The current state of oil and gas economics has emphasized focus in managing and optimizing production from mature fields. It is estimated that approximately 70% of the world's oil and gas production are contributed by mature fields. Sand production is common as pressure declines and water breakthrough takes place. Clastic reservoirs with unconsolidated formation sand with moderate and high permeability are prone to produce sand under these conditions. In gas producing environments, conventional sand control can place demands for continued expensive remediation investment through the wells producing life as high gas velocity increases the chances of erosion and failure of downhole equipment. Gas reservoirs have always been an integral part Malaysia's oil and gas business. As the well the portfolio expands to cater for the regional energy demand, focus on fit for purpose sand control in gas wells is crucial in ensuring continuous production delivery to customers. As a current practice, sand production has been handled by standalone metal screens or combined with gravel packing. One of the cheaper options available in the market is the ceramic sand screen that allows for rigless installation while providing durable material which is resistant to erosion caused by high gas velocity for a continuous production as the ceramic material is 10 times harder than steel (Jackson et al., 2015) and it is more resistant to corrosion in comparison to steel (Wheeler et al., 2014). This paper will focus on the revival strategy of a gas well with a currently damaged screen due to erosion. As this is the first through tubing ceramic sand screen deployment in a gas well in Malaysia, a feasibility process was put place to ensure safe operation and deployment success. Depending on the current well completion profiles, the assessment includes selection of sand screen specification, actual installation sequence, methodology in ensuring safe and successful deployment of ceramic sand screen downhole are focused. The study and assessment has provided future reference for superior downhole sand control options in gas well applications.

PETRONAS completed Well H16 in BS field, East Malaysia with a Digital Intelligent Artificial Lift (DIAL) – an improvement to the current applied gas lift system in the field for production optimization system. This DIAL installation represents the first ever successful installation of the technology in an Offshore oil well for Dual String production. This paper provides the details of the installation planning, designing stages, operational process, well unloading and production undertaken to achieve this milestone. DIAL is a unique technology that enhances the efficiency of gas lift production. 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 which will be challenging in high deviation well (more than 60-degree deviation). With remotely operated, non-pressure dependent multi-valve units, the technology removes the challenges normally associated with gas-injected production operation in a dual completion well i.e., gas robbing and multi-pointing. DIAL 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 value added from the design stage, through installation operations, to production optimization. Digitization and automation have become the new concepts in managing the operations in order to boost efficiency that reflected in long-term cost savings especially in Operating Expenditure (OPEX). 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 strategy, installation process and production phases: system design, pre-job preparations, improvements implementation, run in hole and surface hook-up. The results of well unloading while utilizing the DIAL system to start up the well and lifting the completion brine will be explained in detail in this paper. For each phase, challenges encountered, and lessons learned will be listed together with observed benefits. Despite the additional operational & planning complications due to COVID-19 restrictions, the well was completed with zero Non-Productive Time (NPT) and Loss Time Injury (LTI). Once brought online, this DIAL-assisted production well can be remotely monitored and controlled ensuring continuous production optimization, part of PETRONAS’ upstream digitization strategic vision.

This paper serves to share the findings and best practices of sustaining production for a mature field with high sand production with analysis from Acoustic Sand Monitoring (ASM) paired with Online Sand Sampling (OSS). Field B, located in the East Malaysia Region, is a high oil producer for over 40 years under a strong water drive mechanism. Water production has significantly increased over the past 5 years, which has led to significant sand production impacting surface facilities and well integrity. Hence, the need for a reliable and efficient sand management surveillance in field B. As the first application for oil fields in the region, ASM and OSS was conducted with the objective to determine the maximum sand free production rate from over 80 active strings in Field B over the span of 4 months to safeguard production rates of 10 kbopd. With ASM and OSS, a reduced data surveillance duration can be achieved within 2 hours compared to conventional well sand sampling per well which requires a minimum of 24 hours before sand production rate is determined. ASM sensors are clamped on the well flowline to detect and record the noise vibrations produced by the sand while OSS is conducted concurrently by diverting parts of the same flow from the flowline through a sand filter to have a quantitative representation of sand produced for a predetermined duration. During the campaign, choke sizing was manipulated to control reservoir drawdown. For most wells, a lower drawdown resulted in lower amplitude readings from ASM and less sand observed from OSS. However, there are several wells that had higher sand production at a smaller drawdown due to a change in flow regime (steady flow to intermittent flow) resulted from inefficient gas lift production (multi-pointing). As ASM provided the raw velocity signal which is heavily influenced by the liquid flow regime, gas oil ratio and sand production, OSS results (from physical sand produced and weight of sand particles) established a baseline for ASM signals which indicate a sand free production. Overall, ASM and OSS analysis provided a baseline for determining the optimum rate of production with minimum sand to avoid well integrity issues and protecting the surface facilities, thus allowing continuous field production of 10 kbopd. A presentation and discussion of the successful results, limitations, best practices, and lessons learnt of the ASM and OSS campaign aspires to be additive to the production surveillance sand management in the oil and gas industry by providing a fast and reliable means of identifying optimum sand free production rates for a high number of wells in a mature field.

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.

Malaysian clastic reservoirs are plagued with high fines content which rapidly deteriorates the productivity from wells completed with conventional form of sand control techniques. To mitigate the fines production issue, Petronas recently successfully completed 3 reservoirs in two wells in Field-D using enhanced gravel pack technique. This paper explains in detail the workflow, challenges such as depleted reservoirs, coal streaks, and nearby water contacts and operational execution for the successful re-defined extension pack jobs. This new approach consists of a re-defined Extension Pack / Frac Pack job with fine movement control resin and a re-defined perforation strategy. Perforation strategy consists of limited number of 180 deg phasing non-oriented perforations done under dynamic underbalance conditions. The key requirement to have fracturing as a sand control method is to have a tip screen out (TSO) or high net pressure placement to ensure the fracture has good conductivity. To obtain a good TSO, data acquisition is of paramount importance. The fracturing jobs in the Field – D wells were preceded with step-rate tests, injection tests, minifrac and Diagnostic Fracture Injection Test (DFIT). The data from diagnostic tests were used diligently to have best possible fracturing treatment in the target zones. Excellent pack factors of greater than 500 lbs. per ft were obtained for all the treatment jobs using only linear gel with proppant concentration up to 7 ppa. This high pack factor translates to very good frac conductivity which is essential in fracturing for sand control. Some of the fracturing treatments concluded with a TSO signature which is a big achievement considering the challenges that were associated with fracturing in Field – D. In addition, DFIT and ACA (After Closure Analysis) was performed to estimate permeability and results were compared with various techniques such as log derived and formation tester permeability. Ultimate objective from this analysis is to have a work-flow which can screen candidate wells for such treatments from openhole logs and give an estimated liquid rate post treatment. Also, the workflow for planning and executing fracturing jobs will be presented for Malaysian clastic reservoirs. This work-flow will be vetted against the extensive diagnostic and fracturing data that has been acquired during fracturing treatments in Field – D. Design, actual diagnostic, and fracturing data will be presented in this paper. It is expected that this modified form of sand and fines control will help in reducing the fines issue in Field – D to a great extent along with expected incremental in oil production. If long term production sustainability is proven, similar approach will be adopted by Petronas and can be shared amongst other South East Asia operators in many similar other fields.