Drilling wells in depleted reservoirs is often characterised by a narrow operating window between formation pore pressure and fracture pressure. Drilling High Pressure High Temperature (HPHT) wells into a narrow margin reservoir is even more challenging, and Managed Pressure Drilling (MPD) techniques may be required in order to operate within safe limits. Managing the annular pressure profile during MPD operations requires a robust and reliable drilling control system. The presented work treats some challenges and possibilities regarding a MPD choke control system under evaluation for a planned HPHT well in the Kvitebjørn Field in the North Sea. Here pressure management is to be achieved by regulating the choke opening and thereby compensating for downhole pressure variations. Methodologies for automatic choke control during the drilling operation are assessed. A dynamic fluid flow model is used to calculate well pressures for application in the choke control algorithms, and to simulate pressure response in the well. The performance of choke control during drilling operations is evaluated and results from simulations are presented. Introduction Kvitebjørn is located in the Northern North Sea, southeast of Gullfaks. It is classified as a HPHT gas condensate field. The reservoir consists of sandstones in the Mid-Jurassic Brent group. The top of the reservoir (top of Tarbert) is at 4070 meters. Simultaneous drilling and production has brought pressure depletion, creating a convergence between pore pressure and fracture pressure in the reservoir. The initial pore pressure was 770 bar and fracture pressure was 875 bar. The temperature is 155 degrees, placing the reservoir in a borderline High Temperature category. Water depth is 190 metres. In total, 11 development wells are planned. So far seven wells have been completed (April 2006). Depletion is observed on Kvitebjørn, and for the last wells the narrow pressure window is expected to be a challenge. The depletion forecast indicates that a critical depth is expected to be at top of Tarbert. Managed Pressure Drilling (MPD) may be required to drill these wells. MPD in the HPHT environment has little precedence. This study was performed to examine the feasibility and potential application on Kvitebjørn. Simulations have been done for two theoretical wells representative for Kvitebjørn. Application of oil based mud (XP-07) and Cesium Formate (Cs/K Formate) has been considered in this study. The objectives of the feasibility study were to investigate the effects of the following three techniques:Automatic choke regulation,Continuous Circulation Device (CCD) and/orMud heater These techniques can be combined or used separately. Application of a mud heater and/or CCD has primarily a stabilizing effect on the wellbore pressure profile, while automatic choke regulation is a direct and fast response technique that falls within the collective term of MPD. The scope for simulations at IRIS was:ECD o During drilling o Transients induced by pressure peaks from pump o Effect of CCDTemperature effects o Pump start-up after static period o Drilling o Effect of mud heaterTripping outSurge and swabSmall kicksKill pillLiner runningCementing operation Though all these aspects were simulated, the main focus was on drilling and pipe movements (surge, swab, tripping out) in the 8 1/2″ hole section.

During the 1980's exploration activity in the North Sea turned towards deep, high pressure, Jurassic gas condensate reservoirs. These reservoirs occur at 16 - 18,000 ft, are abnormally pressured with pore pressures of approximately 15,500 psi, and temperatures approaching 400F. This presented a new challenge to the drilling industry which required the development of new techniques, equipment and philosophies. By 1985 considerable experience had been gained in the drilling and testing of these wells. In mid 1985 Ranger Oil drilled well 29/5b-4 to a depth of 17,930 ft using their own semi-submersible drilling unit, the SEDCO 714. Electric logging indicated that the Upper Jurassic objective at 17,080 ft had a pore pressure of 15,800 psi. The presence of H2S and CO2 were detected and calculations showed that the maximum anticipated tubing head pressure was 13,500 psi. By following the concepts developed from past experience that wells of this type cannot safely be tested from a floating drilling unit, the well was suspended. Procedures were established to permit the safe testing of this well using engineering innovation to develop new equipment and techniques. Re-entry and testing took place in August 1986 using the jack-up GLOMAR MORAY FIRTH and produced a total of 54 mmscf/d and 4,500 BOPD. Maximum wellhead pressure was 12,500 psi, surface temperatures reached 300F and reservoir temperatures of 406F were recorded. By examining the operational procedures, equipment and techniques used to overcome the problems encountered, a drilling and testing philosophy is developed, which provides a field proven basis for the economic exploitation for reservoirs of this type. Introduction By the 1980's the North Sea was a mature area producing over two million barrels of crude oil per day, and exploration interest was turning towards deeper higher pressured prospects. Ranger Oil had been active in the North Sea since the early 1970's and, in order to play a key role in this new round of exploration, built a third generation semi-submersible drilling unit, the SEDCO 714. The SEDCO 714 is the latest of the SEDCO 700 series rigs built by Hyundai in Korea in 1983, with a total variable deck load of 3700 tons and equipped with a Hydril 16.3/4 15M BOP stack. The SEDCO 714 arrived in the North Sea in March 1984 and commenced operations on 29/2a-2. Ranger's exploration activity with the drilling unit commenced in June 1984 with the drilling of 22/27a-1, followed by wells on 22/8a-3, 4/26-1a and 22/27a-2. Each of these Jurassic prospects presented a challenging series of problems. JURASSIC WELLS DRILLED BY RANGER OIL IN THE NORTH SEA Total Max. Pore Max RFT Max. Temp Well Depth Pressure Pressure deg F ft ppg psi 22/27a-1 16,585 17.2 13,620 320 22/8a-3 15,195 17.2 12,974 340 4/26-1a 17,285 17.2 14,353 321 29/5b-4 17,930 17.3 15,849 406 22/27a-2 17,247 16.7 14,140 343 P. 399^

