A rigid riser system has been designed, built, and proven as an effective method to conduct coiled tubing operations on floating platforms. This system is installed above the Christmas tree which is supported by the platform's production riser and riser tensioner system. The rigid riser set up is a passive system that does not require the use of a crane or other mechanisms to support or hold up the coiled tubing injector head during operations. The axial load resulting from the weight of the injector head, coiled tubing, and snubbing/pulling forces on the pipe are carried in compression through the rigid riser to the tree and wellhead. The excess capacity of the top tensioner riser (TTR) supports these loads while allowing for relative motion due to tide, waves, and platform motion. The rigid riser system uses a purpose-built, heavy-wall riser and a spider beam insert to resist buckling effects and bending moments. In practice, this system has improved the rig-up time and mitigated HSE issues as compared to the conventional motion-compensated lift frame method. In addition, the system has a support frame that increases the rigidity of the injector head and accessories, resisting the excessive bending and torsional loads imparted by back tension and movements of the coiled tubing (CT) reel. An engineering study was performed to determine the dynamic loads and stresses for the various operational and contingency conditions on all the components of the rigid riser system and to confirm sufficient capacity of the TTR system. The rigid riser system has proven to be a safe and cost-effective solution for coiled tubing operations from a floating platform compared to current motion-compensated jacking frame systems. Coiled tubing well interventions were executed using the rigid riser system, and the operational results have been convincing. The passive nature of the system provides an HSE advantage by eliminating mechanical or human intervention during operation. This paper reviews the design aspects of the rigid riser system, its advantages over the current coil tubing intervention systems, and the operational results after executing the coiled tubing interventions.

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.