Field D is a mature offshore field located in East Malaysia. A geologically complex field having multiple-stacked reservoirs with lateral and vertical faulted compartments & uncertainty in reservoir connectivity posed a great challenge to improve recovery from the field. Severe pressure depletion below bubble point and unconstrained production from gas cap had contributed to premature shut-ins of more than 50% of strings. As of Dec 2019, the field has produced at a RF less than 20%. Initial wells design consisted of conventional dual strings & straddle packers with sliding sleeves (SSD). Field development team was challenged for a revamp on completion design to enhance economic life of the depleting field. In 2015, as part of Phase-1 development campaign, nine wells including four water injectors were completed initiating secondary recovery through water flood. An approach of Smart completion comprising of permanent downhole monitoring system (PDHMS) and hydraulic controlled downhole chokes or commonly known as flow control valve (FCV) was adopted in all the wells in order to optimize recovery from the field and step towards intervention-less solutions. Seeing the benefits of intelligent completion in Phase-1, Phase-2, drilled and completed in 2019 – 2020 has been equipped with new technology "All-electric Intelligent Completion System" in 4 out of 8 oil producers. The new design addresses the reservoir complexity, formation pressure and production challenges and substantial cost optimization, phasing out the load of high OPEX to CAPEX. Installation of "All-electric Intelligent Completion System" has proven to be an efficient system compared to hydraulic smart completions system. It requires 50% to 75% less installation time per zone and downhole FCV shifting time is less than five minutes compared to several hours full cycle for hydraulic system. The new system has capability to complete up to 27 zones per well with single cable. It gave more options and flexibility in order to selectively complete more zones compared to hydraulic FCVs which requires individual control line for each zone. Future behind casing opportunities (BCO) have been addressed upfront, saving millions of future investment on rig-less intervention. In addition to that, non-associated gas (NAG) zones have been completed to initiate in-situ gaslift as and when required avoiding the dependency on aging gaslift facility. The scope of the paper is to show case the well design evolution during Field D development and highlight on how smart completion has evolved from original dual completion to hydraulic smart and recently to electric smart system, how it has contributed to cost and production optimization during installation and production life and also support the gradual digitalization of the Field D. In the end it demonstrates the optimized completion design to enhance the overall economic life of the depleting field.

Field D (offshore Sarawak, Malaysia) first production was in 2012 from three wells, with a second phase of development in 2017 with the drilling of four wells. Severe productivity decline was seen in five of the seven wells, and numerous studies were completed to narrow in on the root causes. Several production enhancement techniques were executed on Phase 1 and Phase 2 wells, where learnings and results will be further shared. Prior to the drilling of six additional wells in Phase 3 (2020), additional detailed lab studies were undertaken, and new strategies were implemeted based on this were applied with encouraging results. The majority of the wells have downhole pressure gauges (PDG), and coupled with frequent well test data, PTA, and Nodal Analysis modeling Productivity Index, permeability thickness (kH), and Skin are able to be tracked over time. By trending these different productivity indicators, it became clear that formation damage was occurring in several wells with varying degrees of severity based on the performance of the reservoir layer being produced. Various formation damage mechanisms were assessed (scale, wax, asphaltenes, drilling & completion damage, fines migration), and based on the initial study it was determined that fines migration was likely the major issue. Historically, no sand was observed on the surface where monthly sand count reported has always been <1 pound per thousand bbl (pptb) which was supported by geomechanics, and sand failure tendency studies completed during development phase of the field. Hence, six of the seven Phase 1 and 2 wells were completed with cased and perforated strategy with no downhole sand control, with the other well completed as a highly deviated open hole standalone completion. The productivity declines were only experienced in the cased and perforated completions, which had much lower gross completed interval and thus experienced higher velocities near the wellbore. The main production enhancement strategy applied to date has been re-perforation (8 re-perforation jobs), with varying degrees of productivity improvement and duration of sustainability. Solid propellant technology was applied in one of the well and clearing of the perforation tunnels via through-tubing dynamic underbalance technique in two wells was applied and no major improvement in sustained production impact was observed. An acid stimulation was recently pumped for the first time in one well and the assessment details will be shared, and results of the pumping will be shared in detail. At the time of the paper, no post production results were available. Prior to the drilling of six Phase 3 wells in 2020, detailed lab studies to look at the impact of various drilling muds were assessed, and learnings were incorporated in the mud program. Critical velocity studies were completed, and learnings from this work such as well ramp-up strategy and normalized maximum production rates have been added to the well-by-well production strategy. Based on Phase 3 production data to date, application of these new learnings has resulted in no major productivity decline seen. The learnings from D field would benefit other operators by sharing the lessons learned on assessment of formation damage mechanisms, the results of the different type of production enhancements applied, and the successful mitigation strategies for future wells (lab assessment, mud strategy change, and production strategies to prevent plugging due to fines migration).

