Summary Hydrochloric (HCl) acid is used to stimulate carbonate formations in both matrix and fracturing treatments. However, the reaction rate of the acid with calcite is fast. In addition, the viscosity of regular HCl solutions is relatively low. Acid-soluble polymers are usually added to the acid to increase its viscosity, which is needed to enhance acid diversion during matrix acidizing and reduce acid leakoff rate during acid fracturing. Gelled acids are extensively used in matrix and acid-fracturing treatments performed in carbonate formations. However, a few studies examined the impact of these polymers on the reaction of HCl acids with calcite. This paper uses a rotating disk instrument to measure the dissolution rate of calcite by use of gelled acids. Measurements were conducted over a temperature range of 25 to 65°C, a pressure of 1,000 psi, and rotational speeds of 100 to 1,000 rpm. Acid formulations that are typically used in the field were examined. Polymer concentration was varied from 0.5 to 2 wt%. The apparent viscosity of the gelled acid was measured with a Brookfield viscometer. Measurements were done for the same solutions tested with the rotating disk instrument. The temperature was varied from 25 to 100°C, while the pressure was maintained at 300 psi. The shear rate was varied from 57 to 1,700 s-1. Evidence of reverse and toroidal flows was noted for the first time by examining the etching patterns of the reacted disks. The etching pattern on the surface of the disk depended, among other factors, on the disk rotational speed and polymer concentration. There was a significant increase in the apparent viscosity of gelled acids and a major decrease in the dissolution rate as the polymer concentration was increased from 0.5 to 1.5 wt%. The reaction of gelled acids with calcite was controlled by a surface reaction at 25°C, and by mass transfer at 65°C. Temperature increased the dissolution rate of calcite at all conditions examined. It did also reduce the viscosity of the gelled acid, which affected the way the acid reacted with calcite. Introduction Carbonate reservoirs are heterogeneous, with large variations in rock permeability. Stimulation fluids, in matrix acidizing, will flow through the path of the least resistance where the permeability is high or the damage (skin) is low. There is a need for proper fluid diversion to enhance the outcome of matrix acid treatments. One way to enhance diversion is to increase the viscosity of the acid (Woo et al. 1999). High viscosity is also needed in acid-fracturing treatments to achieve deep acid penetration and longer fractures (Deysarkar et al. 1984). Gelled (Pabley et al. 1982; Johnson et al. 1988; Crowe et al. 1989; Nasr-El-Din et al. 2002a) and in-situ gelled acids (Mukherjee and Cudney 1993; Magee et al. 1997; Yeager and Schuchart 1997; Buijse et al. 2000; Saxon et al. 2000; Taylor and Nasr-El-Din 2003) have been used to increase the viscosity of the acid on the surface or in the formation. An acid-soluble polymer is typically added to the injected acid to increase its viscosity on the surface. A suitable polymer, a crosslinker, and a breaker are added to the acid to form a gel in the formation over a certain pH range. To overcome some of the concerns raised about polymer-based acids, visco-elastic surfactants (Nasr-El-Din et al. 2006) were introduced to replace high-molecular-weight polymers, which are thought to cause formation damage (Lynn and Nasr-El-Din 2001). Similar to other acid additives, polymers can affect the way the acid reacts with the rock. Several authors reported that the addition of polymers to the acid decreased the dissolution rate of rock by the acid (Taylor et al. 2004a) and the diffusivity of H+ (Hansford and Litt 1968; Mishra and Singh 1978; de Rozieres et al. 1994). There are several ways that polymers can affect the reaction of the acid with the rock. The polymer will increase the viscosity of the acid, which will reduce the diffusion rate of H+ from the bulk solution to the surface of the rock. Polymer molecules can adsorb on the rock surface and form a barrier that reduces acid reaction with the rock. Finally, polymers can change the flow pattern close to surface of the rock, and therefore, affect the way the acid reacts with the rock. The present study uses the rotating-disk instrument to examine the reaction of gelled acids with calcite. This instrument has been extensively used to investigate the reaction of acids and chelating agents (Newtonian fluids) with carbonate rocks (Boomer et al. 1972; Lund et al. 1975; Anderson 1991; Fredd and Fogler 1998a, 1998b, 1998c; Conway et al. 1999; Gautelier et al. 1999; Alkattan et al. 1998, 2002; Frenier and Hill 2002; Taylor et al. 2004b, 2006; Lungwitz et al. 2007). It has been also used to study mass and heat transfer into non-Newtonian fluids (Hansford and Litt 1968; Mishra and Singh 1978; de Rozieres et al. 1994). The reaction between acid and rock is a three-step process that involves the following:Transport of the H+ from the bulk solution to the rock surfaceReaction at the surfaceTransfer of the reaction products away from the surface The slowest step controls the overall reaction rate (de Rozieres et al. 1994). The objectives of the present study are to (1) examine the effect of polymer concentration and disk rotational speed on the etching pattern on the surface of the rock; (2) assess the effect of polymer concentration, temperature, and disk rotational speed on the dissolution rate of calcite by use of gelled acids; and (3) determine the relationship between the apparent viscosity of gelled acids and the dissolution rate of calcite rock.