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.

Summary As the industry pushes the boundary of technology to drill narrow-margin wells, combining safe drilling practices with drilling efficiency is becoming ever more challenging. The practice of drilling with managed-pressure drilling (MPD) by use of statically underbalanced mud weight (MW) is gaining increasing acceptance in high-pressure/high-temperature (HP/HT) well construction. This paper describes the planning and execution of using mud-cap fluid in the drilling of an ultranarrow-margin (0.50-lbm/gal window at the planning stage) HPHT well from a jack-up rig. Drilling equivalent circulating density with overbalanced MW at acceptable flow rate would have exceeded the formation-fracture gradient and resulted in a loss of well integrity. To avoid this outcome, the HP/HT section of the well was drilled with statically underbalanced MW. Displacing well to kill-weight fluid at acceptable flow rates before any trip out of hole was not viable. Planning focused on how to maximize operational efficiency with a cap fluid to trip in and out of hole without compromising openhole integrity and well safety. In this paper, we discuss the design of the mud-cap fluid, selection of change over depth, risks associated with use of the cap fluid, determination of available window for mud-cap placement and removal, planning and execution of mud-cap placement and removal, challenges of running and displacing the cap fluid with a liner, and lessons learned from the repeated use of the technique throughout the well-construction phase, including coring and wireline logging under MPD conditions. Significant operational efficiency was gained from the use of cap fluids, making it possible to drill a well that would otherwise have been near impossible to drill with minimum lost time.

As the industry pushes the boundary of technology to drill narrow margin wells, combining safe drilling practices with drilling efficiency is becoming ever more challenging. The practice of drilling with Managed Pressure Drilling (MPD) using statically underbalanced mud weight is gaining increasing acceptance in High Pressure High Temperature (HPHT) well construction. This paper describes the planning and execution of using mud cap fluid in the drilling of an ultra-narrow margin (0.50ppg window at the planning stage) HPHT well from a Jack Up rig. Drilling Equivalent Circulating Density (ECD) with overbalanced mud weight at acceptable flow rate would have exceeded the formation fracture gradient and resulted in a loss of well integrity. To avoid this outcome, the HPHT section of the well was drilled with statically underbalanced mud weight. Displacing well to kill weight fluid at acceptable flow rates prior to any trip out of hole was not viable. Planning focused on how to maximise operational efficiency by using a cap fluid to trip in and out of hole without compromising open hole integrity and well safety. In this paper, we discuss the design of the mud cap fluid, selection of Changeover Depth (CoD), risks associated with use of the cap fluid, determination of available window for mud cap placement and removal, planning and execution of mud cap placement and removal, challenges of running and displacing the cap fluid with a liner and, lessons learnt from repeated use of the technique throughout the well construction phase, including coring and wireline logging under MPD conditions. Significant operational efficiency was gained from the use of cap fluids, making it possible to drill a well which would otherwise have been near impossible to drill with minimum lost time.