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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.

Summary This paper describes measured and simulated downhole pressure variations ("surge and swab") during drill pipe connections when drilling an ultra-deepwater well offshore Brazil on the Carcará field. Floating rig motion caused by waves and swell ("rig heave") induces surge and swab when the drill string is suspended in slips to make up or break a drill pipe connection and topside heave compensation is temporarily deactivated. This is a known issue in regions with harsh weather such as the North Sea, where pressure oscillations of up to 20 bar have been reported during connections. Recorded downhole drilling data from the Carcará field reveals significant pressure oscillations downhole (in the same order of magnitude as in the North Sea) each time the drill string was suspended in slips to make a connection in the sub-salt 8 ½" section of the well. Mud losses were experienced around the same well depth and they might have been caused by surge and swab. Measured surge and swab pressure variations have been reproduced in an advanced proprietary surge and swab simulator that considers rig heave, drill pipe elasticity, well friction, non-Newtonian drilling mud, well trajectory and geometry. Moreover, findings in this paper suggest that surge and swab was in fact significantly higher than recorded by the MWD (Measurement While Drilling) tool. The true magnitude of surge and swab is not captured in the recorded MWD data due to low sampling frequency of the downhole pressure recording (one measurement every six seconds, a standard downhole pressure sampling rate used on many operations today). This work shows that surge and swab during drill pipe connections on floaters may challenge the available pressure window for some wells even in regions with calm weather such as Brazil. Managed Pressure Drilling (MPD) is a technique that improves control of the downhole pressure. It is, however, not possible to compensate fast downhole pressure transients, such as heave-induced surge and swab, using MPD choke topside. This is due to the long distance between the choke and the bit, which translates into a time delay in the same order of magnitude as typical wave and heave periods. A downhole choke combined with continuous circulation is one of potential solutions. Surge and swab during drill pipe connections can result in a loss or an influx and should be considered in the well planning phase when mud weight, section lengths, etc. are selected.

Harsh weather conditions result in severe heave motion on floating drilling rigs. The drill string is heave-compensated during drilling ahead, however, when slips are set during drill pipe connections, the topside heave compensation system is disabled, and the drill string is then moving up and down together with the rig. Pressure oscillations below and around the drill bit, induced by such movement, are known as "surge & swab". These oscillations can be in the order of 20 bar or more during drill pipe connections in the North Sea and pose a serious challenge to drilling of wells with narrow pressure margins from floating rigs in harsh weather environment. A managed pressure drilling (MPD) choke at the surface cannot be used to control rig heave-induced surge & swab due to the fast nature of the pressure oscillations in question, stochastic character of the sea waves that cause them and long time-delay between topside choking and bottomhole response. Continuous Circulation System (CCS) might be able to reduce the pressure oscillations somewhat by maintaining constant mud flow during connections. Computer simulations and laboratory experiments were previously used to investigate a novel method for attenuating surge & swab by utilizing an autonomous choke to be installed in the bottom-hole assembly (BHA). The bottomhole pressure oscillations can be effectively reduced through dynamic in-situ control of the mud flow through BHA by a downhole choke. This paper presents the downhole choke system and the results from the first pilot trial conducted in a mud flow loop at Ullrigg test rig in Stavanger utilizing a full-scale version of the choke. The prototype was subjected to drilling mud with flow rates up to 2500 lpm and differential pressure up to 250 bar to investigate its ability to accurately control the flow while at the same time withstanding the demanding conditions. Satisfactory choke valve characteristics were obtained, indicating ability to control the flow with sufficient precision. Flow testing resulted in severe erosion of carbon steel components while wolfram carbide components were able to withstand the erosive nature of the flow. The test also uncovered challenges related to operation of the choke with high differential pressure and flow rates which could later be related to the motor, used to control the downhole choke assembly. The next phase of the project is to design a downhole prototype and test it in an onshore test well to achieve Technology Readyness Level (TRL) 4 qualification ("ready for first use offshore"). The final goal is to qualify the downhole choke together with MPD and a Continuous Circulation System (CCS) for use on floating drilling rigs in harsh weather environment.