Fracture acidizing has been a dominant practice in the industry to enhance well productivity in low-permeability carbonate reservoirs. Many acid systems have been developed to improve this stimulation process. The most desirable characteristics for an acid system to be suitable for fracture acidizing are leakoff control and retarded reaction rate. These characteristics are required for deep acid penetration, so that when the fracture closes, long flow channels are etched on the fracture surfaces. Leakoff control can be achieved by pumping a pad containing a viscosifying agent or solid bridging agents to plug wormholes generated by acid dissolution. Reaction retardation is attempted usually by lowering the effective diffusivity of the hydrogen ion.It is well known that during an acid-fracturing operation, the overall reaction rate of hydrochloric acid (HCl) with limestone is mass-transfer-limited. Designing the treatment requires knowing the effective diffusivity of the hydrogen ion in the acid system, which, to the best of the authors' knowledge, has not been determined before. Because of their combined leakoff-control and retardation capabilities, surfactant-based acids have been used in acid-fracturing treatments. Because more carbonate reservoirs are treated by use of this acid system, it is important to obtain the effective diffusivity of H + .The rotating-disk device has been used to investigate the reaction kinetics between a reactive solution and carbonate rocks because the thickness of the boundary layer is uniform throughout the disk surface. This paper discusses the reaction-rate data generated recently for surfactant-based acid by use of a rotating-disk apparatus and presents the methodology used to determine the effective diffusivity from the measurements.The results obtained indicated that the viscoelastic surfactant examined (carboxybetaine-type) reduced the dissolution rate of calcite with HCl acid. The surfactant reduced the diffusion coefficient for H + . The effect of temperature on the diffusion coefficient did not follow the Arrhenius law.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractSurfactant-based acids have been extensively used in matrix and acid fracturing treatments in carbonate formations. As the acid spends and the pH rises, the surfactant molecules aggregate and form long entangled micelles, which enhance the apparent viscosity of the solution. The high viscosity is required for proper acid diversion, which is needed in horizontal and vertical wells with long target zones. Successful field data were obtained with surfactant-based acid, however the impact of the viscoelastic surfactant used on the reaction of the acid with the rock was not systematically examined before. Therefore the objective of the present work is to examine in detail the effect of a viscoelastic surfactant (amphoteric) on the reaction of HCl acid with calcite.The reaction between calcite and surfactant-based acids was thoroughly investigated using the rotating disk apparatus. The effects of disk rotational speed, surfactant concentration and temperature on the dissolution rate were determined. All experiments were conducted using 20 wt% HCl and various combinations of corrosion inhibitor and surfactant concentrations. The system pressure was maintained at 1,000 psi and the reaction was allowed to proceed for 20 minutes only. Samples from the reaction vessel were collected at various times and were analyzed for calcium using ICP. The apparent viscosity of surfactant-based acids was measured as a function of shear rate, temperature, and surfactant concentration using a HTHP Brookfield viscometer.The results obtained indicated that the viscoelastic surfactant significantly reduced the dissolution rate of calcite with HCl. This trend continued as the concentration of the surfactant was increased to 4 wt%. The effect of temperature on the dissolution rate was similar to that of temperature on the apparent viscosity of surfactant solutions where there was a maximum in viscosity at 50-60°C. The dissolution rate was controlled by mass transfer of H + to the surface of calcite.

