In areas with shallow water flow, additional casing strings are normally set to seal off the water-bearing zone. While drilling the first well in Fram East in the North Sea, the operator used a shallow 20-in. surface casing, but this measure increased well costs and caused a number of later limitations in the well construction process. To avoid these complications in other Fram East wells, the operator searched for alternative solutions.It selected a cement design with properties compensating for the loss of hydrostatic pressure and thereby preventing the water flowing. The service company carried out extensive designing and testing of the cement formulations. A major challenge was qualifying the final design for a full-scale field test. A third-party laboratory qualified the cement system, using a modified setup of the gas migration equipment. The results were promising.A dedicated cutting injection well was chosen for the field test. The successful test allowed planning the remaining wells using the new system with projected savings of more than USD 20 million. This paper will describe the development of the solution, the design, and testing of the cement formulation, and the full-scale field test performed. IntroductionThe main objective of the cement is to provide a hydraulic seal across the various permeable formations; zonal isolation is compromised when formation fluids such as water are allowed to enter the annulus. During and after the placement, the cement column and the other fluids in the wellbore or annulus exert a hydrostatic pressure that initially must be greater than the formation pore pressure to prevent invasion of formation fluids. However, as the cement hydrates, the cement slurry becomes self-supporting and the hydrostatic pressure exerted by the slurry decreases. When the hydrostatic pressure decreases below the formation pore pressure, formation fluids such as water can enter the annulus, potentially leading to water flow through the cement matrix, which leads to the loss of hydraulic isolation.

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.

Dvalin field, discovered in 2010-2012. The location of this field is in the Norwegian Sea, as shown in (Figure 1). Dvalin field is an HPHT gas field in Middle Jurassic sandstone in the Garn and Ile Formations – the former being homogeneous with better reservoir properties, during the later heterogenous with low quality. (DVALIN, 2020) The well 6507/7-Z-2 H objective is to produce hydrocarbons from the Jurassic reservoir section of the Dvalin field safely and cost-effectively. The well was planned to be drilled near vertical in the reservoir section and TD'ed at a maximum depth corresponding to the Garn Formation base. After the productivity results from Z-3-H well came in at the low end of expectations, it was evaluated and decided to change the well profile of the Z-2-H well from vertical reservoir penetration to a horizontal profile; to have two penetrations with a minimum of 150m MD separation in the upper high permeable streak and then drop to penetrate lower high permeable streak. This decision was conducted only three days before starting the 17.5-inch section on the subject well. One Team culture was the key to achieving this significant change successfully. The decision to change the well-profile was conducted after a thorough engineering evaluation, including offset well analysis, which was very limited as the closest horizontal well was more than 40 km away. As the well was not planned as a horizontal well, departure between the surface location and Target Easting & Northing was minimal. Therefore, a high turn and deeper inclination build were required, which added some complexity to the well design. One of the additional primary risks related to this change of trajectory design is deploying a more complex BHA design in the reservoir section with a full suite of LWD technologies run in an HT environment. In the planning phase, special consideration was needed to accurately simulate the expected circulating temperature and have proper procedures in place for temperature management and control. Being the first horizontal well in the field, thus detailed planning was key for successful execution. Ultra-Deep Azimuthal Resistivity Tool (UDAR) Reservoir-Mapping capability was considered to help optimize the landing and navigate within the reservoir section. A feasibility study was conducted, and a 2-receiver Ultra Deep Azimuthal Resistivity Tool BHA configuration was selected and deployed. During the execution, the Ultra Deep Azimuthal Resistivity Tool real-time inversion mapped the reservoir geometry, revealing resistive layers within the Garn formation, thereby facilitating optimal placement of the well to achieve the set objectives. The well execution was largely considered flawless, with the real-time Ultra Deep Azimuthal Resistivity Tool data and corresponding interpretations facilitating decisions.

One of the crucial components of well integrity evaluation in offshore drilling is to determine the cement bond quality assuring proper hydraulic sealing. On the Norwegian Continental Shelf (NCS) an industry standard as informative reference imposes verification of cement length and potential barriers using bonding logs. Traditionally, for the last 50 years, wireline (WL) sonic tools have been extensively used for this purpose. However, the applicability of logging-while-drilling (LWD) sonic tools for quantitative cement evaluation was explored in the recent development drilling campaign on the Dvalin Field in the Norwegian Sea, owing to significant advantages on operational efficiency and tool conveyance in any well trajectory. Cement bond evaluation from conventional peak-to-peak amplitude method has shown robust results up to bond indexes of 0.6 for LWD sonic tools. Above this limit, the casing signal is smaller than the collar signal and the amplitude method loses sensitivity to bonding. This practical challenge in the LWD realm was overcome through the inclusion of attenuation rate measurements, which responds accordingly in higher bonding environments. The two methods are used in a hybrid approach providing a full range quantitative bond index (QBI) introduced by Izuhara et al. (2017). In order to conform with local requirements related to well integrity and to ascertain the QBI potential from LWD monopole sonic, a wireline cement bond log (CBL) was acquired in the first well of the campaign for comparison. This enabled the strategic deployment of LWD QBI service in subsequent wells. LWD sonic monopole data was acquired at a controlled speed of 900ft/h. The high-fidelity waveforms were analyzed in a suitable time window and both amplitude- and attenuation-based bond indexes were derived. The combined hybrid bond index showed an excellent match with the wireline reference CBL, both in zones of high as well as lower cement bonding. The presence of formation arrivals was also in good correlation with zones of proper bonding distinguishable on the QBI results. This established the robustness of the LWD cement logging and ensured its applicability in the rest of the campaign which was carried out successfully. While the results from LWD cement evaluation service are omnidirectional, it comes with a wide range of benefits related to rig cost or conveyance in tough borehole trajectories. Early evaluation of cement quality by LWD sonic tools helps to provide adequate time for taking remedial actions if necessary. The LWD sonic as part of the drilling BHA enables this acquisition and service in non-dedicated runs, with the possibility of multiple passes for observing time-lapse effects. Also, the large sizes of LWD tools relative to the wellbore ensures a lower signal attenuation in the annulus and more effective stabilization, thereby providing a reliable bond index.