A novel MPD setup has been tested and used at the Kvitebjørn field in the North Sea to make possible the drilling of 8.5" holes through reservoirs with heavily depleted zones. A central part of the concept has been to use an advanced dynamic flow and temperature model in combination with an automatic choke system to control open hole pressure very accurately. The paper describes briefly the operations, and discusses challenges and experiences related to making these complex components work reliably together. The system has proven its potential for minimal variations in pressure at a given open hole position, with accurate automatic pressure control in wells were margins are very small, smaller than frictional pressure losses added when circulating at drilling rate. This paper focuses in particular on the use of an advanced transient model for automatic choke regulation. Other aspects of the operation are described in more detail elsewhere, see Refs. 1–3. Challenges exceeded expectations, but after a test period with many improvements based on trial and error inside cased hole, the 8 1/2" sections were drilled successfully with good pressure control. Introduction The Kvitebjørn field in the North Sea, close to Statfjord and Gullfaks, started production in 2004. Conventional drilling continued after this, but the increasing pressure depletion caused severe losses on the ninth well. This event put an end to conventional drilling at Kvitebjørn, and the development of a comprehensive managed pressure drilling setup started. Main elements were:Running a real time, advanced dynamic flow model onlineAutomatic choke system with continuously updated pressure set-point from the flow modelContinuous Circulation SystemRotation Control HeadCesium Formate based designer mudUse of a Balanced Mud Pill for minimum pressure surges when pulling out drillstring and running in liner The overall setup, individual components, and experiences are described in detail in Ref. 1. This paper deals with the model part of the concept, with examples from wells A-13-T2 and A-12 on Kvitebjørn. Overall system setup An advanced dynamic flow and temperature model ran continuously with input from the rig system. Desired equivalent mud weight (EMW) at a given position was input to the model, which calculated the corresponding choke pressure. An accurate automatic choke system was used to control pressure according to the set-point calculated. A continuous circulation system was used to maintain constant flow rate and thus reduce downhole pressure and temperature variations to a minimum. The system worked well during drilling operations, and contributed to resolving the very challenging situation with an open string after a shallow drillstring washout.
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.
Drilling wells in high-pressure, high-temperature (HPHT) reservoirs is often characterized by a narrow operating window between formation pore pressure and fracture pressure. Depletion further reduces this window. Managed Pressure Drilling (MPD) provides methods for operating within safe limits in the narrow HPHT windows. Exceptional control over downhole pressures can be achieved with advanced MPD technologies that are uniquely suited for the HPHT environment. Such control can extend achievable HPHT targets, yet still have the flexibility to deal with the troubles that so often arise in these difficult environments. The advanced MPD system developed for StatoilHydro's Kvitebjørn HPHT field are presented along with experiences from their use in the field. This includes:ManagementRunning a real-time, online, advanced dynamic flow modelAutomatic dual redundant choke system with continuously updated pressure set-point from the flow modelContinuous Circulation System (CCS)Pressure Control While Drilling (PCWD)Caesium Formate mud system - A designer mud containing formation strengthening particles.Balanced Mud Pill (BMP) - An innovative fluid technology developed for performing a precision top kill, producing minimal pressure surge when pulling the drillstring and running liner. Introduction Kvitebjørn is located in the Northern North Sea on the Norwegian Continental Shelf, southeast of the Gullfaks Field (Fig. 1). It is classified as a HPHT gas condensate field. The reservoir consists of sandstones in the Mid-Jurassic Brent group and lower Jurassic (Cook Sst). The top reservoir is at approximately 4,070 m TVD. Early production during development drilling has induced pressure depletion, creating a convergence between pore pressure and fracture pressure in the reservoir. The initial pore pressure was 775 bar (1.93 SG) and fracture pressure was 875 bar (2.19 SG). The reservoir temperature is 155°C and the water depth is 190 m. Nine wells had been drilled into the reservoir prior to introducing the MPD technique. The gas/condensate production started in September 2004 after the second well had been drilled and completed. On the last conventionally drilled well, 34/11-A-2, 140–170 bar of depletion was encountered and massive losses were experienced. Drilling was suspended before reaching TD due to the well-control situation created by these mud losses. The A-2 incident marked the end of the traditional drilling programme as no further drilling on Kvitebjørn would be possible, unless a method could be found to safely operate within Kvitebjørn's reduced "Drilling Window". Prior to drilling the A-2 well, the Kvitebjørn platform produced at maximum capacity, 20.7 MMsm3 gas and 8 Msm3 condensate. After the A-2 incident, the Kvitebjørn production was reduced in an attempt to limit the rate of depletion to complete the primary drilling programme. Production from the field was reduced by 50% in December 2006 and then completely shut down by May 2007 when depletion approached 200 bar.