High pH borate gels have been used in fracturing deep gas reservoirs in Saudi Arabia. Guar and hydroxypropyl guar are used at various concentrations up to 45 lb/1000 gals. A breaker (regular or encapsulated oxidizers, guar-specific enzyme, or combinations of these breakers) is usually used to degrade the gel after the fracturing treatment. Field results indicated that the cleaning time following fracturing treatments was too long. Unbroken gel was noted in the flow back samples of some wells. This study was conducted to assess the effectiveness of various breakers that are used in the field, and determine other parameters that may affect the time needed to clean-up fractured wells. This paper presents the results of a detailed study done to evaluate the performance of several breakers at typical field conditions. The apparent viscosity of various borate gels was measured as a function of breaker type and concentration. Gel degradation was followed in a high temperature/high pressure see-through cell. The surface tension of various gel filtrates was measured as a function of temperature up to 150°C. Viscosity measurements indicated that all oxidizers degraded high pH borate gels, however the time needed to degrade the gel was found to be a function of breaker type and concentration; temperature and polymer loading. All guar-based gels produced a residue after reacting with the breaker. This residue was noted irrespective of the type and concentration of the breaker used. The residue was noted with gels formed using either guar gum or hydroxylproply guar. This residue may adversely affect the conductivity of the fracture. Surface tension measurements indicated for the first time that the surface tension of borate gels is high, which will enhance water blockage and hence reduce gas production. This paper examines factors affecting gel degradation, surface tension of borate gel filtrate, and their impact on well productivity. Introduction Hydraulic fracturing is often necessary for oil and gas wells to enhance well productivity. The fracturing fluid is one of the most important components in hydraulic fracturing treatments.1 The fluid is used to create fracture and transport proppant down the created fracture. To make the fracturing operation successful, the fracturing fluids need to possess certain properties such as sufficiently viscous to suspend and transport proppants, suitable at pumping temperature, having low friction pressure, having moderate efficiency, resistant to shear degradation, can be removed efficiently from the fracture, and economically realistic.1 Guar and guar derivatives; HPG (hydroxypropyl guar), and CMHPG (carboxymethyhydroxypropyl guar), are the most commonly used polymers to prepare water-based fracturing fluid.2 High viscosity is generated by crosslinking polymer molecules with a crosslinker (B(III), Ti(IV), or Zr(IV)).1 Borate gels have been used in the oil industry as fracture fluids and zone isolation.3 This study, however, will focus on guar gum and HPG polymers cross-linked with monoborate ions. Pre-Khuff sandstone reservoirs in Saudi Arabia produce sweet gas for more than ten years. Many of wells drilled in these reservoirs are hydraulically fractured.4 Guar gum and HPG are used to prepare the gels used in hydraulic fracture treatment. Both polymers are cross-linked with monoborate ions. The source of this ion is either boric acid or borax or organoborate salts. The sandstone reservoirs are clean sand with illite as the main clay present in the formation. Potassium chloride is used all drilling and completion fluids to avoid fines migration problems. The reservoir temperature and pressure are 300°F and 8,535 psi, respectively. Analysis of well flow back samples following fracture treatments highlighted the presence of very viscous fluids and gel fragments. Also, the time needed to clean the fractured wells was too long. These trends indicated the gels used in these treatment did not break completely. They also indicate that the surface tension of gel filtrate was high, which resulted long cleaning time. The detrimental effects of fracture conductivity reduction resulting from incomplete fracturing fluid flowback/cleanup are well documented in literature.5 Until recently, characterization of fracturing fluid cleanup could only be simulated in the laboratory and can't be monitored in the field.6

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractHydrochloric acid is used to stimulate carbonate formations (both matrix and fracturing treatments). However, the reaction rate of the acid with carbonate minerals, especially calcite, is very fast. In addition, the viscosity of HCl solution is relatively low. Acid-soluble polymers are usually added to the acid to increase its viscosity, which is needed to enhance acid diversion during matrix acidizng and reduce acid leak-off rate during acid fracturing. Gelled acid is extensively used in matrix and acid fracturing treatments performed in carbonate formations. However, a few studies have evaluated the impact of these polymers on the reaction rate of the acid. This paper uses a rotating disk instrument to measure the reaction rate of gelled acids with calcite rocks. Measurements were conducted over a temperature range of 25 to 65ºC, a pressure of 1,000 psi, and rotational speeds of 100 to 1,000 rpm. Acid formulations that are typically used in the field were examined. Polymer concentration was varied from 0.5 to 2 wt%. The apparent viscosity of the gelled acid was measured using a Brookfield viscometer. Measurements were done for the same solutions tested with the rotating disk instrument. The temperature was varied from 25 to 100ºC, while the pressure was maintained at 300 psi. The shear rate was varied from 57 to 1,700 s -1 .The results obtained indicated that the apparent viscosity increased notably as the concentration of polymer increased from 0.5 to 1.5 wt%. On the other hand, there is significant decrease in the dissolution rates as the concentration of polymer was increased from 0.5 to 1.5 wt%, where there was no measure difference as the concentration increased to 2 wt%. Reverse and toroidal flows were noted within the rotational spends examined. The etching pattern on the surface of the disk depends, among other factors, on the disk rotational speed and polymer concentration. The dissolution rate was found to be a function of temperature, rotational spend and polymer concentration.