Since the beginning of production, well NA2 and NA3 wells had issues with wellhead integrity due to thermal growth and wellhead tilting. Seepage was observed from wellhead and based on gas chromatography test, the seepage is Synthetic Based Mud (SBM), possibly from B and C annulus (intermediate and surface casing). For well NA3, seepage was observed coming out from the connection of Casing Head and Drive Pipe Housing House (DPHH) while for Well A2, seepage was found between DPHH and conductor. The issues arise from the failed elastomer seals found at the connections of leak of each well suspected due to well growth/shrink and tilting which caused the wear and tear of the seals. The seepage of both wells was rectified by injecting the failed elastomer seals with pressure activated sealant to the P-seal and grease to the elastomer. Both wells managed to produce at the capped production rate without seepage as of today. Another main issue at Field N is the leaking of metal-to-metal seal at Xmas Tree which led to production deferment. Due to the failed barrier at surface, interim philosophy was established to operate the field and rectification plan was implemented to ensure the well is producing safely at the calculated risk. This paper describes the analysis and diagnosis, operating philosophy outline by operator which led to the well safely producing at the desired rate: (1) Standing Instruction (SI) for Well Production Ramp Up and Down based on trending of production and temperature to ensure wellhead growth and tilting will not affecting the integrity of sealant, (2) Finite Element Analysis (FEA) and Wellhead Growth Study to develop operating limit and maximum allowable growth, correlated with well production and temperature, (3) logging and survey for well leak detection and echometer survey, (4) Wellhead Seal Injection for corrective maintenance upon seepage observed, (5) manual measurement of growth and tilting and utilizing laser sensor for automation, (6) External Slip Lock Brace Support (ESBS) Installation to mitigate abnormal relative growth and (7) risk assessment for well integrity. The holistic approach in diagnostic, monitoring and operating philosophy enabled the well to be ramped up to higher production despite the threat of losing the gas production. PCSB also avoided the utilization of rig to rectify the well which resulted in cost avoidance for the company.

A prolific gas producer in Sarawak waters was shut-in and idle due to a tubing leak resulting in a significant decline in the total hub production. The well remained idle and required immediate remedial action to meet the contractual sales target. Hence, an expandable tubing patch was proposed to isolate the leak and reactivate the well faster. This paper presents data gathered to identify leak location, tubing patch design, and installation using real-time coil tubing. Several logging surveys were performed to detect leak depth including caliper log, leak detection log (LDL), and downhole camera run; since no pressure build-up was observed post bleed-off tubing and casing, while SCSSV was in closed-state. Running caliper log could not indicate severe metal loss of 7-inch tubing, hypothesizing that the leak could be of a smaller dimension. Therefore, LDL was conducted, indicating temperature gradient and acoustic energy changes at a single depth location of 247 ft.THF, above SCSSV. Utilizing the leak depth marker from acoustic log, a downhole camera was staged to verify geometry of tubing leak. Root cause failure analysis (RCFA) was carried out for this tubing anomaly using diagnostics data to determine the possibility of UHP-17Cr-110 tubing failure. The likelihood of tubing failure is attributed to two main causes namely oxygen corrosion cracking and stress corrosion cracking. Based on RCFA outcome, Hastelloy C276, a nickel-molybdenum-chromium superalloy with the addition of tungsten was selected for the patch material, which is V0 rated, internal gas-tight qualification for temperatures up to 150 degrees Celsius and 5,000 psi. Moreover, this patch material satisfies the well conditions at approximately 20% CO2, 200 ppm H2S, 1000 mg/L salinity, and varying Hg concentrations from 800-2,000 ug/Nm3. The design of patch has been improved by adding AFLAS elastomer for the whole exterior of patch to eliminate contacts between the two metals: reducing the risk of galvanic corrosion. Real-time coiled tubing application was selected for setting the patch to ensure accurate depth-sensing control. Additionally, patch is a rig less intervention technique that will not disrupt the production from the existing wells sharing the same drilling platform. Generally, for high-rate gas wells, economic indicators seem lucrative with tubing patch application, where the payout can be achieved within a month of continuous production. The first step in ensuring the success of tubing patch is by running right diagnostics tools such as leak detection logging and downhole camera run, since multi-finger caliper analysis alone would not locate the leak depth and the leak geometry precisely. Valid design inputs are quintessential for the fitting recommendation of tubing patch design which includes accurate reservoir and fluid properties to ensure sustainability of the expandable tubing patch application.

