Kick Mechanisms and Well-Control Practices in Deepwater Vugular Carbonate

Abstract

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper IPTC 14423, ’Kick Mechanisms and Unique Well-Control Practices in Vugular Deepwater Carbonates,’ by F.E. Dupriest, SPE, ExxonMobil, prepared for the 2011 International Petroleum Technology Conference, Bangkok, Thailand, 15-17 November. The paper has not been peer reviewed. Conference rescheduled to 7-9 February 2012. Copyright 2011 International Petroleum Technology Conference. Reproduced by permission. Standard well-control training that drillers receive prepares them to respond to an influx that occurs during underbalanced conditions. The mechanism by which hydrocarbons may enter the wellbore following a vugular loss can be different. One potential result is that the influx may not be detected as early as during conventional underbalanced conditions. A model was developed to explain the unique mechanism by which kicks may occur following vugular losses. Effective recognition and response practices are proposed that are consistent with that model. Introduction When massive losses occur in vugular formations, the well’s behavior does not follow a conventional well-control scenario. Gains in pit volumes are not seen despite hydrocarbon entry, and kicks can go undetected until they have traveled some distance up the annulus. Once the kick is detected, backpressure cannot be held effectively to prevent further influx while circulating the initial kick out and the annulus-pressure trends and values appear to be unpredictable. It also is difficult to control the placement of fluids or pills. The most significant challenge is the inability to detect an influx as soon as it occurs. In deepwater wells, the distance from the vugular zone to the subsea blowout preven-ters (BOPs) may be short, as shown in Fig. 1. Operators are aware of these behaviors, and the industry has developed unique practices for drilling vugular carbonates safely. Rigs having surface BOPs address the risks by use of a rotating control device (RCD). RCDs have been used in a similar fashion at the surface on marine risers with subsea BOPs. The RCD has been installed at the top of the riser above the slip joint, and a tension-ring system is under development that will enable the RCD to be placed below the slip joint. In subsea applications, the pressure that can be applied below the RCD is more limited than on land locations, usually to the rating of the slip joint or marine riser. In some cases, the rating is adequate for the given well. In other situations, the pressure limitations of the riser system or RCD may not provide the robust capability needed.