For the development of the HPHT gas field Dvalin a completion scheme using standalone screens is planned. To secure maximum clean-up and productivity, even after long term suspension, comprehensive lab testing of specific properties from drilling and completion fluids at downhole conditions, e.g. optimum bridging, minimizing formation damage, thermal stability and mobility was carried out. Furthermore, compatibility with production screens and formation fluids were verified. Drill-in fluid systems were advertised by different vendors to be compatible under the given initial reservoir conditions. For the sake of efficiency, the systematic test program consisted of a sequence of four test phases, where only successful fluids went to the next phase. The most important parameters of the test program were long-term high temperature stability and related sand screen compatibility, a detailed rheology characterization as well as complementary formation damage and return permeability tests. Finally, the additive concentrations of the awarded fluid system were systematically optimized to yield the least completion- and formation damage and highest return permeability.

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

An operator had a critical offshore water injection well which was not performing as expected, having an injection rate well below target. The well had a lower completion comprised of four frac sleeves in the horizontal section. A light well intervention (LWI) operation was carried out to evaluate the ball seats and valve status, any blockage that might be present, and to determine the required intervention scope going forward. A camera diagnostic run indicated the presence of debris. A subsequent LWI operation was planned, to deploy an electric line powered mechanical toolstringto mill out all four ball seats and perform a perforation operation across all zonesto generate the desired injectivity rate. Ball seats of reducing sizes had been deployed in the lower completionranging from 3.403 in. ID for the uppermost to 2.697 in. ID for the lowermost. The operator wanted the efficiency of a single run solution to execute the entire milling operation. This required a multistep mill of appropriate sizing to be designed, one that would mill all four ball seat sizes in the completionto a common maximum ID. This would then enable passage for subsequent deep penetrating or big hole perforation charges to be run. The electric line string incorporated a high level of instrumentation to provide real-time measurement and control of the criticalparameters for milling optimization. A Tractor would provide toolstring conveyance, rotational anchoring, and weight-on-bit (WOB). Tension/compression subs would provide in-situ measurements of the WOB. Arotationalsub would provide the torque. Monitoring and adjusting the torque, WOB, and rotational speed in real-time would enable an optimized rate of penetration throughout all steps across all ball seatsconfronted. Thorough pre-job tests were carried out on identical ball seats placed in a test-jig set up. Key toolstring parameters were monitored and the time required to mill through each ball seat was captured, this to determine the optimal tool parameters to use throughout the operation. All four ball seats were milled out successfully in a single run operation, with the toolstring providing both milling and back reaming, this ensuring no sharp edges remained as a result of the milling. The full milling operation was completed in a matter of hours, far below those experienced by the operator on previous operations. Upon return to surface little to no wear was found on the step mill and all mill sections were found to still be well in gauge. In effect, the step mill was used as a drift run, post milling operation, allowing the perforation runs to immediately follow. Following the subsequent perforation operation, the injectivity rate increased considerably, this contributing to increased production from the neighbouring producer wells.

Formation damage by the drill-in fluid has been identified as a major risk for the Dvalin HT gas field. To ensure the long-term stability and mobility of the mud even after an extended suspension time between drill-in and clean-up of the wells, a novel static aging test under downhole temperature and high pressure was conducted. Experiments have shown that the downhole stability is commonly underestimated when the surrounding pressure is lower than in the field. Thus, a high-pressure cylinder was used in vertical orientation in a heating oven with a pressure pump regulating the pressure up to 200 bar. The reservoir section was drilled with the optimized organo-clay-free oil-based drilling fluid (OCFOBDF) specified in the qualification phase. Tracers in the lower completion were used to identify clean-up from the upper high-permeability streak and the deeper (relatively lower) high-permeability streak. Due to extended wait on weather after drilling and completion of the first of the four wells, the lag time until clean-up was almost 11 weeks (74 days). It could be experimentally shown that the qualified OCFOBDF system weighted with micron sized barite remains mobile without phase separation even after static aging at 160 °C and 200 bar for the maximum estimated lag time between drilling and clean-up of 3 months. The absence of a gas cap in the set-up also better represents downhole conditions in the reservoir section and has shown that it improves the fluid´s stability. The clean-up of the well was successful with a maximum flowrate of 3.0 MM Sm3/d. Analysis of the tracers has proven that clean-up was successful for the entire reservoir section, including the deeper part. It could be concluded that in alignment with the lab tests that the mud fulfilled its requirement to be mobile even up to three months. Because of the superior properties, settling of solids (bridging and weighting material) could be avoided, resulting in no blockage of the (lower part of the) reservoir. The use HPHT aging has been the key to proving the long-term stability and mobility of the combined Drill-In and Completion Fluid. This technique falls outside of current API RP testing practices but is believed to be highly beneficial for qualification of fluids that will be left in the lower completion for long periods, especially in open hole completions under high temperature and pressure.