Application of Cationic Surfactant-Based Fluids for Acid Diversion
- Hisham A. Nasr-El-Din (Texas A&M University) | Ayman R. Al-Nakhli (Saudi Aramco) | Saad M. Al-Driweesh (Saudi Aramco) | Thomas D. Welton (Halliburton) | Leopoldo Sierra (Halliburton) | Mary S. Van Domelen (Maersk Oil)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- February 2009
- Document Type
- Journal Paper
- 124 - 134
- 2009. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 1.6.9 Coring, Fishing, 2.5.2 Fracturing Materials (Fluids, Proppant), 4.2.3 Materials and Corrosion, 1.10 Drilling Equipment, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.3.4 Scale, 3.2.4 Acidising, 5.8.7 Carbonate Reservoir, 2 Well Completion, 4.1.5 Processing Equipment, 1.8 Formation Damage, 2.2.2 Perforating, 3 Production and Well Operations, 5.6.4 Drillstem/Well Testing, 5.5.2 Core Analysis
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This paper examines the use of surfactant gels during matrix acid treatments and describes field trials of these fluids. Unlike available viscoelastic surfactants used today in the field, this surfactant is cationic. If used in live acids, the fluid has a relatively low viscosity when pumped. Once the acid is spent, however, the surfactant molecules increase its viscosity significantly. To enhance diversion further, the acidic fluids or brines can be foamed with this surfactant.
Rheological measurements were conducted on Hastelloy®-fitted rotational viscometers at temperatures ranging from 70 to 300°F. The effects of surfactant concentration, shear rate, temperature, and acid additives on the apparent viscosity of various surfactant-based fluids were investigated in detail.
The surfactant was stable thermally and hydrolytically with most acid additives. While it was compatible (i.e., still formed a viscosifying gel), some additives adversely affected the apparent viscosity of surfactant solutions at a given temperature. The apparent viscosity of surfactant solutions increased with salt concentration and can be predicted by use of the Carreau-Yasuda model. Coreflood tests indicated that the surfactant delayed acid breakthrough in calcite cores. Acceptable corrosion rates were obtained when this surfactant was added to the acid.
The performance of this surfactant was validated with field treatments. The surfactant was used in more than 100 matrix acid treatments (oil producers and water injectors). It was used to increase the viscosity of acids in situ and enhance the stability of foams used for diversion. All wells responded positively to these treatments, and no operational problems were encountered. Downhole gauges confirmed the ability of surfactant-based fluids to divert the acid into various zones.
Surfactant gels have been used in matrix acidizing, fracture-pack, and hydraulic-fracturing treatments since late 1970s (Norman 1978; Leggett et al. 1982; Samuel et al. 2001). During acidizing treatments of carbonate reservoirs, the acid will flow into the most-permeable or least-damaged zones. The acid will form highly conductive channels or "wormholes" (Schechter 1991; Samuel et al. 2001). Most of the fluid will flow into the path of least resistance, leaving large portions of the target zones untreated. Therefore, diversion plays a key role in matrix acid treatments. This diversion can be accomplished through mechanical or chemical means, or both (Mohammed et al. 2005; Chang et al. 2007; Nasr-El-Din and Samuel 2007; Nasr-El-Din et al. 2006a, 2006b, 2006c; Baheiri and Nasr-El-Din 2007). Polymer gels, foams, oil-soluble resins, rock salts, and surfactant gels are some of the chemical means available (Chang et al. 2007).
Surfactant gels have become an increasingly popular choice for viscosifying acidic fluids and brines (Nasr-El-Din et al. 2003; Mohammed et al. 2005; Fu and Chang 2005; Nasr-El-Din and Sammuel 2007; Chang et al. 2007; Nasr-El-Din et al. 2006a, b, c; Baheiri and Nasr-El-Din 2007; Cawiezel and Dawson 2007). Extensive laboratory testing was conducted to understand better how viscoelastic surfactants work in the field. It was found that the rheological properties depend on numerous factors such as surfactant concentration, shear rate, temperature, acid concentration, solvents, salt type and concentration, and other acid additives such as corrosion inhibitors (Nasr-El-Din et al. 2008).
Surfactant gels can be prepared with anionic, cationic, or amphoteric surfactants (Nasr-El-Din et al. 2003). Amphoteric surfactants have been the subject of several laboratory (Nasr-El-Din et al. 2008) and field studies (Nasr-El-Din et al. 2006b,c; Nasr-El-Din and Samuel 2007). The present study will focus on cationic viscoelastic surfactants, which present several advantages to carbonate acidizing. Unlike amphoteric viscoelastic surfactants, cationic surfactants have a much higher activity (nearly 75 wt% as compared with 30-40 wt% for amphoterics), do not require cosurfactants or additives to perform adequately, and are safe because no methanol is needed to enhance performance. Cationic surfactants are compatible with most corrosion inhibitors. Finally, by virtue of being cationic, this surfactant will propagate in carbonate formations with minimum loss resulting from adsorption onto the rock surface.
The objectives of this study are to (1) examine the effects of simple inorganic salts and additives on the rheological properties of various solutions that contain a cationic-surfactant gelling agent, (2) assess its impact on acid propagation in carbonate cores, and (3) validate their effectiveness with field trials.
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