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.