fax 01-972-952-9435. AbstractDuring the drilling and completion of the Huldra field in the North Sea, high temperature and high pressure conditions were expected and encountered in the reservoir section. The difference between the pore pressure and the fracturing pressure is small. Cesium formate had been evaluated as a potential drilling and completion fluid, but technical hurdles could not be completely addressed in time for the first well. As a result of well control problems occurring in the first well, with barite sag in the oil based drilling fluid as a contributing factor, it was necessary to use a drilling fluid with insignificant potential for sag. For the first time worldwide the cesium formate brine was chosen as a drilling fluid. This fluid could be delivered solids free with densities up to 2.2 s.g. The required down hole density in the well was 1.91 s.g. At the same time it was necessary to have as little contribution to the equivalent circulating density (ECD) from the flow as possible.The paper describes how the cesium formate brine was used successfully as a drilling and completion fluid. The effect of the fluid on well control, hole cleaning, rate of penetration (ROP), torque/friction, ECD, formation damage, casing wear and hole stability are covered. The paper also describes actions required to minimize losses of this very expensive fluid.The challenges acquiring adequate formations logs while drilling are also described. Finally, the use of cesium formate brine during the completing of the wells with open hole sand screens is outlined.

Cementing high-pressure, high-temperature (HPHT) wells poses various challenges not seen at normal well conditions. For instance, the following objectives are critical for HPHT wells:Prevent losses during drilling fluid circulation and cement slurry placement.Displace the drilling fluid and place the cement slurry effectively.Prevent free-water or gas-channel development.Reduce slurry fluid loss.Provide support for the production packers.Decrease compression loads on casing connectors.Prevent damage to cement sheath.Prevent annular gas pressure over the life of the well. The industry is recognizing the interaction between these factors to determine the optimal cement job design for accomplishing these objectives. This paper presents and discusses the engineering analysis to determine the optimum foamed cement sheath properties for integrity during the life of the well at HPHT conditions. Also, this paper compares foamed cement to nonfoamed slurries in achieving these objectives. Other important issues discussed are the performance of nitrogen at HPHT conditions and the rheological properties of the foams. Key issues addressed are the state and solubility of nitrogen under downhole conditions and the integrity of the cement sheath during the life of the well. Thermodynamic solution theory and experimental studies are applied to the former, and finite element analysis is applied to the later. Case examples are presented discussing foamed and conventional operations at near HPHT conditions for some Norwegian, North Sea wells. Cement properties are contrasted for the different foamed and conventional cement slurry properties with respect to:Achieving the HPHT objectives, such as placement efficiency and sheath propertiesPrejob design to obtain the objectivesJob planning and proceduresJob executionLogging of foamed cementPost-job evaluation of the cement systems Introduction Traditionally, the industry has concentrated on the short-term properties that are applicable when the cement is still in slurry form. This effort is necessary and important for effective cement-slurry mixing and placement. However, the long-term integrity of cement depends on the material/mechanical properties of the cement sheath, such as Young's modulus, tensile strength, and resistance to downhole chemical attack. Considering properties of the cement sheath for long-term integrity is critical if the well is subjected to large changes in stress levels such as with HPHT wells. Recent experience has shown that after well operations such as completing, pressure testing, injecting, stimulating, and producing, the cement sheath could lose its ability to provide zonal isolation.1 Failure of the cement sheath is most often caused by pressure- or temperature-induced stresses inherent in well operations. This failure can create a path for formation fluids to enter the annulus, which can pressurize the well and render it unsafe to operate. Failure can also cause premature water production that can limit the economic life of the well. Consequently, if the cement sheath fails during its active life, the objective of producing hydrocarbons safely and economically may not be met. The cement sheath should have optimum properties so it can withstand the stresses from well operations. In general, cement slurry should be compensated for volume reduction during hydration and the mechanical properties should be optimized for the well operations.

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.

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.