As part of its objectives to increase recoverable reserves and reduce development costs in Norway's Oseberg field, Norsk Hydro has aggressively employed extended reach horizontal drilling over the past four years. Critical to the success realized in the Oseberg development program has been the use of an integrated steerable drilling assembly that features a near-bit sensor providing real-time measurements of the well path, thus enabling drilling in a corridor of one to two meters. Problems with orienting fixed cutter bits in the highly demanding sliding mode necessitated the use of tungsten carbide insert (TCI) roller cone bits to follow the required trajectory. This paper describes the development of new IADC 437 and 447 Class TCI bits, which culminated in a unique gauge cutting structure with diamond-enhanced, chisel-shaped cutting elements. The authors will review the bearing, seal and cutting structure limitations of conventional roller cone bits used in earlier Oseberg wells, emphasizing the negative impact of excessive gauge wear and short bearing life to overall well costs. Laboratory and field data will be presented, with emphasis on the lessons learned during extensive cutting structure and bearing/seal examinations. The successful application of the new design in the Oseberg development drilling program will be discussed in detail. Introduction Norway's Oseberg field, located approximately 130 km north-west of Bergen, was discovered in 1979 and is presently being developed via two platforms - the Oseberg B and C - which are situated 15 km apart. The Oseberg reservoir section is located in the Middle Jurassic comprising several sand units: the Tarbert Upper and Lower Ness, Etive and Oseberg formations (Fig. 1). The Tarbert shows subangular and subrounded sandstones moderately sorted with a thickness of up to 60 m TVD. Firm and blocky coal and silty claystones sequences interbed the sandstones in the Ness formation. The Etive shows angular to subrounded sandstones with silicate cementation and siltstones at the base. The Oseberg formation is the main reservoir, consisting of medium to coarse-grained fan delta sandstones of excellent reservoir quality. The vertical thickness is 20 to 60 m TVD. The Rannoch claystone sequence separates the Etive and Oseberg formations. The first horizontal well was drilled on the field in 1992, and since then 20 wells have been successfully drilled and completed. Over that time, the lengths of both the horizontal section and the Total Measured Depth (TMD) have increased progressively. In 1995, Well C-26A established a then-world record with its 7,853 m horizontal displacement. In that well, the horizontal section was 2,100 m and the total depth 9,325 m. In early 1996, the first multi-lateral wells - C12A, B and C - were successfully drilled from the Oseberg C platform. To maximize the recoverable hydrocarbons in the horizontal reservoir sections, the deviations from the trajectory have to be kept within a tight tolerance on vertical and tangential variations (often 1m). The tight tolerances force the operator to drill the reservoirs with a reservoir navigation tool (RNT). Both fixed cutter (PDC) and roller cone tungsten carbide insert drill bits (TCI) are used, depending on the lithology and operating demands. Historically, dulled TCI bits exhibited severe abrasive wear in the gauge area, frequently resulting in under-gauge hole and early seal failures. Thus, to avoid the risk of losing cones, the operator was forced to pull bits after short times on bottom. Lost cones generally cause difficult and expensive fishing jobs. P. 541^
As part of the digitalization and utilization of Automated Monitoring during drilling operations, real-time dynamic modelling of downhole combined with 3D dynamic visualization have been implemented on the drillfloor in offshore rigs. The objectives have been to give the driller instant feedback on the ECD and other effects of the operations and allow for a safer and smoother operation within the limits of the well. The basic elements of this technology are A digital twin of the well with all relevant data and properties included. A set of integrated transient models (hydraulics, surge & swab, displacement, mechanical friction). These models are driven by the RT data from operation and compute critical safety parameters which are presented for the driller. A diagnostic module analyzing differences between measured and modelled parameters and trends. A 3D Virtual Well which visualize the downhole well, the risk matrix, the diagnostics and messages as well as the ECDs at critical positions in the well. The 3D System has been utilized during drilling of several very challenging ERD and Multi-Lateral wells on two platforms in the North Sea. The system was also used during tripping in and out of the well, and during running of casing and liners. During these operations there is no PWD data available, and the modelled ECD values proved especially useful. The Trip-risk log from the Geologist was included in the 3D View during these operations, and the Driller could then see on the 3D when a risk was coming up. This paper will present the experiences from using the dynamic 3D & modelling system on several wells. The feedback from the Drillers and Drilling manager have been positive, and the results are very promising.
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