PETRONAS Baronia field is a mature oil field with over 45 years of production history, located offshore Sarawak, Malaysia. It consists of several vertically stacked clastic sandstone reservoirs, namely two major reservoirs: S and V2 reservoirs. Both reservoirs have been on production since 1970's with the production strategy evolving over the years to maximize recovery. Natural depletion, infill drilling, water and gas injection, and recently Immiscible Water-Alternating-Gas (IWAG) IOR/EOR strategies have been implemented. All these elements combined with the subsurface uncertainties pose challenges to history match and to conduct probabilistic forecast studies on the dynamic models. Conventionally, the development scenarios for subsurface investigation are limited due to finite computing resources. As PETRONAS is shifting its portfolios to develop more complex and challenging fields, the need for transformation in development concept evaluation is evident. This is key for proper risk and uncertainties quantification. The notable challenges are a) limited number of development scenarios being investigated, evaluated, and compared; b) limited software licenses and infrastructure availability; c) lack of data and decisions traceability. These limitations are addressed by the PETRONAS LiveFDP digital transformation initiative commenced in 2019, through deployment of digital cloud technologies and solutions with scalable High- Performance Computing (HPC) environment. The cloud-based native and Petrotechnical applications enable remote work, ensure full data traceability and auditability, enable multi-realization ensemble analysis, and streamline the automated integration from the reservoir engineering ensemble workflow to economic analysis. Unlimited cloud computing power and licenses facilitate a broader spectrum of reservoir simulation cases to be investigated in a fast-tracked manner. The cloud HPC infrastructure has shortened the history matching cycle from 3 months to 1.5 months. The team has also observed over 5 times speed enhancement on simulation run performance using cloud computing compared to virtual machine and on-premise infrastructure. Utilizing the cloud solutions and ensemble probabilistic approach, the team has achieved over 90% of history match quality through 300 realizations per ensemble running concurrently and completed within 2 hours. The optimized IWAG injection resulted in 2% (~1MMStb) higher oil reserves with 37% less gas injection and 40% shorter injection cycles. This has improved gas sales and prioritization in the field while also monetizing the oil reserves. The ensemble analyses are then visualized using cloud-based data analytics system whereby key realizations and uncertainty parameters are further reviewed and highlighted across various disciplines collaboratively at real time.

PNPR cluster consists of three fields, namely PX, NX and PR (combined STOIIP ~200 MMstb), located ~300 km offshore of Peninsular Malaysia. Throughout its journey of monetizing marginal waxy crude, many challenges and hurdles have arisen, including sustaining oil production rate above economic threshold, pipeline clogging, and FPSO fuel uncertainties, which requires collaboration between surface and subsurface team to develop unique solutions in managing these downturns. Critically, PNPR cluster is expected to reach economic limit within few years’ time. This paper will elaborate on how IOR is achieved in PNPR cluster, historically and in near future. Ever since first production by PX and NX in 2004, infill drilling campaigns have been needed to sustain production above the economic limit of 5,000 bopd. Later in 2009, approximately a year after PR kicked off its first oil; the14 km pipeline to FPSO was plugged due to wax accumulation as a result of prolonged shutdown. A pipeline restoration project was embarked on involving installation of pipe in pipe (PiP), which utilizes hot water circulation as pipeline heating element. Another complexity has been consistently supplying gas to the FPSO for fuel, which involves a cement packer and adding perforation jobs in gas wells. Additionally, the waxy crude in these fields requires gas lift to be produced, particularly after water production started to escalate. This gives an opportunity to introduce through tubing electrical submersible pump (TTESP) to the field, while reducing dependence on gas lift. Financial wise, cost optimization initiatives are necessary to maintain the operability of the fields. To date, five infill projects have been successfully completed, contributing to IOR by bouncing back PNPR oil production rate. Additionally, a gas cap blow down (GCBD) from NX J80 reservoir also managed to improve reservoir recovery factor (RF) while supplying additional gas for fuel. Meanwhile, the PiP system, an enabler for IOR, has successfully ensures smooth crude oil delivery above pour point temperature from PR Platform to FPSO. In terms of gas fuel supply forecast, proper gas wells production phasing is planned to secure steady supply until 2023. IOR through artificial lift, TTESP is planned to be executed soon in one idle production well with potential gain of 500 bopd, hence eliminating option to workover the well, which is costly. Viewing IOR from economic standpoint, operating expenditure (OPEX) reduction through new philosophies were implemented, including reduction of FPSO charting rate, proactive maintenance and low-cost chemical bull heading, resulting in better cash flow for PNPR. It is expected that existing PNPR wells can recover 2 MMstb of oil through extension of economic life via incoming infill drilling in 2021, translating into 1-2% increase from current RF. Moreover, PX and NX already produced ~80% more reserves than originally booked in the first FDP.