In 2020, PCSB implemented the first permanent Plug & Abandonment (P&A) campaign for three Subsea wells in a gas field offshore Malaysia. The main objective of the campaign was to establish two (2) barriers for every movable hydrocarbon or overpressure bearing sand by placing laterally extended cement plug across impermeable formation with enough formation strength to handle the pressure of the formation to be isolated. The unique case of this operation was the challenges to execute PCSB's first subsea P&A operation in gas field Malaysia during pandemic situation. In March 2020, the Malaysian government imposed Movement Control Order (MCO) to curb the spread of the COVID-19. A semi-submersible rig was on-hired a week after government initiated the MCO, resulted in the rig preparation being badly hampered due to manpower management and material fabrication and delivery. PCSB was exposed to expensive rig daily rate that had to be managed. Four (4) main challenges were encountered during operation: safe protection for workers, expensive standby cost, manpower management and material fabrication and delivery. This paper, from the ‘project management’ point of view, describes the journey of managing rig operation during PCSB's first subsea wells P&A in Malaysia efficiently amidst the pandemic by reducing the impact of COVID-19 on project cost. With the experience of managing rig for subsea well operation, a complex operation in Malaysia, amidst pandemic, PCSB sharing on the experience is beneficial to provide context setting and benchmark on maintaining the efficiency of operation. Wells successfully met the objective of operation with no incident occurred, negotiated reduction on standby cost and managed to bring critical manpower on time during operation.

Surface Controlled Subsurface Safety Valves (SCSSV) is a critical completion accessory to maintain the Safe Operation Envelope (SOE) of the well and ensuring the production sustainability. In PCSB, it is a requirement that SCSSVs are tested on specific periods to ensure this safety device meet the acceptance requirement as per company guideline. Monitoring and maintaining the SCSSVs is proven to be challenging for E1 gas fields, located in Offshore Malaysia. Wells in E1 field, recently transferred operatorship, is an aging field producing since August 1982. The wells are equipped with Wireline Retrievable SCSSV (WRSCSSV). Within few months after operating this well, few cases of SCSSVs inoperability were encountered, resulted in significant gas production loss from E1. The main problems with SCSSV are: Control line hydraulic pressure unable to build up and maintain, hence unable to flow the well as SCSSV unable to open. Abnormal hydraulic return observed. E11 wells tripped due to Wellhead Control Panel Hydraulic pressure header hit low-ow trip setpoint. Inoperable after well close in, indication of control line leak. Immediate action taken to rectify include retrieving the WRSCSSV and installing redressed old WRSCSSV, injecting and displacing of Pressure Activated Sealant through control line to patch leak point. Root Cause Failure Analysis (RCFA) conducted on the wells identified preliminary factors that lead to E1 SCSSV issues: Frequent SCSSV cycling with high control line pressure in depleted well pressure (Frequent well tripping and monthly Corrosion Inhibitor batching activity requires close in and opening of SCSSV). Non-compatible SCSSV elastomeric parts with production & CI batching chemical. Wear & tear and corrosion due to valve age (manufactured in 1982 & 1985). Worn out seal bore of BP-6 landing nipple. Short term solution such as reviewing the recommended hydraulic line opening pressure, downhole visual inspection, pressure activated sealant and caliper survey to confirm BP-6 Landing Nipple seal bore damage, Swellable Packer/O-ring (External) and re-dress using non-upgraded Elastomers (Internal) had been planned. Contingency for subsurface controlled SSV and replacement using new WRSCSSV had been put in place as long-term solution. This paper describes operator experience in managing the challenges in maintaining SCSSV operability, diagnostic and solution recommended to avoid production deferment due to this issue.