Abstract

New materials used in deepwater production tubulars, and the increasingly complex and costly deepwater projects, demand greater attention to the design and selection of completion and packer fluids. This requires an integrated approach, from mud displacement through final sand control completion, in order to optimize fluid compatibility and effectiveness. In addition to standard compatibilities with reservoir rock and fluid, compatibilities of completion or packer fluid with control line, stimulation, and production fluids must be considered. Furthermore, compatibility of completion and packer fluids with production tubular metallurgies must be assured in order to prevent environmental cracking. The impact of the production environment on the potential formation of gas hydrates or crystallization of brine due to pressure, at the near-freezing mudline temperatures, must be understood for each of the wellbore fluids used during the completion process. For some projects, more than one completion or packer fluid choice is available, in which case each fluid should be evaluated to select the best ‘fit-for-purpose’ fluid.

This paper presents a new paradigm for testing and evaluating completion and packer fluids for selection in deepwater applications. Details for each test procedure and evaluation method are presented and include completion or packer fluid compatibilities with formation or synthetic formation water, control line fluids, and produced fluids. Core flow studies used to test fluid compatibility with the formation rock, and standard stress-cracking tests, conducted according to NACE guidelines, used to avoid the potential for environmentally assisted cracking of chrome production tubulars, are presented. Specialized evaluation methods to avoid the formation of gas hydrates and the pressure crystallization of completion and packer fluids are also presented. The best fit-for-purpose fluid was selected by following this new paradigm for a GOM deepwater project. Lessons learned are summarized in the paper.

Introduction

Deepwater wells have been completed successfully in the Gulf of Mexico for nearly 10 years, during which time numerous new learnings were experienced. One dramatic example is the crystallization of completion brine above its True Crystallization Temperature (TCT) due to the application of high pressure1. This phenomenon was encountered while running screen and washpipe at Shell's Ram/Powell development in 3,214 ft of water when CaCl2/CaBr2brine crystallized unexpectedly and completely blocked the wellbore flow path2. The entire assembly had to be retrieved in order to remove the plugging. Since then, the Pressure Crystallization Temperature (PCT) of completion brine has been evaluated in some detail and currently an API work group is reviewing the available test methods and apparatus3. Now, completion brine PCT evaluation must be incorporated into the pre-planning process for completing deepwater wells.

Pre-Planning and evaluation for deepwater projects has taken on new dimensions, and testing technologies that were routinely used for some time have been re-evaluated and enhanced to provide optimum results. New testing regimes and paradigms have continuously been introduced into every phase of the completion process, from mud displacement to packer fluid selection.

Another powerful experience impacting deepwater projects is the formation of gas hydrates that are capable of totally blocking inflow and outflow from a well. Gas hydrates of oilfield interest, known for more than 100 years, have been widely published4, 5 and can be generated at temperatures well above the freezing point of water when high pressure is exerted on a hydrocarbon gas-water mixture. Hydrate formation is of intense interest around the mudline in deepwater applications where the water temperature is about 38°F and high pressure is expected. Whenever hydrocarbon gas is produced, the operator necessarily controls the fluid environment within the production tubing especially during startups and in the packer annulus, should this fluid contact produced gas, in order to prevent hydrate formation and the potential blocking of production and well entry.

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