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This paper describes a novel method for utilization of advanced surge and swab simulations during drilling and completion operations. Outcomes are reduced waiting on weather and increased safety. Results are achieved through improved planning by introducing an additional metric – Dynamic Rig Heave Limit. This metric is meant to be used as guidance during offshore operations and indicates how much rig heave is acceptable at any given depth in the well before limits of the well itself, or of the tools in the well, are breached. There are several key differences between this approach and the current practices. The most important difference is that the rig heave limits we describe in this paper focus on the effect that the rig heave has on downhole parameters, i.e. well pressure margins and downhole tool limitations. Present practices focus on topside conditions, for example safety of the rig crew and integrity of the equipment. We do not argue that these traditional rig heave limits should be substituted; we rather suggest that the Dynamic Rig Heave Limit should be used in addition. A number of simulation inputs such as sea state and rig response data, well and geomechanics data, well fluid parameters and drill- and completion string data were used to calculate downhole surge and swab as it was induced by rig heave during tubular connections. The simulation model used has been developed in-house and is field-proven, as described in several earlier publications. Its special feature is that it has sufficient temporal and spatial resolution to accurately capture the influence of rig heave on annulus pressure and flow. The focus of this paper is not on the model itself, but rather on how the modelling results were utilized during well planning and communicated during offshore operations. We discuss results from two case studies, one from a well completion operation on the Knarr field (Norske Shell) and another one from drilling operation on the Hades/Iris prospect (OMV Norge). Hades/Iris is an HPHT field in the harsh Norwegian Sea, where an exploration well was drilled wintertime. Knarr is a mature field with depleted pressure margins in the North Sea. These two very different cases each represent a unique set of challenges where introducing the Dynamic Rig Heave limits is shown to be of a benefit. Introducing a limit for rig heave related to well and completion tool limitations is shown to reduce NPT by one or more rig days per well. The main mechanism behind the NPT reduction is that rig heave limits, specifically tailored to each well and calculated throughout the well trajectory, allow halting and resuming operations during periods with high heave based on precisely tailored calculations, rather than relying on experience, gut feeling and generic best practices. Knowing precisely how the downhole limits are related to rig heave for each well also increases safety since there is less risk of damaging the well and/or completion tools or swabbing in reservoir fluids.

SummaryA novel method of utilizing simulations of surge and swab induced by floating rig heave is presented in this paper. The intended applications are in well planning and follow-up of drilling and completion operations. We focus on rig heave during drill pipe connections when the rig's heave compensator cannot be engaged. The method consists of: (1) estimating a dynamic, well- and operation-specific, rig heave limit based on surge & swab simulations at different depths in a well and (2) clearly communicating the dynamic rig heave limit to the rig crew and onshore organization as a simple metric. We present cases where this novel methodology has been tested during the drilling and completion of two offshore wells in Norway, and we elaborate on the operators’ view of the method's advantages. We conclude that complementing the traditional fixed rig-specific heave limit with the dynamic one that is based on the properties of the actual well and the actual drilling/completion parameters offers an opportunity to improve management of risks related to breaching well pressure margins or damaging downhole equipment and to reduce costs through reduction of weather-related non-productive time. We show that the dynamic rig heave limit may differ significantly from well to well and also throughout the same well depending on the kind of operation in the well, depth in the well, well geometry and other parameters related to well and operation properties. Our conclusion is that care should be taken when generalizing a maximum allowed rig heave value as is the industry practice today. The benefits of utilizing dynamic well-specific rig heave limit should be assessed during well planning for any well drilled and completed from a floating rig. Well planning software existing today does not offer this functionality.