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Geoscientist Kerry Moreland was ExxonMobil's exploration manager for the Guyana/Suriname Basin from 2014 to 2018, when the energy giant confirmed multiple discoveries, including the world-class Liza-1 find, where for decades drillers hit mostly dry holes. After a stint as West Africa exploration manager and Africa geoscience manager for development and production, Moreland was promoted to her current position: vice president, Sub-Sahara Africa and Asia Pacific, exploration and new ventures, ExxonMobil Upstream Business Development Co. Today, Moreland manages ExxonMobil's oil and gas exploration acreage and evaluates new opportunities across the industry's two most important frontier energy landscapes--Asia Pacific and Africa, which are destined to see the highest growth in energy demand by 2050 as well as present the greatest challenges for managing energy supply in a dual energy environment. This week, Moreland discussed her company's current successes and future vision in one of a series of IPTC Insights interviews conducted by a moderator with thought leaders at the International Petroleum Technology Conference (IPTC) in Kuala Lumpur. Here, JPT reports the highlights of Moreland's interview. IPTC: In January 2020, ExxonMobil increased its estimated recoverable resource base in Guyana to more than 8 billion oil equivalent barrels and announced its 18th discovery in September 2020 at the Redtail-1 well on the Stabroek Block.

Abstract Objectives/Scope Field A is a brownfield that has been produced for 52 years under natural depletion via a total of 207 strings. The field comprises 7000 ft of reservoir section, multiple fault blocks and over 200 separate reservoir units has been produced to date. Despite the long period of production, the field recovery factor (RF) to date is only 29%. To improve the RF, a strategic assest value framing exercise was carried out to identify the additional subsurface opportunities i.e. infill well drilling, secondary recovery, late field life appraisal in underdeveloped fault blocks as well as adopting standardized low well concepts and the design one build many facility design concept to reduce cost and accelerate development. The main purpose of the exercise was to capture the overall opportunities for the field, outline the roadmap and phase out the project with suitable wells and facilities design to bring down the cost for project commerciality. Methods, Procedures, Process The integrated workflow of the exercise involved subsurface, drilling, facilities, operations and economist and took a total of 3 months to complete. The process started off with a RF benchmarking exercise utilizing a newly developed inhouse RF benchmarking tool to compare the current attained vs the attainable RF(EUR) and identify incremental reserves. The number of new wells required to develop the incremental reserves was estimated by analyzing EUR per well trends over time. This analysis indicated that on a campaign basis the current realistic average EUR per well is in the order of 0.7-1.0 MMstb per well. The preliminary well placements are guided by bubble maps of all reservoirs, in a top to bottom & block by block approach, to identify underdeveloped areas and combining these areas into stacks of reservoirs that can be combined and developed with simpler wells from existing or future facilities. The drilling team has designed a few simple trajectories to penetrate shallower to deeper reservoirs and proposed the drilling center within a radius of 2 km from the targets. This approach differs from the object-based approach where individual high EUR targets are chased with more complex wells drilled from a specific location during a platform campaign. Result, Observations, Conclusions Potential additional reserves and 6 new projects have been identified which would result in a field recovery factor increase of 11%, of which 2 projects are being accelerated to realize early first oil. Timelines for all the projects have been mapped out with the aim of completing all within the next 10 years. A dedicated project management team has been formed to support the project from the initial stage. Detail Full Field Review study will be conducted to mature all the opportunities up to development stage. The listed projects will follow the low cost well guideline established in the framing as well as fast track facility design concept. Novel/added value The strategic value framing exercise is a systematic approach that provide a total picture of the future opportunities to optimize field production/EUR and maximize commercial value of brownfield redevelopment.

