TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractProduction of Hydrogen Sulfide (H 2 S) gas in oil and gas wells has increased over the last few years. These sour (H 2 S Producers) wells have been successfully acid stimulated for many years. Wellbore acid washes, high rate squeeze treatments and acid fracs have been the norm for stimulating wells in carbonate formations. However, to accomplish this there are many problems related to the interaction of the treatment fluids and the H 2 S. These can result in excessive corrosion, unwanted precipitants, metal cracking, etc.In recent years, the practice of drilling horizontal wells has led to the technique of underbalanced acid washing. Controlling corrosion, metal fatigue and unwanted precipitants when using this technique in sour formations presents a special challenge. The resulting interaction of the H 2 S and acid additives, especially corrosion inhibitors has been the primary focus of concern. This paper describes test equipment and procedures designed to investigate H 2 S and acid additive interactions. Test results with a range of inhibitors and additives designed to minimize formation damage and protect coiled tubing and tubular steels are provided. Specifically, weight loss, pitting and precipitation products are listed.

Laboratory testing of the effects of acidic fluids on metallic samples representative of those used under downhole conditions is the normal procedure to establish additive requirements. Under sour conditions (Hydrogen Sulfide gas contaminated production), test methods utilizing differing amounts of H2S in the gas phase with subsequent contamination of the test solution under bottomhole temperatures is required. Underbalanced acid washing combined with follow-up acid squeezes is becoming more and more prevalent in carbonate wells with sour production. Typically, these treatments are conveyed using Coiled Tubing strings. The thin walled nature of these tubulars makes corrosion control of the utmost importance. Corrosion testing using modified NACE cells under pressures varying from 500 to 6,000 psi and magnetic stirring systems can test various acid systems at temperatures varying from 27° to 315°C (80° to 600°F) over any exposure time. Safety factors, weight loss and pitting guidelines are employed to attempt to ensure the continued integrity of the Coiled Tubing through many treatments. In addition, evaluations of sections of Coiled Tubing after various treatments using the pearlite layer at the concentric center of the Coiled Tubing determine material losses both on the outside and the inside. Surface inspections are also performed to search for pitting or other acid corrosion associated defects. This paper presents the comparison of laboratory acid corrosion testing and the actual effects on Coiled Tubing strings employed. Data from wells treated that produce from 23 to 60% H2S and have bottomhole temperatures ranging from 86° to 110°C (187° to 230°F) are presented. Treatments consisted of acid washes followed by acid squeezes. The varying material deterioration of actual coils, specifically, a loss in wall thickness and surface corrosion features and how this compare to laboratory test data is discussed. Introduction Many areas around the world are using coiled tubing to work on wells that are not only deep with high bottomhole temperatures and pressures but also produce corrosive fluids (H2S and CO2). The well temperatures range from 275° to 415°F (135° to 212°C).1–5 H2S concentrations can vary from <100 ppm to 60%. There is an array of treatments typically performed on oil and gas wells, including fracturing, bullhead matrix, underbalanced washing and wellbore cleanout operations. Washing treatments are typically utilized to clean out scales or debris produced from the reservoir.1,3,4 Table 1 lists the relative importance of reactions that may occur in the acid treatment of sour wells. Since washing treatments are being performed under a less than overbalanced pressure condition and could be performed to remove iron sulfide, both coiled tubing and the production tubulars are highly vulnerable to increased corrosion potential. Another occasion of concern is during the recovery of spent or partially spent acids. 6 Some evaluation of the impact of H2S on the usage of coiled tubing under sour downhole conditions has been performed.7–9 These evaluations have shown that in a sour environment, a preferred tensile strength of coiled tubing for downhole usage is 80 Kpsi or less. In addition, there is a potential for some damaging precipitation products as the result of acidizing operations, from metallic inhibitor intensifiers and some hydrogen sulfide scavengers. Of paramount importance was the need for as close to true downhole conditions as possible for laboratory testing. To more realistically evaluate the ability to protect coiled tubing given the increased severity of corrosive conditions during washing treatments, it was necessary to perform some comparisons of laboratory test results to actual effects of the downhole conditions on coiled tubing strings. Corrosion aspects of this paper focus on the loss of weight and, therefore, wall thickness and tubing surface conditions (pitting).