Originally, an infill well from project H was approved in 2013 to be completed as a single zone Open Hole Gravel Pack (OHGP) to produce gas commingled from three sands located at the shallowest reservoir in that field. Interpretation of recent logs from a nearby producing well indicated that there was significant water threat at two of the sands which would lead to water influx from the beginning of production if the well was to be completed as a single zone OHGP. The well was then redesigned to be completed as a Cased Hole Gravel Pack (CHGP) in order to have mechanical isolation from the water zones with an inner string and internal isolation packers to allow feasibility of zonal isolation to shut off the water producing zone in the future. This feature however resulted in higher well cost as compared to the approved design. Due to recent hostile low oil price, a more cost-effective sand control design was evaluated to reduce the well cost while maintaining similar performances as a CHGP design in terms of the capability to delay water breakthrough. Design feasibility study was performed on multizone OHGP with open hole mechanical packer and an inner string design to evaluate its performance and magnitude of cost reduction relative to a CHGP design. Skin analysis was performed for both OHGP and CHGP completion designs to evaluate any additional pressure loss for each sand. Prior to compartment optimization, an OHGP completion without packer placement was simulated in a dynamic simulation to generate the production profile as a base case. This was followed by a compartment optimization that was performed with OH mechanical packer placement at various standoff distances from the Gas-Water Contact (GWC) such as 5ft, 10ft, 15ft, 20ft and 30ft respectively. Subsequently, similar analysis was then performed on the CHGP completion design with a higher skin value estimated for the CHGP completion to reflect a higher degree of damage resulting from the cementing and perforation operations. Several production sensitivities were simulated by varying the perforation length and standoff from the GWC to replicate the same scenario of the open hole mechanical packer placement in the OHGP design analysis. Finally, analysis on the effectiveness of the base case (OHGP with no packer) against the cases of OHGP with optimum packer placement and CHGP with optimum perforation depth were compared and ranked over cumulative gas production, cumulative water production, operational complexity, and risk as well as total well cost. Based on the dynamic modelling, the base case (OHGP without packer) showed water breakthrough occurring right at the start of production as expected. Once breakthrough occured, water production would rapidly dominate production. On the other hand, packer placement sensitivity analysis for the OHGP design showed that the optimum depth for packer placement was 20ft or 30ft above the GWC depth where it provided highest gas cumulative and lowest water cumulative production throughout the well life. With offset distance of at least 20ft away from the GWC, the cumulative gas production for the OHGP and the CHGP cases were found to be similar and the cumulative water production for the OHGP case was slightly lower than the CHGP case. Mechanical open hole packer was recommended instead of swell packer after considering the risk of inadequate isolation by swellable packer that would lead to early water breakthrough which would subsequently reduce the cumulative gas production. As a result, an OHGP with open hole mechanical packer and inner string was selected to be the most optimum design for this well with estimated cost reduction of nearly 13% from a CHGP design. In general, an OHGP with OH mechanical packer at 20ft or 30ft standoff from the GWC brought benefit to the infill well in terms of cumulative gas production gain and low water production while eliminating sand production.