In mature fields the difference between the pore pressure and fracture pressure, expressed as the hydraulic window, is reduced. Underbalanced drilling and the use of low-viscosity drilling fluids are but a few of the many approaches that have addressed this challenge. While low-viscosity fluids severely reduce frictional pressure loss when compared to more viscous fluids, there is a limit to how much viscosity can be reduced before conventional weight material begins to settle. This paper describes the development and application of novel technology that has resulted in a ten-fold reduction in the particle size of the weighting agent. With this development, invert emulsion drilling fluids can be designed with low viscosity with minimal settling potential of the weight material. The authors will explain in detail the first field applications of this polymer-coated, micron-sized weighting agent in an oil-based drilling fluid. The system was used to drill two wells offshore Norway. These reservoir wells included an 8 1/2-in. section and a 5 7/8-in. thru-tubing section. This novel drilling fluid technology delivers a low-rheology, low-sag fluid offering a number of performance benefits over conventional technology. Performance data from offset wells will be presented that show the benefits of this unique approach. Equivalent circulating densities (ECD) and torque values were significantly lower than comparable wells and no instances of particle settlement were observed. Introduction The Statfjord Field was discovered in 1973 and declared commercial in August 1974, with production startup in 1979. The field spans approximately 25 km by 4 km, and is the largest producing oil field in Europe. Statfjord is located in the Tampen Spur area, in the northern portion of the Viking Graben, and straddles the border between the Norwegian and UK sectors. The field is developed by three fully integrated Condeep concrete platforms. Production is from the Brent, Dunlin, and Statfjord reservoirs, with Brent and Statfjord being the main reservoirs. Cumulative oil production by end of 2003 is forecasted to 626 million Sm3, giving a recovery factor of 63%. The aggressive drilling campaign necessary to achieve such a high recovery is described by Hansen, et al.1 Development of the field has required drilling of long and complex wells, often in reservoir compartments with high pressure depletion. Good hole cleaning and ECD have been and still are main focus areas for achieving a successful drilling operation. Introducing annular pressure-while-drilling tools in the mid 90's highly increased the understanding of hydraulic behaviour in the drilling process.2 However, introduction of Through-Tubing-Reservoir-Drilling (TTRD), possible future ERD wells, and several lost circulation events in the later years, have pinpointed the need for a highly inhibitive drilling fluid system exhibiting a low ECD, low friction and low sag potential. A drilling fluid with these combined properties will also be of key importance if the planned pressure blowdown of the reservoirs in the field is being carried out, as this will narrow the hydraulic window further. In case of pressure blowdown, there will also be a need for openhole sand screens, and the drilling fluid must preferably be "screen friendly". The geological anomalies of Statfjord and similarly mature fields worldwide prompted the initiation of a weighting agent research project (WARP). Conceptually, the foundation of the program was to employ ultra-fine particles of a weighting agent that have been polymer coated to provide a number of technical benefits in drilling fluids. The weighting agent, in this case barite, is milled in an enhanced mineral oil using high-performance milling technology. In this manufacturing process as the barite particles are milled, the new surfaces that are continuously exposed are coated with the special polymer additive. This coating provides effective oil-wetting of the barite weighting agent to produce stable high-solids, high-density and less viscous slurries.

Historically, the surface holes of the wells in the West Azeri field of the Caspian Sea were drilled conventionally with seawater and gel sweeps. However, seawater destabilized the highly reactive soil formations in the surface interval, resulting in unacceptable movement of the 20-in. casing. Further examination identified mechanical and chemical destabilization of the reactive shallow soils as the root causes of this instability. This paper describes the application of a silicate-based drilling fluid system1,2,3,4,5,7,8 in tandem with a unique Mud Recovery System (MRS) that combined to stabilize the problematic formation and allowed for the successful setting of the 20-in. casing without the lateral movement experienced in offset wells. The operator conducted laboratory tests to identify possible fluid alternatives that would provide the necessary chemical stability to provide support for the template and casing. The laboratory investigation considered conventional SBM, glycol/polymer/KCl and silicate/polymer/KCl inhibitive water-based fluids, and a KCl/NaCl/high-performance waterbased mud (HPWBM) as possible alternatives. The oil-based, HPWBM and silicate systems demonstrated excellent chemical stabilization. Offshore discharge restrictions negated the use of oil-based drilling fluids if the MRS was used. The HPWBM provided an alternative but logistics eliminated it from the initial consideration, thus opening the door for the first-time use of the silicate-based system in the Caspian Sea. The authors also review the application of the MRS system that utilized the rig pumps to deliver the fluid down the drill pipe and up the annulus to specially designed equipment on the sea floor. The latter used a sub-sea disc pump to transfer the fluid to the surface for conventional solids processing and maintenance. This technique provided a dual gradient to control the equivalent circulating density. Three field tests were conducted to determine the best fluid and mud weight for use in drilling the surface holes for the operator's template in the West Azeri field. The first test with the MRS unit used a conventional silicate/polymer/KCl system; the second test employed a synthetic-based drilling fluid with a pin-connector and a riser. A third trial utilized the silicate/polymer/KCl system with increased concentration levels of silicate and KCl and a higher mud weight. The authors will review the fluid planning, the performance of the three field trials, and the results which have been implemented into an ongoing field development program. Introduction The shallow soils in the West Azeri field are highly reactive and deformable; the pore fluid is nearly salt-saturated whereas the Caspian seawater is merely brackish. Initial drilling experience using conventional practice of seawater and high viscous sweeps resulted in severe washouts and pack-offs with eventual lost circulation. The initial template was abandoned due the unacceptable movement of the surface casings. In order to solve the instability problem, laboratory inhibition tests using Azeri soil samples were run to identify possible drilling fluid solutions. Inhibition tests in the laboratory showed the soil dispersed rapidly in seawater and various brines, thereby, identifying that salinity alone was not the solution.10 Geomechanical studies suggested that an increased mud weight was required in addition to chemical stabilization.9 The application of the mud recovery system (MRS) provided a solution to allow using a higher mud weight, minimizing the effect on the equivalent circulating density (ECD) at the shoe. The unit provides transfer of the fluid and solids from the seafloor to the surface via a sub sea disc pump. This technique provides a dual gradient condition resulting in ECD pressures lower than those observed with a conventional riser. Laboratory tests evaluated several inhibitive water-based alternatives including glycol, silicate and high-performance water-based muds (HPWBM). Caspian seawater and kerosene (simulating OBM performance) were used as reference benchmarks. Based on this data, as well as logistics contingency, a silicate system was selected for a trial evaluation in the Azeri field. The objective of the field trial was to set 30-in. conductor and drill a 24-in. hole without disturbing the surrounding formation. Additional criteria for success were satisfactory drilling performance, wellbore strength, and an in-gauge wellbore.

