The company has extensive experience in holistic sand control and solid management for shallow water environment. Application to near-future marginal deepwater project called L-B cluster requires higher considerations on subsea umbilical, risers, and flowlines (SURF) integrity and long term well performance due to the high-cost environment. Representative field samples (e.g., cores, drill stem test (DST data) to study rock mechanics is scarce with limited in-situ stresses calibration information. This paper presents the workflow undertaken by team to de-risk and establish the downhole sand control design for both oil producer (OP) and water injector (WI) covering design, installation, and production operations philosophy. The workflow started with an extensive multidisciplinary analogue field study covering regional geological study on sand correlation to determine correct reservoir analogue as well as the deepwater fields sand control best practices and lesson learnt. Since the analogue field already have production, the study was extended to cover the production impairment impact trend and the implementation approach to derisk the field attainability target. Based on geological and geomechanical understanding, L-B regional deepwater formation characteristics with interbedded sand and shale formation does not suit certain types of sand completion methodology, as it introduces additional risk: Deformation of expandable sand screen due to the different expansion rate of sand and shale during depletion, creating weak points in which sand is mobilized into the screen tears resulted from deformation Uneven proppant placement in cased hole frac pack for OP Loss of active sand control for a cased hole frac pack and open hole gravel pack in WI due to proppant flushed away which can be further exacerbated by uneven placement This resulted in the following lower completion strategy: Open Hole Gravel Pack (OHGP) for OP and Open Hole Stand Alone Screen (OHSAS) for WI Allowance for backflushing in WI to remove screen plugging while managing risk of reverse flow impact Sufficient rathole and long horizontal well completion as dampener to minimize magnitude of water hammer/adverse reverse flow impact in WI. For detail design, team devised comprehensive laboratory analyses covering Particle Size Distribution (PSD) and Sand Retention Test (SRT) inclusive of geomechanics modeling work for screen sizing and estimation of fines production through screens. Result is then used to devise method to minimize and manage fines production in SURF and topside. The holistic approach of sand control workflow is compulsory for marginal deepwater development, since the environment is less forgiving during production due to the massive cost of well intervention/troubleshooting and production associated issues; flow assurance and facilities turn-down limit, therefore downhole sand control and operation should be robust enough to cater throughout the life of the field.

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Bayan (BY) is a brown field located in Sarawak region with over 25 years of production. Declining trend in field production resulting from rapidly declining reservoir pressure and increasing water production has prompted aggressive production enhancement activities to arrest further decline. Conventional gas lift method has been widely applied across the field and has provided reliable means of artificial lift to sustain production. However, wells with very low reservoir pressure were not able to sustain production even with gas lift due to the back pressure experienced in the production system. Low Pressure System (LPS) were implemented in two (2) out of four (4) drilling platforms in BY to sustain and increase the field production, reactivate idle wells and to manage the back pressure for the whole production system. Experience gathered from this implementation enable us to improve the candidate selection process and to share potential limitation imposed by the LPS system to operation. Actual BY LPS performance is shown here to illustrate the proven success in increasing the field production and unlocking some of BY reserves. The change in the production trend of well's producing in current production system and after being tied to LPS will show the total achieved production gain which in BY case amounted to more than 1.5 million barrels in 4 years of operation.

L-B is a clustered deepwater development comprising two greenfields currently approaching execution stage. The development concept is subsea umbilical, risers and flowlines (SURF) with dedicated Floating Production Storage and Offloading (FPSO) in L field and a long subsea tieback (20km) for B field. Due to this, production assurance is a major risk particularly for B field during production. To enable a holistic simulation of the production and injection system, an integrated network model (INM) is developed. This paper presents the systematic and integrated approach in developing the INM for L-B cluster, the calibration processes, and the resulting field modifications undertaken as an outcome of the model. The INM comprises dynamic reservoir model, well model and network model coupled using an integrator software. Robustness of each standalone model were assured through stringent construction and reviews by respective disciplines. Multiple collaborative forums participated by cross-function members were held to integrate the models. Next, a custom algorithm and method were developed to address specific field controls such as staggered voidage replacement ratio and skin growth over time. Once the models were compatible, multiple scenarios identified from Concept Identification Workshop were evaluated with INM. The results were then integrated into fiscal evaluations and ultimately facilitated decision-making for L-B project. Thorough utilization of the completed INM models generated vital data for future cluster production forecast of L and B fields: The in-situ FPSO operating pressure was accurately simulated using INM resulting in a dynamically responsive production profile, instead of sole dependence on reservoir model which uses a static pressure set up. INM was also used to identify and mitigate potential bottleneck along production system. Preliminary artificial lift options of Electrical Submersible Pump (ESP), Downhole Gaslift (DHG), Subsea Multiphase Pump (MPP) and Riser based Gaslift (RBGL) were analyzed and selectively narrowed down using INM. Outcomes of the analysis were favorable to MPP and RBGL which were then incorporated in the Concept Select scenarios. Ten scenarios with permutations on recovery method, onset of pressure booster installation, and artificial lift requirement were analyzed and decisively selected using results from INM. Study of new technology such as subsea separator was also concluded to be inapplicable in the field via INM evaluation. Finalized temperature modeling was used to cater for flow assurance constraints such as minimum Flowing Tubing Head Temperature (FTHT) requirement and generated inflow information to be incorporated into specialized Flow Assurance (FA) software. This paper will highlight the benefits of a comprehensive integrated network model covering end-to-end operations to mitigate flow assurance risk prior to field start-up. This model will also be readily utilized during the crucial production stage for calibration with actual field data to generate reliable prediction. The long-term application of INM will give greater assurance of production attainability in the L-B clustered development.