Corrosion Control during Acid Fracturing of Deep Gas Wells: Lab Studies and Field Cases

Abstract

Acid fracturing treatments are used to enhance gas production from tight, deep carbonate reservoirs in Saudi Arabia.The produced gas has a regional variation between 0 and 10 mol% H[2]S. This variation in H[2]S content has impacted the metallurgy of well tubulars used in these areas.Gas wells in the high H[2]S area are completed with low-carbon steel (L-80 and C-95); those in the low H[2]S area are completed with super Cr-13 tubulars. Acid systems used to fracture these wells included: regular, emulsified, and in-situ gelled acids, all based on 28 wt% HCl.However, 15 wt% HCl - 9 wt% formic acid was used to stimulate wells completed with super Cr-13 tubing. High temperatures (275ºF) encountered in deep wells, the presence of high H[2]S content and the use of large volumes of concentrated acids render corrosion control of tubulars a very difficult task. Experiments were performed to develop a cost-effective acid system to enhance the productivity of deep gas wells, while maintaining the integrity of well tubulars.Acid fracturing treatments were monitored in the field and well flow back samples were collected following these treatments.The concentrations of key ions were measured in these samples including iron and manganese for completions with low-carbon steel tubulars and chrome, molybdenum, and nickel for completions with super Cr-13. Analysis of flow back samples following the initial acid fracturing treatments showed that the return samples contained high concentrations of acid (up to 16 wt% HCl) and total iron (up to 20,000 mg/l). The presence of iron was a major concern during acid fracturing treatments. Modifications of the corrosion inhibitors package, increasing soaking time and over flush volume resulted in better results. Most importantly, the integrity of well tubulars was maintained. This paper discusses lab studies and application of these modifications in the field. Introduction Acid fracturing treatments have been conducted in a deep carbonate gas reservoirs.[1]Various acids are used in these treatments. Almost all of these acids are based on 28 wt% HCl. Corrosion control during these treatment has been a major concern. This is because of the use of concentrated acids, high temperature, and the presence of hydrogen sulfide in some areas in the gas reservoirs. During pumping the acid down the tubing, the acid is continuously depleted from the active ingredients of corrosion inhibitors by the adsorption and/or polymerization on the metal surface. The active ingredients of corrosion inhibitor adsorb to the metal surface and form a thin film that protects the metal leaving the live acid with less inhibition. When the acid reaches the formation its inhibition is further reduced by adsorption on surfaces of rocks.Recovery of the spent acid back through the well tubing may cause corrosion problems if the return fluids contained live acid. This is mainly due to the low levels of corrosion inhibitor in the return fluids. In addition, surfactants, which are used to disperse the inhibitor in the acid, also have very high tendency to adsorb on rock surfaces.[2] This, in turn, leaves the return fluids with minimal dispersivity and poor functionality. In general, cationic or partially cationic corrosion inhibitors adsorb to surface of the rock, especially in the case of sandstone. Nonionic corrosion inhibitors such as acetylenic alcohol show little if any adsorption on rock surfaces. Several authors have addressed the problem of corrosion inhibitor being adsorbed on formation rocks and thereby damaging the formation, altering wettabilty or causing emulsion problems.[3,4] The concern of the presence of live acid in well flow backwas first raised by Huizinga and Like.[3] A similar work was done later by Morgenthaler et al.[4] Their experimental work was done on acidizing of sandstone rocks by HCl/HF acid. Simulated and real spent acids were used to test their effects on low-carbon steel (L-80) and stainless steel (super Cr-13). Both studies agree on that spent acid could be corrosive and may adversely affect the integrity of well tubulars. The extent of the problem can be addressed by a thorough understanding of the composition of the spent acid and its effect on various types of tubing.

Development of efficient formulation for the removal of iron sulphide scale in sour production wells

“…The industry standard for the corrosion rate is set to be a maximum of 0.227 kg/m 2 (0.05 lbm/ft 2 ). Any fluid should have a corrosion rate less than this value to avoid corrosion of the well tubulars . The formulation containing 20 wt% HCl and 3 vol% of CI is very corrosive, ruling it out for scale removal.…”

From initial treatment design to final disposal of chelating agents: a review of corrosion and degradation mechanisms

“…However, concentrated HCl can dissolve this layer, resulting in severe corrosion to the base metal. 42 …”

Stimulation of Seawater Injectors by GLDA (Glutamic-Di Acetic Acid)

“…The production rate from this well increased to 200% after the treatment, and after 1 year, the production rate was stable almost at the same rate. Bakar et al (2013) used GLDA instead of HCl to remove calcium carbonate and iron-scale deposits from the electrical-submersible-pump (ESP) system and near-wellbore region at elevated temperatures and pressures in an offshore well. Besides scaling issues, high hydrogen sulfide (H 2 S) concentration, up to 300 ppm, was also detected in this well.…”

“…Bakar et al (2013) used GLDA through bullheading to remove scale from wells equipped with ESP completion instead of HCl. They obtained 95% removal of calcite and iron scales after 24 hours without damaging the well completion.…”