Fracture Acidizing: What Role Does Formation Softening Play in Production Response?

Summary

Fracture acidizing of carbonates has yielded increases in production in many areas of the world, but depending on rock strength and reservoir closure pressure, this response may be lower than expected. Also, as a result of rock strength and closure pressure, production may decline at a higher rate than following a proppant fracture treatment.

Laboratory results are presented describing the effect of various acid systems on the strength reduction of limestone -nd dolomite-formation rock samples. Formation samples were dry or saturated with 2-wt% potassium chloride brine before testing. Samples were exposed to neat, emulsified, gelled, and crosslinked 15-wt% hydrochloric acids (HCls) and each exhibited a differing effect on rock-strength reduction. In addition, production responses are presented and compared with regard to the type of acid system used for stimulation.

On the basis of the results obtained, acid-system choices made a significant difference in the degree of rock softening of carbonates. Emulsified acid caused the least softening effect on limestone and dolomite cores. Softening effects were greater on limestone than on dolomite rocks. Production responses from emulsified-acid treatments were best.

Introduction

The Khuff is a deep gas carbonate made up of sequences of limestone and dolomite sections. Acid fracturing has been used to increase gas production from this reservoir (Rahim et al. 2002; Bartko et al. 2003).

Since 1999, acid fracturing of the Khuff formation has proved to be successful in obtaining required high gas rate. In the beginning, the acid-fracturing program consisted of pumping a viscous pad (high-temperature-crosslinked borate gel) followed by 28-wt% in-situ-gelled acid and then by an acid stage of regular 28-wt% HCl, pumped below the fracture closure pressure. Typically, the total acid volume ranged from 500 to 2,000 gal/ft. Over the next few years, introduction of emulsified acids (Nasr-El-Din et al. 2001), in-situ-gelled acids (Yeager and Shuchart 1997; Taylor and Nasr-El-Din 2003; Nasr-El-Din et al. 2002a), HCl/formic (Nasr-El-Din et al. 2002b; 2006b), and viscoelastic surfactant-based fluid system (Nasr-El-Din et al. 2006a) has contributed to optimizing the acid-fracturing treatments. In all cases, extensive analyses of flowback samples were conducted to determine the reactive efficiencies of the fluids used.

The most recent work evaluated stimulation of the Khuff in light of pumping rate, acid volume, and acid system and compared these to the lithology (Bartko et al. 2003). Of significance was that increasing treatment pumping rate resulted in wells with better initial production responses. The work showed that the emulsified-acid system outperformed the other acid systems being used on all types of lithology, using a PI/kh basis. In addition, neither the emulsified-acid system nor the in-situ-crosslinked acid system was affected by lithology variances.

The productivity of some of the treated wells declined with time. One of the potential reasons for this decline is softening of reservoir rock following acid-fracturing treatments. The objectives of the present study are to: assess the effect of various acid systems on rock embedment stress (RES), examine the impact of the lithology of rock softening, and compare rock softening and field results obtained with various acid systems.