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This paper discusses the integrated approach for investigating the declining production rates in an offshore Basin located in Western Balingian province, Malaysia. Four infill wells drilled in 2017 have suffered formation damage that has severely limited production rates. Re-perforation and stimulation attempts have resulted in some improvement, but the problem of declining production rates persisted. The work was conducted in two phases. Phase-1 focussed on understanding the damage mechanisms associated with existing wells. Testing the existing Reservoir Drill-In Fluid (RDIF) with static Permeability Plugging Apparatus (PPA) and dynamic Wellbore Conditioning Test (WCT) with reservoir core plug samples allowed for a base case result. The RDIF, and more specifically bridging package, was then optimised via static and dynamic testing to include sized calcium carbonate with reduced barite loading to reduce filter cake invasion. During dynamic testing, it was apparent that critical velocity or kaolinite fines migration was another contributing factor to the formation damage. It was proposed at the end of this phase that critical velocity testing be conducted to further understand and target the problem. As all previous reservoir core plug material had been exhausted or were unsuitable for testing, it was recommended that freshly cut cores be used in the next phase of testing. Furthermore, if the core material was of initial, non-produced state without the influence of production fluid flow on the reservoir matrix, it would allow for significant information to investigate the declining production rates as well as increasing well productivity. The ensuing six well drilling campaign utilised the optimised RDIF from Phase-1. One well drilled with the optimised fluid acquired 27 Rotary Side-Wall Cores (RSWC) with no flowback production conducted on the well, ensuring that core plugs were in a virgin state post drilling. Scanning electron microscopy (SEM) of freshly cut RSWC plugs confirmed the RDIF used having minimal filter cake invasion in the new wells. This result was in-line with the results from the laboratory, providing a benchmark for the fluid system in the field. Phase-2 of the study utilised the RSWC plugs in investigating critical velocity rates of different reservoir sections within the offshore field. Testing involved scaled down-hole production rates with reservoir-matched production fluid viscosity and monitoring differential pressure across a core plug. Critical velocity events were confirmed in the laboratory testing and the results were upscaled for individual reservoir units in the field. Well unloading rates were applied in the field and significant improvement in well productivity was observed. This paper ultimately highlights the importance of exploring the integrated "results matter" approach to analyse the contributing damage mechanisms and discovering solutions for well productivity.

Diagnosing and resolving unknown well obstructions at high deviations presents significant challenges to Operators. Combining a downhole camera with an electric line (e-line) tractor enables operators to traverse high angles and view the camera feed in real time, options unavailable on conventional Coiled Tubing (CT) unless running expensive smart CT. Furthermore, with e-line already on site, the operator maintains the flexibility to rig up an e-line milling tool to mill the obstruction. This paper describes how e-line tools helped identify the obstruction in a shut-in well and successfully milled the EGF ceramic flapper for the first time. Earlier this year, in a gas field offshore East Malaysia, an Operator needed to investigate probable sand intrusion from an open-hole gravel pack prior to design a remedial plan to reactivate the well. The well presented several challenges, such as high angles, unknown restrictions, restrictions within the inner diameter (ID), potential sand production, and uncertain flapper valves condition in the well. The Operator opted for an e-line tractor to convey a downhole camera to identify the obstructions and an e-line milling tool as a contingency to mill obstructions or faulty valves. This operation was completed in six runs and comprised of the e-line tractor conveying the downhole camera for drifting or visually inspecting the completion until successfully logging down to the targeted intervals. During the first two runs, the tractor conveyed the camera through the lateral and found a fluid-loss control EGF flapper partially open but could not pass through because of the restricted ID. In the third run, the tractor worked on the string and tagged the flapper, attempting to close it. The next camera run showed in real time that the flapper valve had been closed. The milling tool was then run in hole (RIH) to mill the flapper on the fourth run. On the fifth run, the tractor and camera confirmed that the valve had been milled successfully and the toolstring could pass through the ID. Finally, the tractor conveyed the logging tool to the target intervals and pulled out with no overpull observed. Running this operation entirely on e-line enabled the Operator to access the well obstructions despite the high angles, view the camera feed in real time, and mill the EGF ceramic flapper valve. This case shows the effectiveness of e-line operations to succeed in challenging well environments without the cost, risk, or time needed for traditional methods like CT or rigging units. The e-line tractor conveyed the camera at high angles to successfully identify the obstruction, and the e-line milling tool milled the EGF ceramic flapper to restore access to the horizontal section. The Operator completed the logging job, which was essential for future well rectification plans that also included setting plugs for zonal isolation.