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.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
21 December 2006
- Meeting paper published:
24 September 2006
- Revised manuscript received:
7 June 2007
- Manuscript approved:
2 July 2007
- Version of record:
20 May 2008
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