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

Nasr‐El‐Din, Hisham A.; Al-Driweesh, Saad; Sierra, Leopoldo; Domelen, Mary Van; Welton, Thomas

doi:10.2118/103978-ms

Cited by 12 publications

(2 citation statements)

References 26 publications

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“…However, a campaign of twelve wells acid fractured using the organic acid blend indicated that effective half-lengths of only 40-50 ft were achieved, 10 suggesting that there is a potential for a more retarded system to be used in acid fracturing applications. Gelled 11 and in-situ gelled 12 HCl/formic acids were used to acid fracture deep gas wells completed with super Cr-13 tubing. Good field results were obtained, however the fracture half-length was less than expected.…”

Section: Spe 106054mentioning

confidence: 99%

Laboratory Evaluation of an Innovative System for Fracture Stimulation of High-Temperature Carbonate Reservoirs

Nasr‐El‐Din

Kelkar

Still

et al. 2007

Proceedings of International Symposium on Oilfield Chemistry

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fax 01-972-952-9435. AbstractAcid fracturing is the commonly applied stimulation technique in low permeability carbonate reservoirs. Achieving adequate fracture length is challenging due to the fast acid spending rates and high leakoff resulting from these treatments. The problem is exacerbated when treating high temperature formations and compounded with the difficulty of providing adequate corrosion control. In addition, the health, safety and environmental implications of acid handling at surface and shortage of hydrochloric acid in certain regions must also be considered to fully appreciate the challenges imposed by acid fracturing operations. The industry has successfully tried different methods to deal with each, or a combination, of these problems. However, none of them fully address all of the challenges discussed.This paper describes a detailed laboratory evaluation of an innovative, solid-based acid fracturing system to address the above-stated limitations of conventional systems. Extensive laboratory studies, which included acid capacity, etching patterns, conductivity measurements, solubility of reaction products, reaction kinetics, and corrosion tests were conducted at temperatures up to 300 o F. The studies demonstrate that the new system results in heterogeneous etching and wormholing in both limestone and dolomite rocks. In addition, this material exhibits increased fluid efficiency as compared to conventional acid fracturing systems, with the potential of achieving heterogeneously etched half-lengths that approach the length-scale achieved with traditional proppant fracturing operations.This paper will demonstrate the applicability of the novel solid-based acid fracturing treatment. Additionally, the paper will highlight some of the unique challenges of placing a solid-based acid system in the formation and the engineering steps taken to mitigate these challenges. Finally, application limitations of the system will be discussed.

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Section: Spe 106054mentioning

confidence: 99%

Laboratory Evaluation of an Innovative System for Fracture Stimulation of High-Temperature Carbonate Reservoirs

Nasr‐El‐Din

Kelkar

Still

et al. 2007

Proceedings of International Symposium on Oilfield Chemistry

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“…[17][18][19][20][21] A thorough tubing pickling was conducted before each treatment. Both matrix and fracturing acidizing treatments were conducted in this field.…”

Section: Introductionmentioning

confidence: 99%

Lessons Learned From Repickling Old/Sour Gas Wells

Garzon

Nasr‐El‐Din

Al-Mutairi

et al. 2007

Proceedings of SPE Middle East Oil and Gas Show and Conference

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

et al. 2006

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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

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

Cited by 12 publications

References 26 publications

Laboratory Evaluation of an Innovative System for Fracture Stimulation of High-Temperature Carbonate Reservoirs

Laboratory Evaluation of an Innovative System for Fracture Stimulation of High-Temperature Carbonate Reservoirs

Lessons Learned From Repickling Old/Sour Gas Wells

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

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