Publication Details (including relevant citation information):
Welton, Thomas D., Van Domelen, Mary S. -
Abstract: Summary This paper discusses the development of a unique in-situ crosslinkable acid system that uses a blend of hydrochloric acid (Hcl)/formic acid as the base acid and a synthetic polymer gelling agent. The ability to in-situ crosslink an organic acid blend is novel. In addition, an unexpected result of the fluid development was the discovery of its unique rheological properties. Historically, both gelled and in-situ-crosslinked acids have been used for fluid-loss control during fracture acidizing and for diversion in matrix treatments in carbonate formations. Various synthetic polymers are used to gel the acid. Past research indicates that ~20 cp base-gel viscosity is required as the first step in fluid-loss control. In-situ crosslinking allows very high viscosities to be generated as the acid spends. The crosslinked gel creates a permeability barrier and subsequent fluid stages are diverted to other sections of the zone. When the acid fully spends, the gel breaks, giving a low-viscosity fluid. HCl is the most common base acid used for carbonate stimulation. Combinations of HCl and organic acids have been used because of their high dissolving power and relatively low rates of corrosion at elevated temperatures. In extreme cases, combinations of organic acids are used. While HCl/formic-acid blends have been used in the past, the unique rheological properties of these blends have not been fully explored. The chemistry and rheology of gelled and in-situ crosslinked HCl/formic-acid blends equivalent to 28% HCl will be described and compared with traditional gelled acid and in-situ crosslinked acid. Introduction The stimulation of carbonate reservoirs is often achieved through the use of fracture or matrix acidizing. For maximum benefit, the acid system must be properly matched with the formation characteristics as well as the associated completion and production equipment. With higher temperatures or acid strengths, the difficulty in inhibiting corrosion increases along with the likelihood of formation damage because of the inhibitor. High-alloy steels have been steadily gaining in popularity for use in high-temperature reservoirs that contain corrosion fluids such as carbon dioxide (CO2), hydrogen sulfide (H2S), or corrosive brines (Murali 1984a, 1984b, 1984c; McDermott and Martin 1992). In the petroleum industry, these high-alloy steels or corrosion-resistant alloys (CRAs) are commonly chromium alloys, such as 13Cr and the newer super 13Cr (Canyard et al. 1998; Sakamoto and Maruyama 1996; Asahi et al. 1996). One drawback to 13Cr and duplex CRAs is that they are highly susceptible to corrosion by mineral acids such as Hcl (Nasr-El-Din et al. 2003; Nasr-El-Din et al 2002a; Crolet 1983; Garber and Kantour 1984; Kolts and Cory 1984). One potential solution to this problem is to use organic acids. Organic acids have been extensively used in the acid stimulation of hydrocarbon reservoirs (Harris 1961; Scheuerman 1988; Wehunt et al. 1993; Fredd and Fogler 1998; Shuchart and Gdanski 1996; Coulter and Jennings 1997; Nasr-El-Din et al. 1997; da Motta et al 1998; Huang et al. 2000a, 200b; Wang et al. 2000; Nasr-El-Din et al. 2001; Frenier 1989; Hashem et al. 1999; van Domelen and Jennings 1995; Smith et al. 1970; Chatelain et al. 1976). The use of a combination of organic and inorganic acids dates back to 1978 (Dill and Keeney 1978). More recently, Nasr-El-Din and coworkers studied the rates of reactivity by rotating disc method (Nasr-El-Din et al. 2002b). Organic-acid systems may be more attractive than HCl systems because of their significantly lower corrosion rates and extended reaction times. Acetic acid is available in concentrations up to 100%, while formic acid is available in 70 to 90% concentrations. For field use, however, acetic solutions are normally diluted to 15% or less. At concentrations greater than 15%, one of the reaction products, calcium acetate, can precipitate because of its limited solubility, depending on temperature. Similarly, the concentration of formic acid is normally limited to 10 to 11% because of the limited solubility of calcium formate. Gelling agents are often used in fracture acidizing to increase the live acid-penetration distance and to help control fluid loss. Gelling agents can also be used in wellbore cleanouts in both sandstone and limestone formations to help transport fines out of the wellbore. Next, the efficiency of matrix-acidizing treatments can be enhanced with viscosified acids (Paccaloni et al. 1993; Hill and Rossen 1994; Jones et al. 1996). Commonly used high-temperature, acid-gelling agents are copolymers consisting of various ratios of acrylamide, acrylamidomethylpropane sulfonic acid, quaternized dimethylaminoethylacrylate and quaternized dimethylaminoethylmethacrylate. The ratios of these monomers in the polymer will control the viscosity of the polymer on a per-pound basis, the capability and nature of the crosslink, the viscosity profile as a function of temperature and the upper-temperature limit of the gelled-acid fluid (Chatterji and Borchardt 1981; Norman et al. 1981).