A drilling fluid designed for drilling long horizontal wells in extremely depleted chalk reservoirs within the limitations of a narrow mud weight window, high overbalance, high solids contamination and static periods was successfully implemented when drilling a water injection well on Valhall Flank North in the southern Norwegian Continental Shelf. In parts of the Valhall reservoir the depletion is estimated to 313 bar (4500 psi). The estimated pressure gradients in the planned trajectory were pore pressures between 0.64 sg and 0.70 sg (5.3 ppg to 5.8 ppg) and with a corresponding fracture gradient of 0.95 sg (7.9 ppg). These conditions required a drilling fluid which could be maintained at a density as low as 0.78 sg (6.5 ppg) combined with a low viscosity, strict fluid loss control, tolerance towards contamination of chalk and high stability. No conventional drilling fluid would provide a sufficiently low density to drill this section, thus an unconventional solution had to be found. The proposed solution was to add hollow glass spheres (HGS) rated to withstand pressures up to 1310 bar (19,000 psi) to reduce the density of a conventional fluid. However, previous experience using HGS as an additive in drilling fluid was limited. Therefore, the design and qualification of this drilling fluid had to be conducted both in the laboratory as well as on a larger scale yard-trial. Laboratory testing and the yard trial verified the feasibility of mixing the HGS in a large-scale production and confirmed their ability to withstand the expected downhole pressure and mechanical strain while drilling. The 1750 m (5740 ft) 8.5" injection well on Valhall Flank North was drilled in one run, with no drilling fluid-related problems. The drilling fluid density was maintained between 0.78 sg (6.5 ppg) and 0.85 sg (7.1 ppg) while the maximum measured equivalent circulation density (ECD) increased from 0.83 sg (6.9 ppg) at start of the section, to 0.96 sg (8.0 ppg) at section TD. Completing this well was resulted in an increase of 7.5 mmboe recoverable oil demonstrating that implementing HGS in drilling fluids provides an expanded operational envelope and access to so far inaccessible oil reserves.

The HPHT well, A-16A, was planned to test a certain part of the Kvitebjørn field in the North Sea for hydrocarbons in order to prove sufficient reserves to justify a field development. Drilling fluid selection and optimization in the planning phase was considered to be one of the key factors to be able to drill the pilot slim hole section through the Deco/Brent and Cook formations which brought challenges above the standard Kvitebjørn wells due to the risk of high depletion combined with high initial pressure.The well was planned with a pilot hole, A-16, in order to test the drillability of the overlying strata and prove the absence of highly depleted sand formations. It was important to penetrate all possible depleted zones in the pilot well to verify that sidetrack can be drilled to produce from the Statfjord target. Oil based drilling fluid weighted with treated micronized barite (OB TMB) together with a wellbore strengthening approach was successfully implemented to achieve the pilot well goals.Managed pressure drilling (MPD) and rig assist snubbing (RAS) equipment were rigged up and the 5 ¾-in pilot section was drilled through a 7-in temporary upper completion (TTRD) set in 9 7/8-in casing. MPD and RAS technologies were used in order to control the bottomhole pressure accurately and to ensure that the additional two barriers were maintained in the well at all times, even if the primary fluid barrier was lost due to crossflow.The paper provides detail about the drilling fluid planning and execution for the pilot slim hole section; this includes the fluid design and work performed to select and optimize wellbore strengthening materials (WSM) package. The WSM package was optimized by sophisticated, formation fractured, laboratory tests based on the fracture size estimated by proprietary software. Initial formation losses observed while drilling were cured with the particles kept continuously in the fluid, which eliminated the use of extra lost circulation material (LCM) pills or cement slurries. The section was then drilled with more than 500 bar (7252 psi) hydrostatic overbalance (including MPD back pressure), with no further formation losses and without differential sticking incidents while taking pressure points in the extremely depleted zones.The interval was drilled through extremely depleted formations with the highest overbalance drilling in the operator's experience. Superior integrity of the WSM prevented losses and minimized fluid treatments; this reduced the overall costs with minimal logistics. Low density (~1.5 specific gravity) WSM prevented particle settling in the well or in the drillstring and within the surface equipment, which proved the reliability of the design for MPD sections.