Well Integrity Assurance: A Successful Method for External Corrosion and Damage Detection on Outer and Middle Concentric Strings of Casing
- Mary Jean Loveland (ConocoPhillips Alaska Inc.) | Joey P. Burton (ProActive Diagnostic Services Inc.)
- Document ID
- Society of Petroleum Engineers
- SPE Annual Technical Conference and Exhibition, 11-14 November, Anaheim, California, U.S.A.
- Publication Date
- Document Type
- Conference Paper
- 2007. Society of Petroleum Engineers
- 4.2.3 Materials and Corrosion, 3.1.2 Electric Submersible Pumps, 3 Production and Well Operations, 6.5.2 Water use, produced water discharge and disposal, 7.1.8 Asset Integrity, 1.14 Casing and Cementing
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As well integrity is of utmost importance for personnel safety and environmental interests there is an ever increasing need for tools and systems that verify and confirm the status of wells with suspect integrity. Recent near-surface, outer casing failures caused by external corrosion on relatively new wells in the Kuparuk Field of Alaska prompted research for a non-invasive predictive method to foresee failure and aid repair prioritization. There are a variety of tools and methods available to locate leak points and corrosion inside of tubulars, but very little literature exists concerning external corrosion and damage detection on outer and middle concentric strings of casing. The following method is a valuable qualitative approach used to determine existence and severity of shallow external surface casing corrosion before leaks occur.
The technique uses a logging tool that analyzes the variations of metal thickness within three concentric sets of down-hole tubulars and identifies areas where metal loss exists. The metal loss combined with assumed or known internal tubing condition reveals the wells with the highest risk for shallow surface casing leaks. When a high risk area is discovered proactive excavation repair plans can be made before any safety or environmental problems occur. This paper summarizes the tool, technical approach and assumptions, limiting factors, and the remarkable comparison between the metal thickness logs and the actual external surface casing corrosion observed on 12 wells after excavating each up to 27 ft in the Greater Kuparuk Area. Future plans and strategy using the technique are also discussed in the paper.
The Kuparuk field is located on the North Slope of Alaska, approximately 30 miles west of Prudhoe Bay (Fig. 1). The Greater Kuparuk Area (GKA) includes the Kuparuk reservoir as well as several other smaller oil pools in the operating unit. The majority of GKA wells are completed with a conductor casing (CC), a surface casing (SC), a production casing (PC) and tubing. However, about 5% of the 1100 wells in the GKA have a single casing design—only the CC, SC, and tubing are present (Fig. 2).
Normally the SC functions as an element of a secondary or tertiary layer of protection between the reservoir and atmosphere. For single casing wells the surface casing is the primary and sometime only layer of protection if there is no packer. Therefore, a degradation of the surface casing resulting from corrosion is considered a serious breach of the integrity of a given well1. Prediction and mitigation of SC corrosion problems are considered vital steps to maintain the mechanical integrity of the wells, the safety of the personnel, and protection of the environment while maximizing the life of the wells.
Cause and Extent of Surface Casing Corrosion
Historical records, field investigation and lab results from a previous study (SPE Paper 100432) indicate the near surface casing corrosion is a result of cyclic or consistent moisture ingress of oxygenated water with the annulus between the SC and CC. Elevated well operating temperatures in conjunction with an extremely corrosive environment caused by the soluble salts that leach from the cement create a very aggressive corrosion environment1.
Over the last few years, the aggressive corrosion environment has become increasingly evident as 38 GKA wells have been discovered with severe SC corrosion failures at shallow depths typically less than 30 ft. Most of these corrosion failures are on single casing produced water injection wells. They appear to have a higher failure rate than other GKA wells because they operate at warmer external casing temperatures than multi casing injectors or production wells.
To date, 22 of the 38 known failures have been visually inspected and repaired by a process which takes approximately four weeks to complete. In addition to the remaining wells currently waiting for repair, the failure rate is such that several new wells are added to the repair list every year. The driving factor behind running the thickness log was to develop a tool that can recognize and locate metal loss with enough accuracy that it can be used as a proactive tool to prioritize repairs before the corrosion becomes actual leak failures to the environment.
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