Impact of Acid Additives and Fe (III) on the Rheological Properties of a New Class of Viscoelastic Surfactant
- Lingling Li (Texas A&M U.)
- Document ID
- Society of Petroleum Engineers
- SPE International Symposium on Oilfield Chemistry, 20-22 April, The Woodlands. Texas
- Publication Date
- Document Type
- Conference Paper
- 2009. Society of Petroleum Engineers
- 1.8 Formation Damage, 5.4.10 Microbial Methods, 3.2.4 Acidising, 1.10 Drilling Equipment, 1.6.9 Coring, Fishing, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.8.7 Carbonate Reservoir, 4.2.3 Materials and Corrosion, 4.1.5 Processing Equipment, 4.1.2 Separation and Treating
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Surfactant-based acid systems were developed over the last few years for diversion to overcome the severe problems caused by polymer residue and crosslinker precipitate after polymer-based system treatments during matrix and fracture acidizing. Two main types of viscoelastic surfactants have been used: amphoteric and cationic. Surfactant molecules can form rod-like micelles and significantly increase the viscosity in the presence of the salts. After acid treatments, the surfactant gel can be broken by mixing with hydrocarbons, external breakers, and internal breakers or by reducing the concentration of salts via dilution with water.
This paper introduces a new type of viscoelastic amphoteric surfactant (amine oxide). It carries a positive charge in the presence of live HCl acid. The effects of acid additives and Fe (III) contamination were examined on its rheological properties. Measurements were made at temperatures from 75-220 oF, and 300 psi at various shear rates from 0.01-935 s-1. Acid additives included corrosion inhibitors, mutual solvent, non-emulsifying surfactant, iron control agents and hydrogen sulfide scavenger.
The apparent viscosity of surfactant solutions prepared in deionized water, live acid, and spent acid was found to be a function of temperature. Calcium chloride increased the apparent viscosity of live acids. Concentration of HCl in the live acid system affected its apparent viscosity. Live acid that contained 12 wt% HCl showed the highest apparent viscosity. Low concentrations of Fe (III) caused an increase in the apparent viscosity. Two immiscible liquids, and then a precipitate were noted as the concentration of ferric ion was increased in live acids. A demulsifer and mutual solvent decreased the apparent viscosity at all temperatures examined. Iron control agents reduced the apparent viscosity of surfactant based acids. The impact of lactic acid on the apparent viscosity was significant, especially at high lactic acid concentrations. Citric acid also reduced the viscosity of surfactant based acids, but cannot be used at concentrations greater than 0.5 wt% because of precipitation of calcium citrate. EDTA slightly reduced the viscosity of surfactant based acids, but the solubility of EDTA in 20 wt% HCl is very low. Up to 1 wt% methanol can be used with this spent acid system at temperatures below 175oF. Higher concentrations of methanol caused significant reduction in the apparent viscosity.
Polymer and surfactant-based acid systems have been developed for acid diversion by increasing the viscosity of the injected acid during matrix acid treatments in carbonate formations.
Crosslinked acid systems were introduced because they have much higher viscosity than uncrosslinked acids. There are two types of crosslinked acids. The first type of acid is crosslinked on the surface and remains crosslinked in the formation (Johnson et al. 1988). The second type of acid is uncrosslinked when it reaches the formation and the crosslinking reaction occurs in the formation (Yeager and Shuchart 1997; Saxon et al. 2000).
The in-situ gelled acids use pH to control a crosslinking polymeric solution. The crosslinker may be iron (III), zirconium (IV) or other multivalent cationic species. However, there are several concerns related to this system. One noted concern is precipitation of the crosslinker (Fe (III)) in the formation (Lynn and Nasr-El-Din 2001; Nasr-El-Din et al. 2002). Taylor and Nasr-El-Din (2002, 2003) reported the result of permeability loss after injection of in-situ gelled acid because of polymer retention in the core and on the injection face of the core. Also, a significant amount of residual polymer will be found if a large volume of acid is used (Mohammed et al. 1999).
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