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This paper introduces and examines the prospect of subsea power generation at seabed level using marine current turbines to facilitate remote subsea tiebacks. Important parameters for the assessment of the feasibility of the technology are identified. The system can use proven ("off the shelf") technology for energy storage, power conditioning and switching, while turbine blade design issues are discussed. Results from a simulation code, built for the assessment of the technical feasibility of the system, are presented and discussed for representative base cases of two single-well production systems (all-electric and electrohydraulic). Introduction The substantial depletion of exploitable deposits in shallow waters of the continental shelf has increased the interest of the petroleum industry towards reserves at increasing water depths. As a result, enabling technology for the exploitation of deepwater reserves is developing exponentially. The emerging technology has made the prospect of hydrocarbon production from satellite reserves, which may lie considerable distances from production infrastructure, more attractive, subject to long distance tiebacks becoming more economical. As advances into production technology (e.g. subsea boosting, processing) make the exploitation of marginal fields technically feasible, the principal factors governing the use of subsea tiebacks become predominantly economic. Localised power generation offers the possibility of reducing the costs associated with the production from subsea tiebacks by:Reducing the required umbilical functionality, with associated reduction in power transmission costs.Reducing or removing power generation systems at the surface platforms, with associated increase of their payload capacity. Umbilicals, who together with flowlines, respresent the largest cost items in the post drilling phase of the production system installation, are used for the transmission of hydraulic and electrical power required for the production system operation, as well as control, data monitoring and chemical injection. From the above duties, the high-pressure power transmission lines (hydraulic power and chemical injection) are the most costly, followed by the electrical power lines, control and data monitoring. The removal of these operations will yield the corresponding cost savings to the system. Indicative of the potential economic benefits offered by the removal of hydraulic lines is the current trend in the deepwater arena to develop all-electric (hydraulics-free) subsea production systems, which eliminate the need for hydraulics lines in the umbilical. Furthermore, especially for large stepout distances (>30km), a large proportion (over 50%) of the power supplied from the topsides is lost in umbilical losses. Consequently, as stepout distance increases, the power generation requirements from the surface platform increase accordingly. Reduction or removal of the umbilical power transmission will reduce the power generation requirements from the surface platform, increasing its payload and lowering costs.

Installing an electrical submersible pumping (ESP) system in an oil well is one of the optimal artificial lift methods to increase production and maximize ultimate recovery. However, installing and retrieving an ESP using an offshore rig is costly and presents planning challenges. In some geographies and projects, offshore intervention rig costs and risks sometimes outweigh the potential gains of an ESP system. An operator in Malaysia was interested in installing an ESP system in an offshore well to maintain production rates, but the intervention costs were a roadblock. The challenge was to devise a rigless ESP deployment system that can be deployed through the existing completion to avoid the need for a rig, even on the initial deployment. The system would need to provide a 2000 BPD flow rate to justify the initial investment of the wellhead modifications, surface equipment, the newly developed rigless-deployed ESP system, and completions accessories. This new generation rigless-deployed ESP system features an inverted ESP with the ESP motor on top, connected directly to the power cable. This revolutionary design eliminates the motor lead extension, removing the weakest connection in traditional ESP systems. The rigless deployed ESP system enables deployment under live well conditions, eliminating the need to kill the well and the need for a rig – inclusive of the initial deployment. This paper reviews the design and deployment process of the first installation in Southeast Asia.

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A mature deepwater asset of 1,330 m of water depth offshore Sabah, Malaysia, has been delivering notable production since 2007, and currently the field is in its declining mode. The second phase of the field development focused on producing from the thin-bed layers of the reservoirs, which were found less efficient in pressure maintenance given existing water injection support as the primary support. Initial conceptual studies were conducted between 2012 and 2014 to determine which improved oil recovery (IOR) initiative would be the most effective and economical way to retain declining production of the field, extend end-of-life, and ultimately protect reserves. Further in-house engineering studies and follow-up with a field mini-trial in 2014 demonstrated that providing gas lift to the spar wells would improve and revive production of the targeted wells. A permanent coiled tubing (CT) with gas lift completion (CTGL) was determined as the most efficient and cost-effective solution. Single-point gas injection is sufficient given available injection pressure, static/dynamic fluid level, and the available maximum depth of the injection tip. Modifications of the dry tree on the spar facility were required to accommodate the changes; changes included a new 5-in. gas lift pipeline; topside piping at the spar; and installation of associated control, metering, and instrumentation devices. Specific CT bottomhole assembly (BHA)/components were determined to safely deliver gas inside the 3.5-in. and 4.5-in. production tubing to slightly above the well’s downhole safety valve. A total of 14 dry-tree wells were selected for this project and the project has successfully completed installation of CTGL in 11 wells by mid-year 2019. Wellhead modification was carried out by installing the tubinghead spool and gas injection arm. A CT rigid riser well stackup was rigged up directly on the tubinghead spool. The 1.25-in. outer diameter (OD) chrome CT string and gas lift BHA of specific simulated venturi sizes were deployed to the targeted depth in each well. Downhole completion safety valve and gas lift BHA double flapper check valves were then be inflow tested. Blowout preventer (BOP) was engaged against the 1.25-in. OD CT string, and pressure in the well stackup above the rams was bled off before cutting off the CT string. The CT tubing hanger was made up directly on the cut CT string. Finally, the CT tubing hanger was installed into the tubinghead spool with a 4-in. flow release pulling tool. An additional simulation study was performed to confirm the ability of the 1.25-in. OD CT BHA to inject up to 3 MMscf/D. The executed wells were brought online, and a comparison of the well tests was performed. The CTGL wells responded very well whilst being assisted with gas lift, which delivers an outstanding result by adding incremental gain of 20%, and even adding value to revive idle wells, which has significant value by doubling the base production figure without gas lift. An estimate of more than 50% protected reserves can be achieved with the 11 CTGL wells at the end of field life. The installation and execution of CTGL came at the right time as the field requires lift assistance to stay productive.