Abstract As host authority for all hydrocarbon resources in Malaysia, Petroliam Nasional Berhad (PETRONAS) Malaysia Petroleum Management (MPM) has championed Asset Value Framing (AVF) since 2016 to facilitate identification of asset enhancing opportunities and to establish a roadmap for opportunity realization. This paper is the continuation of the previous paper (SPE-196486) which illustrated opportunity identification through AVF. In 2019, PETRONAS had embarked on benchmarking oil reservoirs for all Malaysian oil reservoirs which was used for the AVF process to improve economic recovery factor of an oil field and booking new contingent resources. This paper focuses on enhanced AVF approach to integrate subsurface, wells, surface and operations; coupled with recommended improvements to AVF process from lookback exercise, reservoir performance assessment, data analytic through reservoir benchmarking tool and assessment of analogue reservoirs. A case study will be shared from one of the largest oilfields in Sarawak wherein enhanced AVF approach was applied to unlock significant potential of which conventional techniques faced challenges in identifying opportunities. Field B consists of multi-layered depositional system with numerous fault-bounded accumulation areas. Benchmarking process was performed for each of reservoir units to estimate the potential recovery factor and degree of complexity. In reservoirs where current estimates of recovery factor were lower than the benchmark, these were screened to be considered for identification of new opportunities through AVF process. Additionally, benchmarking process was applied to evaluate optimal well spacing, need for secondary recovery and identification of potential challenges for future development planning. A paradigm shift was undertaken to AVF process itself whereby focused development plan was considered for the entire column of rock within every fault block - instead of chasing oil by reservoirs. This subsequently allowed an integrated approach to optimize well type and cost, infill and water injection well count, completion design and overall evacuation strategy. Application of reservoir benchmarking significantly improved the delivery of AVF process by identification of recovery gaps in the field and application of learnings from better performing reservoirs. This coupled with Enhanced AVF workflow approach of focused development plan has resulted a roadmap for Field B to achieve ultimate recovery factor of 40% through a number of potential development opportunities within the next few years. An enhanced AVF workflow coupled with benchmarking process has facilitated field potential evaluation within two months, leading to efficient decision making, resource accrual and value creation for all stakeholders. This workflow can be replicated to other fields, maximizing economic reserves, increasing asset value, and defining the development roadmap.

Abstract Based on the data of drilling rigs working in Malaysia from 2014 to 2020 as per shown below, it can be concluded that, historically the demand for rig in Malaysia is very dynamic and it was influenced by mainly the brent price albeit a delayed impact. The red line showed the Brent Price. With the dynamic of the demand, a systematic and well-organized methodology to develop an integrated rig sequence was essential. It is to ensure all rigs were planned accordingly and successfully acquire in time to ensure the projects can be executed as per expectation. A glimpse on the outcome of having an integrated planning between all the parties related such as host authority, project planners, procurement team, and rig planning team together with a right tool is essential to sequence and plan the projects and the drilling rigs requirement.

ABSTRACT Brownfield oil and gas (O&G) project defines as a project involving upgrading or rejuvenating existing facilities to cater to production enhancement, extend production profile, and install new equipment or tie-in with new greenfield platform. This abstract serves to share the replicable solution on brownfield project management for Commissioning and Start-up (CSU) strategy for Offshore Field Rejuvenation and Redevelopment Project. Field A and Field B are two fields in the Baram Delta Operation (BDO) in Malaysian Waters. Field A and B were first discovered and started its production in the early 1970s, putting the existing facilities’ current service life at an average of 40 years. Field B is within the Baram Delta in the South China Sea, about 40km from Miri, Sarawak. Field B plan for Brownfield Project is rejuvenation and redevelopment scopes to cater to the upcoming new installation of 3 wellhead platforms (WHPs) and one Central Processing Platform (CPP). The redevelopment project aim is to install new topside facilities to revive and upgrade platforms in Field B. The new facilities installed on the platform are new knock out drum, flare boom, Diesel Engine Generator (DEG), Gas Engine Generator (GEG), Diesel Tank, Sump Tank, HP Flare Knock up Drum Pump, and Instrument Air Package. This project is also part of the Enhanced Oil Recovery (EOR) project to increase overall Field A & B production from 60kbpd to 120kbpd total liquids.

Abstract COMPANY-A is the operator of Field-A gas field that started operation in Country-A in 1996. Reliable and smooth condensate handling is key to ensure the continuous gas production and hence, maintaining the gas supply assurance. To cater for the reduced condensate throughput and export, COMPANY-A hired Company-B to refurbish a Floating Storage and Offloading vessel (FSO) named FSO-B; a new player and has minimum experience in oil and gas industry. Operation readiness review is crucial to ensure the safe operations in Field-A. In this paper, a review on the pipeline transient analysis and process safety focusing on condensate export line from SPM, flexible hose and piping modification on FSO-B is described as a showcase. The review that referred to API standard and internal PETRONAS Technical Standards (PTS) has contributed in determining the revised operating envelop of the SPM and FSO-B compared to the initial project proposal. The technical operation and design review resulted in the avoidance of potential loss of process containment (LOPC), production deferment and PETRONAS reputation as prominent gas supplier within the region. It is important to ensure that the operating envelop is suitable with the production profile. With the operational readiness exercises, FSO-B was designed correctly and ensured of safe operation. FSO-B was commissioned on time and started operation without much delay and hence, securing the gas supply of 60 MMSCFD from Field-A to Customer-C, and exporting up to 1500 BPD condensate smoothly without interruption. This exercise has contributed to safeguard the tangible value of maintaining the gas production as well as keeping the intangible value of PETRONAS reputation. The operational readiness especially on the pipeline transient analysis review is significant novel to be replicated in other similar operations in PETRONAS and in similar operations in other operators.

