Practical and Successful Prevention of Annular Pressure Buildup on the Marlin Project
- Richard F. Vargo Jr. (Halliburton) | Mike Payne (BP plc) | Ronnie Faul (Halliburton) | John LeBlanc (BP plc) | James E. Griffith (Halliburton)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- September 2003
- Document Type
- Journal Paper
- 228 - 234
- 2003. Society of Petroleum Engineers
- 1.1 Well Planning, 4.2 Pipelines, Flowlines and Risers, 4.3.1 Hydrates, 1.14.1 Casing Design, 4.2.4 Risers, 6.1 HSSE & Social Responsibility Management, 2 Well Completion, 1.11.2 Drilling Fluid Selection and Formulation (Chemistry, Properties), 1.6 Drilling Operations, 3 Production and Well Operations, 2.4.3 Sand/Solids Control, 1.14.4 Cement and Bond Evaluation, 1.14.3 Cement Formulation (Chemistry, Properties), 5.6.5 Tracers, 5.5 Reservoir Simulation, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.14 Casing and Cementing, 4.3.4 Scale, 1.10 Drilling Equipment
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In late 1999, BP plc experienced a well failure in the Marlin development in deepwater Gulf of Mexico. Within hours of starting production, the production tieback casing collapsed, causing failure of the production tubing. Pressurization of outer annuli because of production thermal effects was identified as the most likely cause of the failure.
The industry has reported cases of annular pressure buildup (APB) in annuli for several years.1 In land, platform, and spar-type wells with access to annuli, APB is usually handled by bleeding off annular pressure as needed. Subsea completions, however, do not allow this capability, and the technology to provide access is still being studied. Especially susceptible to APB are deepwater developments in which the differential between mudline and flowing-production temperatures can exceed 125° to 200°F.
Three primary mitigation techniques were employed to help reduce the impact of APB on the Marlin project. The first used an enhanced casing design capable of withstanding higher pressure conditions. In the second method, a burst disk was installed in the outer casings to provide a controlled leak path. The third technique involved the application of nitrified cementing spacers in the annulus to provide a compressible cushion and to help reduce the effects of temperature expansion.
Service company and operator engineering staffs worked proactively and integrated their efforts to identify, evaluate, plan, and implement multiple options for resolving this substantial well-integrity issue. This article reviews the problems associated with APB, describes the large-scale testing conducted in the Marlin project, and discusses the best practices developed to help prevent APB from affecting casing design. These best practices were successfully implemented on the Marlin subsea development, and other projects are also using these techniques.
Marlin History, Well A-2 Failure Summary.
An incident investigation team was formed to evaluate the failure of Well A-2. The team provided detailed analyses of probable failure modes and determined two possible root causes of the failure - excessive APB or annular hydrate disassociation. The failure-analysis results were applied to the five remaining Marlin wells.2 When these original Marlin wells were batch drilled, a number of mitigation techniques presented in this article were not implemented and were no longer available for consideration. As a result, the redesign of the Marlin completions had to focus on vacuum-insulated tubing (VIT) and fiber-optic monitoring systems as a means of both controlling and observing thermal behavior.3
Early in the investigation, a root cause analysis was performed to discern the most likely causes of tubing ovalization.4 Possible causes included:
Excessive helical (column) buckling of the production tubing.
Hydrate formation and dissolution.
Trapped annulus pressure leading to casing collapse.
Miscellaneous issues, such as proper tubulars and well- head movement.
From the possible causes, the most likely hypothesis was that APB caused the casing collapse. Calculations and laboratory testing further reduced the possibilities, suggesting that helical buckling did not lead to deformation of the production tubing. Further testing on surplus samples of tubulars indicated that the materials exceeded API performance ratings and were, therefore, not a contributing factor. Two of the root causes were interrelated - cementing the annulus into previous casing and a hydrate plug possibly causing a trapped annulus, leading to APB. All the conditions necessary for the formation of a hydrate plug were potentially present in the 13 3/8 × 16-in. annulus. A rise in temperature during production coupled with a confined container within which dissolution might proceed could generate enough pressure to collapse the 13 3/8-in. intermediate casing. That collapse could then lead to a cascading point loading/collapse sequence on the production tieback and tubing.
When the production string was cemented, the annulus between the production and intermediate casings was purposely sealed because of a hydrocarbon zone just below the intermediate casing. The fluids in the annulus at the time they were trapped (i.e., when the cement was set and the seal assembly was installed at the wellhead) were at a relatively low temperature. The fluid temperature and pressure profiles at this point in the well constitute the initial conditions of these annular fluids. When the well was produced, the annuli probably became heated from the transfer of bottomhole temperature up the well by the produced fluids. When heated, the fluids trapped in the annulus could have begun to expand thermally. If the trapped fluids expanded, the pressure generated between the intermediate and production casings could have caused that string to collapse. A collapse failure of the production casing could immediately cause a collapse failure of the production tubing also. The Marlin A-2 well failure demonstrates the severe risks APB can pose to subsea well integrity and how collapse failure of outer casings can propagate inward, caus- ing additional failures of inner casings and tubings. The severe consequences of such potential failure modes demonstrate that APB mitigation should be successfully implemented into subject well designs.
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