Field A is a mature hydrocarbon-producing field located in eastern Malaysia that began producing in 1968. Comprised of multistacked reservoirs at heights ranging from 4,000 to 8,000 ft, they are predominantly unconsolidated, requiring sand exclusion from the start. Most wells in this field were completed using internal gravel packing (IGP) of the main reservoir, and particularly in shallower reservoirs. With these shallower reservoirs continuously targeted as good potential candidates, identifying a sustainable sand control solution is essential. Conventional sand control methods, namely IGP, are normally a primary choice for completion; however, this method can be costly, which requires justification during challenging economic times. To combat these challenges, a sand consolidation system using resin was selected as a primary completion method, opposed to a conventional IGP system. Chemical sand consolidation treatments provide in situ sand influx control by treating the incompetent formation around the wellbore itself. The initial plan was to perform sand consolidation followed by a screenless fracturing treatment; however, upon drilling the targeted zone and observing its proximity to a water zone, fracturing was stopped. With three of eight zones in this well requiring sand control, a pinpoint solution was delivered in stages by means of a pump through with a packer system [retrievable test treat squeeze (RTTS)] at the highest possible accuracy, thus ensuring treatment placement efficiency. The zones were also distanced from one another, requiring zonal isolation (i.e., mechanical isolation, such as bridge plugs, was not an option) as treatments were deployed. While there was a major challenge in terms of mobilization planning to complete this well during the peak of a movement control order (MCO) in Malaysia, optimal operations lead to a long-term sand control solution. Well unloading and test results upon well completion provided excellent results, highlighting good production rates with zero sand production. The groundwork processes of candidate identification down to the execution of sand consolidation and temporary isolation between zones are discussed. Technology is compared in terms of resin fluid system types. Laboratory testing on the core samples illustrates how the chemical consolidation process physically manifests. This is used to substantiate the field designs, execution plan, initial results, follow-up, lessons learned, and best practices used to maximize the life of a sand-free producer well. This success story illustrates potential opportunity in using sand consolidation as a primary method in the future.

The B Field is located in the South China Sea, about 45 KM offshore Sarawak, Malaysia, in a water depth approximately 230 ft. Its structure is generally regarded as a gentle rollover anticline with collapsed crest resulting from growth faulting. The reservoirs were deposited in a coastal to shallow marine with some channels observed. Multiple stacked reservoirs consist of a series of very thick stacked alternating sandstone and minor shale layers with differing reservoir properties. The shallow zones are unconsolidated, and the wells were completed with internal gravel packs. Wells in B Field mostly were completed in multi-layered reservoirs as dual strings with SSDs and meant to produce as a commingled production. The well BX is located within B Field and designed as oil producer well with a conventional tubing jointedElectrical Submersible Pump (ESP) system which was installed back in 2008. Refer to figure 1, the initial completion schematic is 3-1/2″ single string that consist of the single production packer, gas lift mandrel, tubing retrievable Surface Controlled Subsurface Safety Valve (SCSSV) and ESP. The production packers equipped with the feed thru design to accommodate the ESP cable and the gas vent valve as part of the ESP completion design. The gas lift mandrel was installed in the completion string as a backup artificial lift method to receive the gas lift and orifice valve in the event of the conventional ESP failed. Hence the well still able to produce by introducing the gas thru the annulus to activate the gas lift valve. Eventually throughout the end of the the field life, the well would depend on the ESP system for the primary lifting method due to gas lift depth limitation and the gas supply. The conventional ESP failed after seven years of operation which is above the average ESP lifetime. The well last produced at a flow rate with 28 % water cut, however the well is not at the end of the field life. Based on the economical study with the right technology and cost efficient approach, the well still economicaly profitable. The Thru Tubing (TT) ESP technology is approached as cost effective solution compare to fully well workover. Despite a couple of operational challenges, for example, setting the cable hanger, maintaining downhole barrier requirement, the Thru Tubing Electrical Submersible Pump Cable Deployed (TTESP CD) and Cable Thru Insert Safety Valve (CT-ISV) was successfully installed. Several post-installation findings have uncovered some problems which are requiring some additional technical and operation improvement for future similar applications. This paper will highlight the deployment of the Cable Thru Insert Safety Valve (CT-ISV) that was successfully installed as pilot, which is the first application in the world, and also highlights the success, lesson learnt and improvement for future requirement for the CT-ISV application as one of the solution for retrofitting completion application without jeopardizing the well integrity. This achievement is collaboration between Company and service partner as the technology and deployment under the proprietary scope. Further technology application, the replication of this insert safety valve was conducted and successfully deployed on other three wells.

