The Boa and Kameleon accumulations in the Alvheim field have thin oil rims developed with long horizontal wells. Several of the latest wells are characterized as attic infill wells, drilled in the remaining oil rim, close to the gas cap, and shallower than the early wells. Autonomous inflow control technology is a key enabler for these wells. This paper describes the design, execution and performance review of a Boa attic well. This well combined passive and autonomous inflow control devices (AICD). The AICDs used were tested with Alvheim fluid in the laboratory. A clear lower completion strategy was essential in the planning and execution of this well, e.g. to use AICD close to the gas cap and to design inflow linked to estimated oil per drainage area. 4D seismic interpretation, pilot wells information and deep resistivity logging while drilling were other critical factors to plan and optimize the well path. Tracers were mounted in the sand screens to monitor clean-up, inflow per zone and the onset of water production. The steady state inflow model was used extensively in the execution and review phases. Pilot wells information and logging while drilling enabled successful geo-steering. During the drilling phase, the steady-state model was updated with the as-drilled information and the lower completion design adjusted to get what was estimated to be an optimal inflow. Tracers sampled during the clean-up indicated good clean-up of the entire well. The initial well performance with no water and low free gas amounts gave a larger pressure drop than expected. A later tracer based chemical PLT gave also slightly different results than expected. Pressure data, tracer data, log data and the effective multi-phase AICD model were thoroughly investigated to derive scenarios, that could explain this discrepancy. The most likely scenario gives a good history match for both pressure and tracers and gives extra insight into key reservoir parameters, zonal inflow and the effective behavior of the AICDs during multi-phase flow. The well has exceeded pre-drill production rate expectations, despite the larger than expected pressure drop. This is partly explained by the autonomous choking on gas inflow along the wellbore. The post-review evaluation enables continuous improvements for Alvheim and similar fields.

Siliciclastic turbidite lobes and channels are known to exhibit varying degrees of architectural complexity. Understanding the elements that contribute to this complexity is the key to optimizing drilling targets, completions designs and long-term production. Several methods for 3D reservoir modelling based on seismic and electromagnetic (EM) data are available that are often complemented with outcrop, core and well log data studies. This paper explores an ultra-deep 3D EM inversion process during real-time drilling and how it can enhance the reservoir understanding beyond the existing approaches. The new generation of ultra-deep triaxial EM logging tools provide full-tensor, multi-component data with large depths of detection, allowing a range of geophysical inversion processing techniques to be implemented. A Gauss-Newton-based 3D inversion using semi-structured meshing was adapted to support real-time inversion of ultra-deep EM data while drilling. This 3D processing methodology provides more accurate imaging of the 3D architectural elements of the reservoir compared to earlier independent up-down, right-left imaging using 1D and 2D processing methods. This technology was trialed in multiple wells in the Heimdal Formation, a siliciclastic Palaeocene reservoir in the North Sea. The Heimdal Fm. sandstones are generally considered to be of excellent reservoir quality, deposited through many turbiditic pulses of variable energy. The presence of thin intra-reservoir shales, fine-grained sands, heterolithic zones and calcite-cemented intervals add architectural complexity to the reservoir and subsequently impacts the fluid flow within the sands. These features are responsible for heterogeneities that create tortuosity in the reservoir. When combined with more than a decade of production, they have caused significant localized movement of oil-water and gas-oil contacts. Ultra-deep 3D EM measurements have sensitivity to both rock and fluid properties within the EM field volume. They can, therefore, be applied to mapping both the internal reservoir structure and the oil-water contacts in the field. The enhanced imaging provided by the 3D inversion technology has allowed the interpretation of what appears to be laterally stacked turbidite channel fill deposits within a cross-axial amalgamated reservoir section. Accurate imaging of these elements has provided strong evidence of this depositional mechanism for the first time and added structural control in an area with little or no seismic signal.

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Reservoirs containing complex structures require additional technology to obtain optimum performance from planned production wells. In this scenario, logging-while-drilling (LWD) technologies play an important role in well construction from purely geometric trajectories to the real-time trajectory steering and formation and fluid characteristics measurements. A North Sea Alvheim field case study is presented in this paper. During the exploration and initial development phase of the field, the oil/water contact (OWC) varied to 7 m due to the presence of mudstone baffles and faults. The field has been on production since 2008 using bottom-aquifer drive, and current fluid contacts have shifted from their initial levels. To enhance field recoverable reserves, an infill development plan was required to place the wells within a thin oil rim between the gas/oil contact (GOC) and the OWC. Field objectives included achieving optimal well landing, identifying the moveable oil in situ, mapping the hydrocarbon-bearing reservoir, and identifying the hydrocarbon type (oil or gas) along the wellbore trajectory. To address the challenges, an integrated drilling bottomhole assembly (BHA) consisting of a deep-directional resistivity (DDR) tool to refine the reservoir delineation and structural positioning, a downhole fluid analyzer (DFA) using optical spectrometry to identify in-situ fluids, and advanced petrophysical measurements provided a complete quantitative reservoir evaluation during well construction. This paper presents the design, execution, and interpretation of the acquisition program to achieve the well objectives, including positioning the producer well in the desired moveable fluid zone. The final results demonstrated that integrating LWD measurements in the operation added significant value toward achieving the desired wellbore trajectory by optimally positioning the wellbore in the desired reservoir fluid layer.