Summary In this paper we describe the analysis, test, and design work to deliver an optimal lower completion for a trilateral well by integrating passive and autonomous inflow-control devices (ICDs) (AICDs) at the Alvheim Field offshore Norway. In 2015, both passive ICDs and AICDs were tested in the laboratory with Alvheim fluids at reservoir conditions. The experimental flow testing demonstrated that the AICD chokes gas more efficiently than the passive ICD. The experimental results enabled correct modeling of AICDs in both the reservoir-simulation model and the simpler steady-state inflow model. The following lower-completion strategy was established for the new well: Where the well was close to the overlying gas cap, AICDs should be used, whereas passive ICDs with variable strength were to be used elsewhere to optimize the inflow. During the drilling phase, the steady-state model was updated with the as-drilled information; the lower-completion design for each branch focused on obtaining what was estimated to be an optimal inflow depending on the oil volume per drainage area. A key uncertainty in the design work was whether shaly zones along the wellbore would creep/collapse with time and act effectively as packers. The lower completion covered 7 km of reservoir penetration in the three branches, and 15 unique oil tracers were installed to evaluate the cleanup and the inflow profile along the well. The well started producing in May 2016 and a successful cleanup was confirmed by oil-tracer responses. In August 2016, a restart-tracer-sampling campaign was performed after a 12-day shut-in, and this formed the basis for a “chemical production log.” The tracer-based inflow interpretation was compared quantitatively with the model-predicted inflow and qualitatively to the tracer responses seen during the cleanup. The comparison confirmed that the lower completion works as initially planned. The interpretation further indicated that the upper zone has a lower degree of pressure support than the lower zone, and that the larger shaly sections have creeped/collapsed and act as packers. The well has exceeded predrill production expectations, with an average oil rate of 3375 std m3/d (21,240 STB/D) during the first production year. A large part of exceeding the predrill expectations is attributed to the lower-completion design, where the focus has been to optimize such that the whole well contributes, from the heel to all toes.

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.

This paper describes the analysis, test and design work to deliver an optimum lower completion for a tri-lateral well, by integrating autonomous and passive inflow control devices (ICD), in the Alvheim field offshore Norway. Chemical tracers, permanently installed in the completion, enabled the evaluation of inflow performance in each lateral. This continues to give valuable information to assess whether the tri-lateral completion is performing as predicted, improves reservoir characterisation and guides reservoir management decisions. In 2015, both passive and autonomous inflow control devices (AICD) were tested in the laboratory with Alvheim fluids at reservoir conditions. The experimental flow testing, reported in this paper, demonstrated that the AICD chokes gas more efficiently than the passive ICD, but also that the strength of the AICD were lower than expected a priori. The experimental results were used to model the AICD correctly and establish a lower completion strategy as follows: where the well was close to the overlying gas cap, AICDs should be used, while passive ICDs with variable strength were to be used elsewhere to optimise the inflow. Steady-state inflow modelling was performed before the drilling operation and updated accordingly with the as drilled information. The lower completion design for each branch focused to get what was estimated to be an optimal inflow based on oil volume in place. A key uncertainty in the design work was whether shaly zones along the wellbore would creep/collapse with time and act effectively as packers or not. The lower completion covered around 7 km of reservoir penetration in the three branches, and 15 unique oil tracers were installed to evaluate the clean-up and the inflow profile along the well. The well started producing in May 2016 and downhole flow control valves enabled a successful clean-up, as confirmed by oil tracer responses. In addition, a restart tracer sampling campaign was done after a 12-day shut-in, in August 2016, and this formed the basis for a "chemical production log". The tracer based inflow interpretation is compared quantitatively with the model predicted inflow and qualitatively to the tracer responses seen during the clean-up. This gives valuable feedback to the completion design, and assist in understanding the various degrees of pressure support and if the shaly reservoir sections have creeped/collapsed or not. The well has exceeded pre-drill production expectations, with an average oil rate of 3375 Sm3/d (21240 stb/d) during the first production year. This is a consequence of higher than expected NTG, but is also partly a result of the lower completion design, where the focus has been to optimize the lower completion such that the whole well contributes, from the heel to all toes. To the knowledge of the authors, this is the first well in the world with a lower completion integrated with AICDs, ICDs and chemical tracers.

When used for running sand control screens, low-solids, oil-based completion fluids (LSOBCF) maintain reservoir wellbore stability and integrity while minimizing the potential risks of losses, screen plugging, completion damage, and productivity impairment. Until now, using LSOBCF as a screen running fluid (SRF) has been limited by fluid density. The design, qualification, and first deployment of an LSOBCF that incorporates a newly developed, high-density brine as the internal phase to extend the density limit is discussed. The following parameters were examined as part of the preliminary qualification: rheology performance, long-term stability, fluid loss (filter-cake repair capability), reservoir fluid and drill-in fluid (RDIF) compatibility tests, emulsion breaking test, production screen test (PST) on 275 µm screen, crystallization temperature [true crystallization temperature (TCT) and pressurized crystallization temperature (PCT)], and corrosion rate. The fluid was then tested for formation and completion damage performance, where the high-density, brine-based LSOBCF exhibited minimally damaging behavior in the core-flow tests. As a result of the positive observations made during these wide-ranging laboratory tests, this new high density-based brine was deemed as a good candidate in an LSOBCF for high-density SRF applications. Viable LSOBCF with densities up to 1.50 SG have been designed. This paper details the design and field application of a 1.45 SG LSOBCF. Calcium bromide (CaBr2) brine is commonly used during the discontinuous phase for LSOBCF applications that require fluid densities up to 1.38 SG. For higher density requirements, LSOBCF use a cesium formate brine as a discontinuous phase. Using the new developed brine in the discontinuous phase provides viable LSOBCF up to 1.50 SG. The base brine has a good environmental rating, is pH neutral, and provides improved safety during low-temperature/high-pressure conditions. As a standalone fluid, the new brine can achieve densities up to 1.80 SG, with acceptable TCT and PCT values for North Sea applications without using zinc or formate-based brines. After laboratory qualification, the final fluid formulation was deployed on a dual lateral oil producer well with 9.5 in. horizontal reservoir section lengths of 2315 and 1696 m. After drilling the sections using an engineered low equivalent circulating density (ECD) oil-based RDIF (OB RDIF), each section was sequentially displaced to 1.45 SG LSOBCF. The lower completion, consisting of 5.5 in. screens equipped with autonomous inflow control devices (AICD) and swellable packers, was successfully run to bottom without significant issues. The field application demonstrated evident operational efficiency gains. The positive pre-deployment formation response test (FRT) results have been verified by well productivity data. The process to qualify the brine for first-use application in LSOBCF is described, and laboratory testing (including FRT), mixing and logistical considerations, field execution, and well productivity are discussed.