To successfully perform a Managed Pressure Drilling (MPD) operation in a high-temperature, high-pressure (HTHP) field offshore Norway, an innovative fluid technology was developed for well control purposes. The drilling fluid used in MPD mode had insufficient density for tripping operations. To balance the reservoir pressure when tripping, an isolation pill was spotted in the upper part, leaving dense fluid on top of the well and making the total hydrostatic pressure in the fluid column sufficient for well control. This development pill enabled pressure to be transmitted to the bottom of a well by placing the pill in between a dense fluid on top of a less dense fluid. The design and properties of this pill made it possible to run test wireline logs and eventually a test liner run through the pill, and at the same time, maintain a pre-determined hydrostatic pressure to keep the well under control without externally applied pressure. In addition, the pill did not cause instability by interfacing different density fluids as this would have a dramatic impact on the hydrostatic pressure. One of the criteria was to displace the pill out of the well by using the circulating system only. As this paper describes, the pill stayed intact during the entire operation and displacement of the pill from the wellbore was performed successfully. Another benefit observed was the lack of remedial treatment needed at surface when the pill was circulated out. As this was a solids-free pill, no additional treatment was required. This paper describes in detail the development of the fluid pressure transmission pill and the purpose of using such a pill, including testing performed, and the final result of using the pill for the first time in a well exposed to open reservoir. Introduction A Fluid Pressure Transmission Pill (FPTP), also known as a "Balanced Mud Pill", was developed for use in logging and completion operations during Managed Pressure Drilling (MPD) operations in the Kvitebjørn field. MPD operations have gained popularity for development of modern HTHP gas fields. Batch drilling of entire fields is a high risk and big cost approach. However, due to the rapid pressure drop common in many gas reservoirs after the initiation of production, the pressure regimes for drilling the remaining wells in the project are more challenging. The specific background for the development was well 34/11-A-13 T2 in the Kvitebjørn field. Density for the tests was chosen at 1.87 SG, which was the predicted fluid density while drilling in MPD mode. Required equivalent mud weight to balance the reservoir pressure was estimated to be 1.91 SG and the plan was to use 2.08-SG Cs-Formate mud above the FPTP to achieve this density. The primary target for the project was to develop a crosslinked polymer pill with sufficient integrity to isolate the highdensity brine or drilling fluid in the upper section of the well from the lighter fluid in the deeper section. This would save the cost and logistic challenges of having to displace the entire circulating system to balance the reservoir pressure. The FPTP should also serve as a contingency plan if it should become necessary to open the choke to pull out of the hole without having to displace the entire well volume; thus the pill should be able to transmit the hydrostatic pressure of the added high-density fluid above to the open hole below. The pill should provide sufficient flexibility to enable tripping, allow logs to be run, and finally enable running of liners/production screen assemblies and yet not allow the high-density fluid to channel through it.
This paper describes the first field application of a high-pressure/high-temperature (HP/HT) organophilic clay-free invert emulsion fluid (OCF IEF) weighted with small-particle-sized (SPS) barite, qualification of which was achieved through extensive laboratory investigations (described elsewhere). The paper describes detailed observations of the fluid performance during first use (i.e., “critical first well application”) on a Statoil-operated HP/HT field in the North Sea. In the well selected for first application, finger-printing was performed so that behaviors of the 1.96-specfic gravity (sg) invert emulsion fluid (IEF) could be examined and recorded before entering the open hole. When in the open hole, observational tests were continued throughout the well. Before and after trips, fluid behavior and properties were monitored and recorded. Additionally, extensive fluid testing was conducted on the rig (rheology, HP/HT fluid loss, particle plugging test [PPT] static sag, and viscometer sag shoe test [VSST]). Before running stand-alone screens (SAS), screen flow-through tests were performed. Extensive tests showed acceptable fluid performance within stringent, defined criteria at all times. When re-initiating circulation on several consecutive connections, pump ramp-up time was gradually reduced. No pressures above drilling equivalent circulating density (ECD) were observed at any time. While drilling, the ECD values were maintained well within the required values. No barite sag was observed on any occasion, even after 90 hours static or during a slow circulation rate test performed to simulate conditions likely to induce dynamic sag. Fluid loss control (PPT) was maintained within specifications through the addition of ground marble. A decrease of approximately 60% in fluid treatments compared to a conventional HP/HT IEF resulted in a reduction in chemical and logistical costs and manual handling. The well was drilled well ahead of plan, resulting in saved rig time. No issues were observed when running screens to total depth (TD) with the IEF. The well was easily brought on production after ∼30 days, with the IEF being produced back to surface, consistent with expectations from the qualification laboratory testing undertaken at Statoil's laboratory facilities. Highly acceptable production rates were achieved, indicating minimal productivity impairment. The efficient drilling of the well, along with being able to complete the well in the same IEF and not displace to brine, as was previously performed, resulted in substantial cost savings compared to other qualified solutions. This successful first application demonstrated that the well could be drilled and completed in the same fluid with an enhanced drilling performance and highly acceptable productivity outcome.
Historically, invert emulsion drilling fluids (IEFs) require organophilic clays to provide viscosity and suspension characteristics. Whilst effective, these chemicals are prone to stratification in certain conditions, slow chemical reaction times, high pressure spikes, and high equivalent circulating densities (ECDs) attributed to the solids contribution and inherent chemistry of the fluid. To help reduce such adverse effects, clay based chemicals used in IEFs can be replaced with highly sophisticated polymer viscosifiers, filtration agents, and emulsifiers, which provide a strong, stable emulsion, even with low-oil/water ratio (OWR) IEFs. Legislation governing the energy industry’s use of chemicals in Norway prohibits use of certain products that are otherwise globally used in drilling fluids. To address such restrictions, extensive research and development has resulted in availability of environmentally acceptable chemicals that produce the unique rheological and suspension characteristics inherent to clay-free IEF systems. This paper describes the first application of clay-free IEFs in the Norwegian continental shelf (NCS) with an emphasis on an impressively low ECD contribution far more consistent than previously recorded in comparable wells. Further, a treatment was developed to allow the IEFs to be used to drill into a section exhibiting temperatures greater than 160°C. Chemical consumption was substantially lower compared to previous wells using traditional IEF systems, thus reducing shipping requirements. Before planning the subject well, the environmentally acceptable chemicals intended for use were approved by governing bodies. Consequently, a vertical exploration prospect was selected as the initial well to be drilled using a clay-free IEF. This well was comparable to a previously drilled high pressure/high-temperature HP/HT well, allowing direct comparison of several of the metrics.
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