Deepwater operations aimed at preparing DVA and subsea wells for extended shut-ins include injection and/or bullheading of a number of fluids down the wellbore to displace or "deactivate" hydratable fluids. This strategy is only marginally effective as manifested by the multiple occurrences of hydrate plugs per year in DVA wells during extended shutin due to a combination of both short cool down times in the riser section and relatively high watercut. Operators also treat deepwater subsea wells by injecting or bullheading significant volumes of fluids such as methanol or diesel to either deactivate the free water or to displace hydratable well fluids below the subsurface safety valve. In this paper we describe work done aimed towards determining the effectiveness of such bullheading or fluid injection operations.
The application of a robust flow assurance strategy is of great importance in both DVA and subsea deepwater wells. In this paper, we will investigate the general applicability of bullheading or injecting a variety of fluids in the wellbore to protect it from hydrate formation during a planned shut-in. The general idea is to either displace hydratable well fluids deep down where the ambient earth temperature is higher than the hydrate temperature or to "deactivate" the free water in the wellbore via mixing with injected methanol. These strategies have been only partly successful in DVA wells where hydrate plugging is common for high watercut wells. The same strategies when applied to subsea wells appear to be generally more effective than in DVA wells due to longer cooldown times although quite costly due to the large volumes of methanol currently employed.
The paper will provide results from both flow simulations and laboratory experiments that were conducted to evaluate the effectiveness of the current bullheading strategies. Gasliquid and liquid-liquid separation phenomena in a wellbore are shown to be of utmost importance in determining the hydrate risk during well shut-in. True displacement of hydratable well fluids past the subsurface safety valve with diesel or methanol does not occur with the currently employed operational practices. Both diesel and methanol have higher density than live oil and therefore sink easily through the liveoil/ dispersed water phase, which subsequently hydrates as the wellbore cooldown progresses. We will conclude with a summary of our learnings to-date and will offer various recommendations on new and more robust techniques to protect wellbores from hydrating during shut-in.
As deepwater fields mature, water production is increasing and thus hydrate risks become serious. For example, since water production onset in one Gulf of Mexico deepwater platform over six years ago, several hydrates occurrences have been experienced in the high water cut wells. In the majority of these incidences hydrate plugging in the wells occurred despite operations efforts to protect the wellbores prior to shut-in by means of injecting diesel and/or methanol in the tubing. These hydrate occurrences have lead to weeks or even months of downtime of the wells, several days of operations personnel focus to remediate, and safety concerns during remediation.