Smart Auto Gas Lift (AGL) refers to a downhole system that utilizes gas from a gas zone or a gas cap in a well to lift oil below or above the gas zone in the same well. This paper illustrates a novel AGL intelligent completion design approach including candidate screening, pre-drill feasibility study, sensitivity analysis, and followed by the completion installation and production operation practices for the first two (2) successfully completed AGL wells in Malaysia. In the candidate screening process, a novel design approach was used based on a 3D numeric single wellbore dynamic model forecasting method. Firstly, candidate screening was performed for the application suitability of AGL in the candidate reservoir. The key screening factor includes the identification of the source of AGL gas, either from the associated overlaying gas cap or independently from another layer of non-associated gas, estimation of gas pressure and oil pressure, estimation of volume of available AGL gas and longevity of gas reserve throughout oil production life, and considering the reservoir structure and drive mechanism. Secondly, single well prediction modelling analysis was performed to evaluate candidates' dynamic performance on production rate, water cut, gas oil ratio (GOR) profile and pressure depletion over time. This is to make sure designed AGL completion will meet expected various production dynamic responses during the entire life of well. The next step is to conduct production snapshot nodal analysis for the appropriate choke size design for AGL downhole flow control valve. Those dynamic results from the single wellbore prediction model becomes important input for nodal evaluation to simulate changing reservoir conditions at different stages. Finally, various sensitivity analyses on layer properties and valve setting depth are followed to ensure that the AGL valve choke sizing design range is flexible enough to cover expected reservoir uncertainties and to be effective over the entire well life. Based on above design and analysis approaches, a specified range of AGL valve choke opening were designed for T field candidate wells and smart AGL completion system was installed successfully and safely in two wells by end of 2014 without any health, safety and environmental (HSE) issue and AGL related non-productive time (NPT). The production and well test data were available for production performance surveillance, and the dual permanent downhole gauge system (measuring pressure and temperature in both the tubing and the annulus) at gas zone enabled the continuous auto gas injection monitoring at real time basis. This paper discusses AGL well design approaches, justifications, best practices and lessons learned regarding completion installation, well clean up and production operations to give a general guideline for AGL implementation in this area in the future.

PETRONAS completed well H-X on B field in Malaysia with a Digital Intelligent Artificial Lift (DIAL) gas lift production optimization system. This DIAL installation represents the first ever successful installation of the technology in an Offshore well for Dual String production. This paper provides complete details of the installation planning and operational process undertaken to achieve this milestone. DIAL is a unique technology that enhances the efficiency of gas lift production via downhole monitoring of production parameters informs remote surface-controlled adjustment of gas lift valves. This enables automation of production optimization removing the need for well intervention. This paper focusses on a well completed in November 2020, the fourth well to be installed with the DIAL technology across PETRONAS Assets. The authors will provide details of the well and the installation phases: system design, pre-job preparations, improvements implementation, run in hole and surface hook-up. For each phase, challenges encountered, and lessons learned will be listed together with observed benefits. The DIAL system introduces a paradigm shift in design, installation and operation of gas lifted wells. This paper will briefly highlight the justifications of this digital technology in comparison with conventional gas lift techniques. It will consider the value added from the design stage, through installation operations, to production optimization. This successful installation confirms the ability to implement the DIAL technology in a challenging dual string completion design to enable deeper injection while avoiding interventions on a well with a greater than 60-degree deviation. With remotely operated, non-pressure dependent multi-valve in-well gas lift units, the technology removes the challenges normally associated with gas-injected production operation in a dual completion well – gas robbing and multi-pointing. Despite the additional operational & planning complications due to COVID-19 restrictions, the well was completed with zero NPT and LTI. Once brought online, this DIAL-assisted production well will be remotely monitored and controlled ensuring continuous production optimization, part of PETRONAS' upstream digitization strategic vision.

Completing well in a carbonate formation is often a big challenge due to occurrence of severe losses in highly fractured limestone formations. In some cases, total losses might lead to prolonged operation time and/or well abandonment with attendant cost implications. Traditionally, Loss Circulation Materials (LCMs) are used to combat losses before completion operation commences. However, there have been limited success with this approach especially in this case where Karst was encountered.Originated under Managed Pressure Drilling (MPD) system, Pressurized Mud Cap Drilling (PMCD) with continuous seawater injection was introduced in XT Carbonate Oil Development Project. Due to the subnormal formation pressure, seawater was injected continuously down the annulus to maintain the hydrostatic pressure of the hole while ensuring that no formation fluid or gas entered the well bore. By injecting at a rate higher than the loss rate, an artificially induced surface pressure allows for wellbore monitoring while completion assemblies are being deployed.Prior to running in Lower Completion, a composite bridge plug was set at deepest possible location in production casing instead of the conventional Downhole Deployment Valve (DDV) resulting in the savings of about USD 1 Million. Some modifications were made on initial completion string whereby a sacrificial motor and a bit were included in Lower Completion string design. With the well in static mode, this modified lower completion string which consists of mud motor, drill bit and pre-drilled liner was used to drill out the bridge plug effortlessly. PMCD mode with continuous sea water injection was activated once the plug has been drilled out and while Lower Completion string was run to Total Depth (TD). After setting the Liner Hanger Packer and closing Fluid Isolation Valve, the well was back to static mode and ready for wellbore cleanup and upper completion runs.Five (5) high temperature wells have been designed employing the above technique which resulted in significant savings in rig time and cost as well as formation damage reduction and increased operating efficiency. This paper summarizes the practical experiences gained during the planning and deployment of lower completion string with perforated liners in a total losses condition with PMCD .