Marlin Failure Analysis and Redesign: Part 1 — Description of Failure

Abstract

This is the first of three related papers that describe the actions of an incident-investigation team formed to evaluate the failure of Well A-2 on the Marlin tension-leg platform (TLP). This paper outlines several possible failure modes and narrows the field of candidate failure modes to a small subset by deduction from both analysis and physical evidence. The application of these results and analytical techniques, as incorporated into the redesign of the subsequent completions, is addressed in the second paper of the series. The third paper discusses real-time monitoring of the redesigned completions. Abstract The Marlin field is located in the Gulf of Mexico, Viosca Knoll Blocks 871/915, and was originally intended to be produced from a TLP by means of five predrilled dry-tree penetrations. First production from Well A-2 began in November 1999. Shortly thereafter, a minor but persistent tubing leak occurred. Between 7 and 20 November, Well A-2 was alternately flowing and shut in, depending on the shakedown of surface equipment and pipeline availability. On 20 November, the casing pressure jumped to shut-in tubing pressure, signifying a major tubing failure. This paper describes the actions of an incident-investigation team formed to evaluate the failure of Well A-2. Possible failure modes investigated by the team include: Helical buckling of the production tubing, with or without the combined loss of a tubing centralizer. Crushing of the tubing by ratcheting displacement from a failed centralizer. Lateral deflection of the subsea wellhead. Collapse of the production (and/or intermediate) casing onto the tubing because of one or a combination of the following. Hydrate formation outside the intermediate casing owing to gas migration from a shallow hydrocarbon zone with subsequent dissolution during initial production. Nonuniform loading of the production casing because of the geometry of the submudline packoff tubing hanger (POTH) slips. Leak in a production-casing connection. Annular fluid expansion (AFE). Formation of a heat pipe in the production tubing by production casing/riser annulus. Casing wear on the intermediate casing. Excessive initial pressure resulting from setting the casing hanger seal assembly in the subsea wellhead. Inadequate performance of the tubing or casing caused by either an incorrectly run or an inadequately manufactured joint. Deducing from both analysis and physical evidence, the current installment will narrow the field of candidate failure modes to a small subset. Applying these results and analytical techniques, as incorporated into the redesign of the subsequent completions, is addressed in the second paper of the series.1 The final paper describes the implementation of the redesign as an insulatedtubing completion.2