SPE Production & Operations
Volume 23, Number 2, May 2008, 112-118

Summary

Workover of wells contaminated with hydrogen sulfide (H₂S) is a difficult task. Coiled tubing (CT) has become one of the mainstays in treating this type of wells, but failures do occur, such as tubing recovered with leaks or catastrophic parting, which can leave several thousand feet of tubing, including bottomhole assemblies (BHAs), to be fished.

Corrosion control is essential to protect production equipment, and to avoid CT failures during acid treatments. Also essential for the safe use of CT are the proper selection of metallurgy for the downhole environment, appropriate use of H₂S inhibitors, nondestructive testing of the coil before usage, and periodic sampling of the coil for physical examination. Other precautionary measures are still in the development stages.

In this paper, we discuss two case histories of CT failure during workover in sour environments. The analyses performed to determine causes and recommended practices to avoid the reoccurrence of these failures are included along with a set of guidelines for the safe use of CT in sour-well workovers.

Introduction

CT is used in many areas around the world (e.g., Russia, western Canada, and a few fields in Saudi Arabia) to work on deep sour wells. Workover treatments can have disastrous consequences if H₂S escapes to the surface, putting personnel in a life-threatening situation. There are also the mechanical dangers of parted pipe and the possibility of treatment fluids contaminating the site.

Since 1998, production of CT strings has been increasing at a rate of 10% per annum. In 2002, CT units numbered 1,043, with more than half of them in North America (Active 2002; van Adrichem 1999). Service companies (Stanley 1998; Crabtree and Skrzypek 1998) reported nearly 33% of CT failures were because of corrosion—broken down into storage, acid, and H₂S. A comprehensive review and field cases of the use of CT in sour fields in Western Canada is given by Crabtree and Gavin (2005).

During 1995–2001. In the mid-1990s, as a result of two sour-well blowouts in Canada, the government levied restrictions on drilling of sour reservoirs in populated areas. Industry experts set out to examine all aspects of drilling under sour conditions, and joint-industry projects (JIPs) were established to determine proper test methods and material requirements (Luft and Wilde 1999). Changes suggested to the industry recommended practices (IRPs) included, among others, relaxation of strength limits to include 70 and 80-kpsi CT grades and increasing maximum hardness to Hardness Rockwell “C” scale (HRC) 22 (Luft et al. 2002). These efforts resulted in more stringent IRPs for drilling sour wells in Canada (IRP 2000). Additional efforts to establish a world standard for verification of sour-service materials have been advanced (ISO 15156 1999).

To prevent tubing failure during drilling, nondestructive inspection systems are used to detect corrosion, mechanical damage, and manufacturing defects. Use of nondestructive testing (NDT) systems over a 2-year period resulted in zero well-control accidents (MacArthur et al. 1999). Of the CT strings determined to be unfit, 50% were because of mechanical damage and 30% because of corrosion (pitting). Overall, a 52% reduction in failures was achieved. Not all NDT systems on the market monitor all parameters, and the detection time to failure is uncertain. Efforts continue to improve using CT in sour environments.

Corrosion starts the day CT is milled and spooled, unless a suitable corrosion-inhibition program is implemented (van Arnam et al. 2000). For underbalanced-drilling operations in sour wells, performance testing of corrosion inhibitors demonstrated that there should always be an H₂S inhibitor incorporated where CT is used (Luft 2003; McCoy and Thomas 2006).

Workovers take on additional problems with the use of acid treatments, especially at high temperatures. The petroleum industry has arbitrarily set acid-corrosion limits for jointed carbon-steel tubing to less than 0.05 lbm/ft² of tubing surface area and less than 0.03 lbm/ft² for jointed chrome-based alloys (Rae and di Lullo 2003). The 0.05 lbm/ft² represents a reduction in the wall thickness of between 0.001 and 0.00125 in. in 1 ft of tubulars. A wall-thickness loss of this magnitude (~0.5%) is considered acceptable protection over all temperature ranges. This loss is attainable with a reasonable loading of corrosion inhibitors at most temperatures. As bottomhole temperature increases, the amount of inhibitor required increases dramatically. In addition, a suitable intensifier should be used at temperatures greater than 200°F. These acceptable corrosion rates can be increased somewhat at temperatures greater than 300°F (Hill and DeMott 1977).

The use of CT tubing, with its thinner wall thickness and frequent exposure to corrosive environments, dictates a more stringent weight-loss limit: less than 0.02 lbm/ft² (~0.5% thickness loss). All acceptable corrosion rates are based on the the life of acid treatment, or acid-contact time (Mingjie and Boles 2004).

© 2008. Society of Petroleum Engineers

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History

• Original manuscript received: 23 June 2004
• Meeting paper published: 28 May 2004
• Revised manuscript received: 29 October 2007
• Manuscript approved: 7 November 2007
• Version of record: 20 May 2008