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Well Integrity Assurance: A Successful Method for External Corrosion and Damage Detection on Outer and Middle Concentric Strings of Casing

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 environment.

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.

Outer Concentric String Casing Damage Evaluation: Advancements in Electromagnetic Inspection Data Interpretation for Common North Slope Well Completions

Alaska's North Slope wells are subject to a variety of mechanisms that cause corrosive damage to outer casing strings. These include: (1) near-surface casing damage resulting from the ingress of oxygenated (surface) water; (2) corrosive power fluids pumped down the inner annulus of venturi pump wells; and (3) exposure to formation salt water in intervals of poor cement quality. The importance of maintaining casing integrity for safety and environmental reasons, combined with the high cost of pulling tubing strings on the North Slope create a need for an economical means of evaluating outer casing string integrity with the tubing in place.

The successful use of AC magnetic wave, electromagnetic pipe inspection technology to qualitatively assess outer concentric string casing damage for certain well completions has been well documented for applications on Alaska's North Slope since 2006. Information and conclusions drawn in existing literature are all based on the comparison of tool recordings made in the field to the visual inspection of casings subsequently dug up or removed from the well. While these comparisons illustrate many good correlations between recorded metal loss indications and areas of severe metal loss observed in some completions, there remains a need to better quantify the minimum threshold for the extent of casing damage that can be detected via this method.

This paper presents the results of surface tests conducted on dual concentric string pipe configurations with an array of engineered metal loss features designed to test the tool's response to total volumetric metal loss and the spatial configuration of damage to the outer string. The tool's response to deep pitting on the external surface of the inner concentric string is tested as well. Conclusions are drawn in respect to the approximate size and shape of defects that can be expected to be detected for the concentric pipe configurations tested. The application of this knowledge to data recorded in the field
will add greatly to the confidence of risk assessments made with this technology in well work decision processes.

In one North Slope field, premature tubing failures had occurred in wells completed with Venturi pumps. Multi-Finger Caliper logs of the tubing indicated little, if any corrosive activity on the inside of the tubing, which lead to the suspicion of external tubing corrosion as the failure mechanism. This was confirmed when the visual inspection of the tubing pulled from one of the wells exhibited an intermittent line of deep pitting on the outside of the tubing that breached the tubing wall at three locations (Fig.1). This raised concerns of similar damage occurring on the inside of the production casing, which is composed of similar material and environmental exposure.


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