials. Marble composed of 100% calcite (calcite marble) as well as 91% dolomite (dolomite marble) was used and compared very well with previously published results. Results of rock dissolution rates with common acidizing additives showed significant differences. • 1.5 vol% cationic acrylamide copolymer decreased the calcite and dolomite dissolution rates significantly. At 1,000 rpm, the calcite dissolution rate with 1.5 vol% polymer and 0.1 M (0.36 wt%) HCl had a value that was 11.4% of the value measured with 0.1 M of HCl alone. • Polymer changed the acid/rock reaction from mass-transferlimited to surface-reaction-limited with both calcite and dolomite. This surface effect is possibly caused by polymer adsorption. • 10 vol% mutual solvent increased the acid dissolution rate by 9% for calcite and by up to 29% for dolomite. • 5000 mg/L iron (III) resulted in surface deposition of iron (III) hydroxide for both calcite and dolomite. At low rotational speeds, this surface layer had an inhibiting effect on the dissolution rate. • 2 vol% corrosion inhibitor decreased the calcite dissolution rate by approximately 9%. • Citric acid at 12 g/L decreased the calcite dissolution rate by an average of 9%, possibly because of the formation of calcium citrate at the surface. • 0.2 vol% nonionic surfactant had no significant effect on the acid dissolution rate of calcite.

Summary This paper examines a new class of viscoelastic surfactants (amphoteric) that are used to enhance sweep efficiency during matrix acid treatments. It appears that surfactant molecules align themselves and form rod-shaped micelles once the acid is spent. These micelles might cause the viscosity to significantly increase, and induce viscoelastic properties to the spent acid. The enhancement in these properties depends on the micelle shape and magnitude of entanglement. The effects of acid additives and contaminants [mainly iron (III)] on the rheological properties of these systems were examined over a wide range of parameters. Viscosity measurements were conducted using specially designed viscometers to handle very corrosive fluids. Measurements were made between 25 and 100°C, and at 300 psi at various shear rates from 58 to 1,740 s-1. Acid additives included corrosion inhibitors, inhibitor aids, an iron control agent, a hydrogen sulfide scavenger, an anti-sludge agent, and a nonionic surfactant. Effects of mutual solvents and methanol on the apparent viscosity were also investigated. It is observed that temperature, pH, shear conditions, and acid additives have a profound influence on the apparent viscosity of the surfactant-acid system. The viscosity and related properties are very different from what were observed with both natural and synthetic polymers. The differences in these properties were characterized and correlated with the type and nature of the additives used. Optimum conditions for better fluid performance in the field were derived. Introduction Previous studies (Thomas et al. 1998) highlighted the need for proper diversion during matrix acidizing treatments of carbonate reservoirs. Various systems were introduced to enhance diversion by increasing the viscosity of the injected acid. Depending on the viscosifiying agent, these systems can be divided into two main categories: polymer-based acids and surfactant-based acids. Acid-soluble polymers have been used to increase the viscosity of HCl, and to improve its performance (Pabley et al. 1982; Crowe et al. 1989). As the viscosity of the acid increases, the rate of acid spending decreases and, as a result, deeper acid penetration into the formation can be achieved (Deysarkar et al. 1984). Addition of suitable synthetic or natural polymers to HCl improved acid penetration; however, acid placement did not significantly improve (Yeager and Shuchart 1997). Crosslinked acids were introduced in the mid-70s, as cited by Metcalf et al. (2000). These acids have much higher viscosity than regular acids or acids containing uncross-linked polymers. Two types of crosslinked acids are available The first type consists of a polymer, a crosslinker, and other acid additives [e.g., corrosion inhibitors and iron control agents (Johnson et al. 1988)]. The acid in this case is crosslinked on the surface and reaches the formation already crosslinked. The second type of crosslinked acid consists of a polymer, a crosslinker, a buffer, a breaker, and other acid additives. The acid in this case reaches the formation uncrosslinked, and the crosslinking reaction occurs in the formation (Yeager and Shuchart 1997; Saxon et al. 2000). In-situ gelled acids were the subject of several lab and field studies. In general, lab and field results were positive; however, there were several concerns raised about these acids. Taylor and Nasr-El-Din (2002, 2003) noted that in-situ gelled acids caused loss of core permeability in tight carbonate cores. Permeability loss was attributed to polymer retention in the core and on the injection face of the core. A similar observation was noted by Chang et al. (2001). Lynn and Nasr-El-Din (2001) noted precipitation of the crosslinker (iron) when in-situ gelled acids were used to enhance the permeability of tight cores at high temperatures. Nasr-El-Din et al. (2002) showed that the crosslinker (Fe(III)) may precipitate in sour environments. Mohamed et al. (1999) reported poor field results when large volumes of polymer-based acids were used to stimulate seawater injectors with tight carbonate zones.

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Surfactants have been used over the past few years as a diverting material when mixed with acid solutions. Several papers are aimed to understand the overall process and the diversion capability. However, most of the coreflood experiments, if not all, used relatively short cores usually ranging between 2 to 6 inches in length and 1 to 1.5 inches in diameter. In this paper and for the first time, 20 inches long cores were used in conducting the acidizing experiments. The lithology of the rock type used was calcite, which has permeability of 50 to 120 md. In addition to the appropriate surfactant concentration, 15 wt% HCl was used. A key parameter such as flow rate, affects the behavior of the gelling material significantly. Therefore to capture that effect, flow rates chosen to be representative ranged between 5 and 15 cm 3 /min. A further analysis included is the effluent concentration for the mineral composition mainly Ca ++ . In addition, the acid concentration in the effluent was measured and validated with an analytical model to address the acid profile along the wormhole, which becomes an important aspect in understanding the flow of VES fluids in carbonate cores.Part of this study is to characterize the wormhole propagation expected from the acidizing process. To accomplish this task, computerized tomography (CT) was used to generate 3-D images to describe the shape of the wormhole. There is a major difference in the shape of the wormhole when using the diverting material compared to conventional acids. The wormhole path observed in the first case tended to have several changes in direction as the acid tried to find its way to propagate further and avoid any possible blockage caused by the diverting material. This phenomenon would not be captured with short cores that were used in the previous studies.