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).
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
30 January 2006
- Meeting paper published:
15 February 2006
- Revised manuscript received:
1 June 2007
- Manuscript approved:
30 August 2007
- Version of record:
20 May 2008
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