No abstract

This paper describes a step change by well completion group in adopting Single Trip Liner Open Hole Completion (STRIP-LOC) technology, basis of selection, design, and operation approach. This has contributed to the reduction in initial well cost estimates thus benefited overall project cost. The technology adoption signifies the importance for continuous design improvement, operational optimization, and capital expenditure reduction, while not compromising with technical and HSE standards.

Straits of Malacca Exploration Campaign marks PETRONAS' first oil/gas well drilling in the region of West Coast of Peninsular Malaysia. Three (3) exploration wells were drilled in a period of four (4) months. This paper will highlight the challenges, lessons learnt and key to success of this fast track drilling campaign in a new region of operation.The team which was entrusted with the mission to drive PETRONAS' quest of oil and gas in this new region were then given six (6) months to deliver the first well out of three (3) exploration wells. Apart from the uphill task to set up staging base and logistics support in the West Coast of Peninsular Malaysia, the team faced challenges of drilling in one of the world's busiest shipping lane. Navigational safety is one of the main concern here. Besides, two (2) of the three (3) wells were located close area where sea robberies and hijacking were rampant. In terms of drilling operation, two (2) of the wells were exposed to the risk of total losses. This paper will share the approaches taken by the project team in overcoming challenges in three (3) main areas -(1) logistics; (2) navigational and offshore safety and security; and (3) well engineering.Although faced with numerous challenges together with limitation of time and resources, the project team has managed to deliver all the three (3) wells successfully, meeting all the geological objectives within Authorisation For Expenditure (AFE) cost. On top of that, the drilling campaign was completed with zero Lost Time Incident (LTI) and zero accident. Another notable success in this project is setting up the modus operandi in a new region of drilling within six (6) months. Due to the fast track nature of this campaign, first of the three (3) wells was spudded concurrently with 3D seismic interpretation by taking the risk of relying on 2D seismic data. Halfway through the well construction, Well #1 (Well A) was re-sanctioned based on the findings while drilling and latest 3D seismic data received. Target depth of the well was revised to 3130m TVDSS from initial 2100m TVDSS. Despite all the challenges, the drilling team managed to complete drilling operation of three (3) wells ahead of time by 11 days in total.Apart from engineering and logistics challenges, this paper will share the experience of drilling in one of the busiest shipping lanes in the world. Lessons learnt and key success factors of this fast track exploration drilling campaign will be beneficial to all oil and gas (O&G) operators, especially to those planning to operate in the Straits of Malacca or any other similar regions in the world.

An approach to establish an effective HSE culture on a previously inactive jack-up rig contracted for a one well drilling program proved successful in achieving the campaign HSE targets. The challenges were remote location, crews were unfamiliar with each other much less with the service company's personnel and unfamiliarity with the rig equipment. In addition, the operator's shore based team did not have previous experience in Crew Resource Management (CRM) approach. A CRM approach in tandem with an iterative job planning and execution strategy based on Deming's Plan-Do-Check-Act (PDCA) cycle was utilized. Personnel with extensive hands on experience in this aspect were mobilized to the rig to provide coaching on board covering all personnel. Coach's observations were shared daily with head office and performance metrics were monitored to gauge performance to identify area of focus for coaching. A weekly debrief with the shore based management team on progress was also carried out. The effectiveness of this approach was assessed with previously employed CRM used on working rigs on long term contracts as well as rigs on a one well contract. The coaching commenced after the rig was already in operations and the change in HSE culture could be compared to the culture after CRM approach was implemented. Results showed that the approach used in this campaign resulted in significant improvement in the performance metrics that were monitored. In addition, in a matter of six weeks, significant improvements were observed on non-technical skills as a leading indicator. Participation by all on board the rig with strong support from shore based and head office management of the operator and drilling contractor were key to the success of the program

Based on the production data from first development campaign in 2017, contamination reading of CO2 and H2S from gas production wells were observed increasing from 3% to 10% and from 3ppm to 16ppm respectively within one year production. These findings have triggered the revisit in 2019 development campaign optimization strategy in terms of material selection, number of wells, reservoir targets, and completion design. Thus, tubing material was upgraded to HP1-13CR for the upper part of tubing up to 10,000 ft-MDDF (feet measure depth drilling rig floor) to avoid SSC risk due to the geostatic undisturbed temperature is less than 80 deg C, however the material of deeper tubing remains as 13CR-L80 as per 2017 campaign. Moreover, the mercury content from first campaign was observed to be above threshold limit from intermediate reservoir based on mercury mapping exercise done in August 2018.As the mercury removal system is not incorporated in the surface facilities, the mercury reading from the well in the 2019 campaign need a close monitoring during well testing so that appropriate action can be taken in case the recorded contaminant reading is high. Dedicated zonal sampling plan to be performed if the commingle zone (total) mercury reading was recorded to be above the threshold limit, and that zones will be shut off to preserve the surface facilities. Opportunity was grabbed to optimize number of wells by completing both shallow and intermediate sections in a single selective completion to maximize the project value. However, this combination will lead to major challenges during operation due to the huge difference in reservoir pressure and permeability contrast in each perforated reservoir as the required overbalanced pressure of completion brine for shallow reservoir is much lesser than the requirement for the mildly overpressure intermediate reservoir. Thus, a potential risk of severe losses and well control is present at shallow reservoir. To mitigate this risk, loss circulation material was pre-spotted in the TCP (Tubing conveyed perforation) BHA prior to fire the gun to allow for self-curing process should losses take place. During the first development campaign, the completion tubing was running in hole in two stages. The lower completion was deployed via drill pipe and the perforated zones was secured with fluid loss device located between lower completion tubing and gravel pack packer. The upper completion tubing was then deployed and tied back to the lower completion packer. This approach was applied as mitigation to prevent fluid losses and to ensure the tubing can be safely deployed to the intended final depth. However, based on the actual performance and losses rate data during the first campaign, the completion design in second campaign was optimized and deployed in single stage. Since shallow and intermediate reservoir were combined in multiple production zones where five SSD (Sliding Side Door) were installed, the slickline option to set packer was waived due to the risk of setting tubing plug in deep wells. Pump out plug was considered as an option but then dropped due to high hydrostatic pressure. The packer setting pressure was too close to plug shear pressure. Therefore, a self-disappearing plug was utilized as it did not require any slickline intervention and can be ruptured by pressure cycle. With this option, risk of pre-mature rupture of plug was eliminated. The paper will discuss in detail each challenge mentioned above together with details calculation that was performed throughout evaluation and selection processes prior best solution being selected as these optimizations resulted in nearly three days saving of rig time, contributing to 2.6% of well cost reduction and the required number of wells were optimized to be three instead of four wells. Moreover, a safer production life of wells by selecting a suitable tubing material and eliminating the risk of mercury production above the above threshold limit.