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 Dvalin gas field is located in the Norwegian sea on NCS and is operated by Wintershall DEA Norge. It is supported by two independent reservoir structures, Dvalin East and Dvalin West. The field was explored through wells 14S and 15S in 2010 and 2012, respectively. The field is characterized by dry gas, high CO2, high temperature (160 °C) and high pressure (SIWHP 620 bar). The targeted Garn sandstone has good reservoir quality, but with a high permeability contrast. The field development was sanctioned in 2016 and calls for a 4 well solution through a centrally located subsea template, producing gas back to the host platform Heidrun TLP 15 km away. Water depth at location is 380 m and targeted reservoirs are at 4140 m MSL (East) and 4240 m MSL (West). Production plateau rates are estimated to be approximately 106 MMscf/D (3 million std m3/d) per well where thin high-permeability zones within the Garn formation are expected to dominate the inflow. The lateral facies development is thought to be relatively homogenous throughout the field, thus S-shape wells falling off to vertical through the reservoir will ensure effective drainage. Sand failure is expected after short time of production and would increase the risk of erosion causing severe damage to well jewelry and production facilities. It has been decided to integrate sand screens as a means of downhole sand control as part of the primary lower completion design. The sand screens will offer sand control, erosion resistance, hot spotting resistance as well as robustness towards a full hole collapse during reservoir pressure depletion. As the subsea completions are carried out from a mobile drilling unit in harsh environments, protection of the sand control filter media during installation is of utmost importance. This paper will describe the selection process of sand control and qualification steps carried out to use ceramic screens as the stand-alone screen solution for successful deployment and integrity for the Dvalin field development

Downhole sand control selection plays a vital role in sand free production optimization over the well lifecycle. Design and selection criteria to assess the optimum sand control methodology requires consideration of many inputs to assess the sand control service life. A qualified sand control method, offering high erosion resistance is critical to enhance service life, especially in cases where small particles may be entrained in the produced fluids at high velocity. An integrated approach considering advances in filter media material, allow integration of ceramic components, to redefine operating envelope of sand control screen. In the process of designing and selecting a suitable sand control method for a high-rate gas well application in Norway, ceramic sand screens were considered as a possible solution to manage the high erosion loading expected during production. To estimate the operational limits for stand-alone ceramic sand screens, a series of erosion tests were conducted by a third party research and testing agency defined by the operator to evaluate the erosion behavior of the ceramic filter element. As indicator for erosion the filtration cut point (FCP) of the ceramic filter element was used. The testing allowed the operating envelope of the ceramic screens to be defined in terms of FCP and erosion load. For a specific increase in FCP value the operational limits for a stand-alone ceramic sand screen can estimated. This methodology was then applied to a specific field application to predict ceramic sand screen lifetime for the expected production profile. This paper presents the results of the study, using CFD simulations and, independent industry testing methodology to investigate the suitability and expected service life for stand-alone ceramic sand screen. Understanding the operational erosion risk profiling enables the operator to apply an erosional resistant stand-alone screen approach offering reducing planning, deployment complexity, lower HS&E risk and increased flexibility in optimising the wells production envelope.