Acid Fracturing HT/HP Gas Wells Using a Novel Surfactant Based Fluid System

Abstract

During acid fracturing of carbonate reservoirs, the acid dissolves the rock, creating wormholes which increase fluid loss. Excessive fluid loss lowers the net pressure in the fracture limiting fracture extension, and adversely affects the conductivity of the fracture. To overcome this problem, multiple stages of polymer pads are usually pumped in acid fracturing treatments to reduce leak-off. In addition, synthetic polymers are commonly added to the acid to produce gelled or in-situ gelled acids. The objective of adding these polymers is to reduce leak-off, by increasing the viscosity of the acid. This in turn reduces the rate of mass transfer of the acid to the rock surface. However, several studies have shown that these polymers can cause formation damage. Moreover, the crosslinker can precipitate in the formation causing further damage. Efficient mixing of synthetic polymers in the field is also a concern, especially when the polymers are present in a solid form.To overcome problems associated with polymeric fluids, polymer-free fluids were used for the first time to acid fracture several vertical wells in a deep gas reservoir in Saudi Arabia. The acid fracture treatments consisted of several stages including: viscous pads, emulsified acid, in-situ acid and an inhibited acid. A visco-elastic surfactant system replaced the polymers used in the pad and the leak-off control acid (28 wt% HCl). Calcium chloride produced from acid reactions with the carbonate rock viscosifies the acid in-situ, reducing leak-off volume. ResultsThe pressure response to acid f racture treatments clearly indicates that the surfactant-based system is very effective in controlling acid leak-off during the treatment in wells with a bottom hole temperature of nearly 260 o F. Good leak-off control did help in maintaining a constant pumping rate throughout the treatment. Significant increases in both gas production and flowing wellhead pressures were achieved utilizing this new system. In addition, pumping operations were simplified by continuous mixing of the fluids. The nondamaging nature of the system enhanced production rates above expectations.

Long-Term Comparative Evaluation of HCl/Formic Acid System Used To Stimulate Carbonate Formations at Severe Conditions in Saudi Arabia

“…5 The acid systems used were based on 28 wt% HCl and included: regular, 5 emulsified, 6 in situ gelled acid, 3,7 and recently, acids based on viscoelastic surfactants. 8 The southern part of this reservoir has very low hydrogen sulfide content, less than 100 ppm, and more than 2 mol% CO 2 . Low-carbon steel tubulars cannot be utilized under these conditions because of excessive corrosion to the tubing.…”

Emulsified Chelating Agent: Evaluation of an Innovative Technique for High Temperature Stimulation Treatments

“…HCl is pumped as the main stimulation fluid in most of the stimulation treatments. At high temperatures, the reaction between HCl and carbonates is very fast, and for low acid injection rates this will result in rapid HCl spending and face dissolution (Allen and Roberts 1989;Nasr-El-Din et al 2003). Also, HCl can cause excessive tubing corrosion and formation of acid/oil sludge in asphaltene-rich crudes.…”

Effect of Presence of Crude Oil on the Performance of Emulsified Acids

“…HCl is pumped as the main stimulation fluid in carbonate stimulation treatments, but the reaction between regular HCl and clacite is very fast, and it becomes higher at higher downhole temperatures. This high acid-rock reaction rate results in rapid HCl spending and failure of stimulation treatment (Allen and Roberts 1989;Nasr-El-Din et al 2003). Regular HCl may cause excessive tubing corrosion, and may form acid/oil sludge in asphaltene-rich crudes.…”