The Barents Sea offers unique drilling challenges related to issues such as biogenetic gas in shallow formations, thermogenic gas seeps up to the seabed from underlying formations, shallow formations with abnormal pressure, shallow reservoirs, low-fracture-pressure formations in part of the overburden, and naturally fractured/karstified carbonate reservoirs. This paper discusses cementing challenges when drilling wells in the Barents Sea and the experience gained using managed pressure cementing (MPC) practices. When drilling the surface hole in potentially slightly overpressured formations, the riserless mud recovery (RMR) technique was used. For the first time on the Norwegian Continental Shelf (NCS), MPC was used when cementing the surface casing. RMR compensates for drilling the overpressurized zones without a riser and blowout preventer (BOP), and MPC allows for pressurization and monitoring of the pressure on the subsea wellhead toward the formation during the cement curing stage. Once the marine riser and BOP were installed, controlled mud level (CML) technology was used during drilling, running casing/liners, cementing operations, and other activities. CML enables manipulation of the fluid level in the riser and therefore helps optimize downhole pressure to avoid losses and maintain an overbalance. CML has proven to be particularly useful during cementing of liners in naturally fractured reservoirs and during setting of balanced cement plugs in an open hole. As a result, high circulation rates can be achieved and conventional high-density cement slurries can be used. MPC using either RMR or CML was employed for the first time in the Barents Sea. Examples of how cementing operations were planned and executed are described and results are presented.
Losses to the formation when drilling can lead to non-productive time (NPT), altering the wellbore construction due to unplanned casing points, and well control incidents due to the loss of overbalance pressure. The karstified and fractured carbonate reservoir formations sometimes encountered in the Barents Sea represent a high lost circulation risk. The large vugs (or caves) in these formations can be as large as 50 cm in diameter and cause severe to total losses while drilling. Dynamic loss rates are typically in the range of 30-60 m3/hr and can be greater. A unique lost circulation mitigation (LCM) solution is required for these conditions. An operator which plans to drill through this type of formation is wise to plan effective LCM solutions in order to rapidly cure any losses. The presented method is setting a reactive cementing fluid train downhole that creates an effective blockage in the loss zone. The cementing fluid train is composed of three fluids: sodium silicate, calcium chloride, and an innovative thixotropic and low compressive strength cement slurry designed to rapidly cure loss zones. When the first two fluids come into contact, they instantly form a viscous slush-like precipitate of calcium silicate. The fluid train is designed so the ‘slush’ forms inside the loss zone and creates a base for the cement following behind, allowing the cement to set up inside the loss zone. Together these fluids create the ideal LCM solution to large vugs and cavernous zones. The fluids are pumped through the drill string and the bottom hole assembly after it has been pulled above the loss zone. After the fluids are pumped, a short wait on cement time allows the operator to drill ahead through the cement and continue with the planned well path. The content presents a description of the procedures and successful results from two operations performed in the Barents Sea. The operator cured the loss rate to the necessary level to continue drilling, negating the need for a sidetrack. Furthermore, multiple LCM solutions had failed prior to pumping this fluid train, proving the effectiveness of the solution.
When the production of a platform well is no longer profitable, two options are available—either perform permanent plug and abandonment (P&A) or reuse the slot by plugging the original well and sidetracking. P&A requires setting barrier elements in the wellbore to prevent hydrocarbon migration between potential flow zones and to the surface. In most cases, it is financially beneficial to perform as much of this work as possible during an intervention phase before rig operations begin, thus saving rig operating expenses. Most conventional barriers are balanced cement plugs, and setting a cement plug requires a drilling rig to handle the workstring through which the cement is placed, crew, and associated equipment [e.g., blowout preventer (BOP)]. However, the rig time spent performing P&A could be used more productively, such as drilling and completing new wellbores. An operating and a service company developed a method for setting the primary P&A cement plug toward the reservoir without a drilling rig. The cement is set through the Christmas tree using a specialized wireline-set packer as a base and wiper plugs installed on a specialized spool piece to isolate the cement and indicate completion of the job. This paper explains the method and equipment and presents three case studies from the Norwegian sector of the North Sea.
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