Acid Fracturing of Deep Gas Wells Using a Surfactant-Based Acid: Long-Term Effects on Gas Production Rate

Abstract

The deep, tight carbonate formations in Saudi Arabia are ideally suited for acid fracturing treatments. Various types of acids such as regular, in-situ gelled, and emulsified acids, have been used in order to achieve optimum fracture length and conductivity. Acids used for these treatments were based on 28 wt% HCl. A mixture of 15 wt% HCl and 9 wt% formic acid was used in wells completed with super Cr-13 tubulars. A high pH borate gel was pumped in stages to reduce leak-off and maintain the bottomhole pressure at values greater than the fracturing pressure of the formation. A new generation of viscoelastic surfactant-based acid was implemented in the field. A short term production evaluation based on the initial production (post flowback) from these wells could not clearly distinguish between the benefits obtained from the viscoelastic diverting acid versus the in-situ gelled acid.1 However, the wells treated with viscoelastic surfactant based acid did clean out in a shorter period of time. The main objective of this study was to compare the "long term" production results obtained from five wells treated with the surfactant-based acid with off-set wells treated with in-situ gelled acids. This paper provides for the first time long term production data evaluation following acid fracturing using surfactant-based acids. It also compares the performance of two main acid systems based on field data. The evaluation of acid fracturing treatments with in-situ gelled acid systems and surfactant-based acid systems suggest that there was no significant variation in the design and the execution of both the viscoelastic and in-situ gelled acid treatments. Among the 5 wells treated with surfactant-based acid, 4 of them showed better long-term production performance over a 2–3 year period compared to their offset wells. In the short-term (nearly 3 months production), 2 wells treated with viscoelastic acid showed no difference in production performance compared to their offset wells. Introduction Saudi Aramco has embarked on an aggressive program to develop its gas fields. The unassociated gas is being produced from two main reservoirs: J (sandstone) and K (carbonate). Hydraulic fracturing is used to enhance gas production from the sandstone reservoir, while acid fracturing is used to increase gas production from the carbonate reservoir.1,2 The K-formation is a deep and high temperature gas reservoir underlying the giant Ghawar oil field in the eastern region of Saudi Arabia. This formation is a heterogeneous reservoir consisting of dolomite and limestone with streaks of anhydrite, shale or non-permeable intervals. This heterogeneity of the K formation makes it an excellent candidate for acid fracturing treatment. The K-formation is also classified as a moderately permeable to tight gas reservoir, which has a porosity ranging from 1 to 25 vol% in the higher porosity sections. These types of porosities, coupled with the natural fractures present in the zone and the high bottom hole temperatures (250–280F) results in undesirably high leak-off rates during acid fracturing treatments. Regular HCl acid has high leak-off rates that hinder acid propagation during fracturing treatments. The rate of leak-off,3 Ct, can be determined using Eq. 1

A Novel Pore-Scale Thermal-Fracture-Acidizing Model With Heterogeneous Rock Properties

“…They found that increased acid-contact time sometimes reduced the fracture conductivity (weakening of the rock structure), whereas fluid loss can increase it, creating more surface roughness. They showed that the effect of rock-embedment strength and closure stress on acid-fracture conductivity is accurately predicted by the Nierode-Kruk correlation (Nierode and Kruk 1973).…”

“…This model assumed an infinite reaction rate at the fracture surface, and the velocity and acid distributions were modeled after analytical solutions. Nierode and Kruk (1973) presented an evaluation of fluid-loss additives and retarded acids. They also presented correlations to predict fracture conductivity on the basis of the mass of the dissolved rock (ideal fracture width), assuming the walls dissolve uniformly.…”