Abstract For any given Exploration oil and gas portfolio and associated opportunities, successful business decisions can only be made on the basis of technically robust estimates of the subsurface risk versus the resource potential and estimate of the associated upside(s). Ideally, these estimates should incorporate the entire spectrum of opportunities for the complete portfolio and they should be made in a consistent and comparable way. However, as Explorers, we are often faced with data that is incomplete, limited, of variable quality, and/or inconsistent. As a result, subsurface evaluation may be seen more as educated guessing rather than a robust science of evaluation grounded in facts and defensible logic. In their January 2020 paper "Randomness, serendipity, and luck in petroleum exploration" authors Milkov and Navidi (Ref 1.) go quite a bit further and demonstrate that in the exploration success equation. They also showed a general lack in long-term consistency in exploration results of individual companies. Indeed, after we looked at PETRONAS’ own historical POSg versus actual technical success rates and observed only a fair to poor relation between actual technical success rate and the pre-drill POSg estimate. A similar—albeit less worrisome—observation was made for volume ranges and fluid phase predictions. Clearly, there is, and always has been, a phenomenal challenge for the Petroleum Geoscientists to provide the sought after estimates as accurately as possible, and we were no exception. In a bid to improve on this PETRONAS set out on a more disciplined approach to characterizing subsurface uncertainties on its conventional exploration efforts. Over time, more accurate characterizations of such exploration risk and resource potential have followed from a series of procedural guidelines, enhanced capability training program and careful governance of exploration workflows. With improved capabilities and workflow consistency, our evaluation teams have delivered substantially better subsurface evaluations. This in turn has led to more confident decision-making on e.g., individual drilling decisions and new play entries. While our newly implemented workflows are not groundbreaking in isolation, in combination they have delivered notable success and an improved ability to shape the future growth for PETRONAS. In this article, we will highlight the main contributing changes and demonstrate that the overall improvements are indeed impactful. We are not directly challenging the article of Milkov et. al., but are convinced that .

Abstract The execution phase of the wells technical assurance process is a critical procedure where the drilling operation commences and the well planning program is implemented. During drilling operations, the real-time drilling data are streamed to a real-time centre where it is constantly monitored by a dedicated team of monitoring specialists. If any potential issues or possible opportunities arise, the team will communicate with the operation team on rig for an intervention. This workflow is further enhanced by digital initiatives via big data analytics implementation in PETRONAS. The Digital Standing Instruction to Driller (Digital SID) is a drilling operational procedures documentation tool meant to improve the current process by digitalizing information exchange between office and rig site. Boasting multi-operation usage, it is made fit to context and despite its automated generation, this tool allows flexibility for the operation team to customize the content and more importantly, monitor the execution in real-time. Another tool used in the real-time monitoring platform is the dynamic monitoring drilling system where it allows real-time drilling data to be more intuitive and gives the benefit of foresight. The dynamic nature of the system means that it will update existing roadmaps with extensive real-time data as they come in, hence improving its accuracy as we drill further. Furthermore, an automated drilling key performance indicator (KPI) and performance benchmarking system measures drilling performance to uncover areas of improvement. This will serve as the benchmark for further optimization. On top of that, an artificial intelligence (AI) driven Wells Augmented Stuck Pipe Indicator (WASP) is deployed in the real-time monitoring platform to improve the capability of monitoring specialists to identify stuck pipe symptoms way earlier before the occurrence of the incident. This proactive approach is an improvement to the current process workflow which is less timely and possibly missing the intervention opportunity. These four tools are integrated seamlessly with the real-time monitoring platform hence improving the project management efficiency during the execution phase. The tools are envisioned to offer an agile and efficient process workflow by integrating and tapering down multiple applications in different environments into a single web-based platform which enables better collaboration and faster decision making.

Abstract This paper describes a methodology that can be used to estimate the potential value of implementing digital and automation technologies in the well construction process in the context of a complex deepwater environment during the drilling conceptualization phase. This serves as a guideline for those interested in quantifying the value of applying digitization and automation processes, not only to make informed decisions related to investment in drillship or systems hardware and software but as well as performance improvement.