This paper will discuss the case study of two (2) projects in Malaysia that were stretched-to-limit and optimized ‘on-paper’ all the wells’ related engineering design and construction, operation activities pre and during drilling campaign as well as logistic arrangement, which led to significant cost reduction in wells and thus improving the overall project economics. This significant savings achieved with full compliance to technical standards as well as with the betterment to improve HSE during offshore execution.

Output is the core index of oil and gas enterprises, and the management of output is very important to the operation of oil and gas enterprises. Each year, oil and gas companies will develop a production allocation plan according to well productivity. Under the guidance of the allocation plan, the annual production target would finally be achieved. In the digital transforming stage of development and production management of oil and gas fields, the traditional offline manual production allocation can no longer meet the needs of delicacy management. For this reason, based on the development and production management platform, a system of production allocation and management was established and deployed in an international oil and gas company. In this paper, through the information platform concept model, introduced the development and production management platform construction method. Based on the platform architecture, taking production allocation and management as an example, the system construction process is introduced from the aspects of business process splitting, system function design, data and software integration call, etc. Furthermore, through the integration of intelligent oil and gas project results based on the platform architecture, the integrated application of intelligent workflow to core business activities in the production allocation and management process is realized. The platform has been fully applied by a large natural gas production company. Through this platform, a management mode with "business standardization, process standardization, and execution standardization" was adopted to realize the comprehensive transformation of production allocation and management from the traditional mode to the digital one. The application of the platform shows that: the process of production allocation and management optimized in process-driven way is traceable and can form a business closed loop; through process reorganization and integrated application, the efficient business collaboration across specialities and departments has been achieved, improving the scientific decision-making ability and the level of business management;

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.

Natural gas is the noble fuel of 21st century. Consumption increased nearly 30% in last decade. Exploitation of conventional, unconventional, and contaminated gas resources are in focus to meet the demand. There are number of giant gas fields discovered worldwide and some of them with higher degree of contaminants viz. CO 2 , H 2 S and Hg. Additionally, they have operating challenges of high pressure and temperature. It becomes more complex when discovery is in offshore environment. This study presents the development and production, separation, transportation and identification & evaluation of storage sites and sequestration and MMV plan of a giant carbonate gas field in offshore Malaysia. Geological, Geophysical and petrophysical data used to describe the reservoir architecture, property distribution and spatial variation in more than 1000m thick gas bearing formation. Laboratory studies carried out to generate the rock and fluid representative SCAL (G-W), EOS and Supercritical CO 2 -brine relative permeability, geomechanics and geochemical data for recovery and storage estimates in simulation model and evaluating the post storage scenario. These data are critical in hydrocarbon gas prediction and firming up the number of development wells and in the simulation of CO 2 storage depleted carbonate gas field. Important is to understand the mechanism in the target field for storage capacity, types of storage- structural and stratigraphic trapping, solubility trapping, residual trapping and mineral trapping. Study covers methodologies developed for minimization of hydrocarbon loss during contaminants separation and utilization of CO 2 in usable products. Uncertainty and risk analysis have been carried out to have range of solution for production prediction and CO 2 storage. Coupled Simulation studies predict the production plateau rate and 5 Tscf recovery separated contaminants profile and volume > one Tscf in order to have suitable geological structure for storage safely forever. Major uncertainties in the dynamic and coupled geomechanical-geochemical dynamic model has been captured and P90, P50, P10 forecast and storage rates and volumes have been calculated. Results includes advance methodologies of separation of hydrocarbon gas and CO 2 like membrane and cryogenics for bulk separation of CO 2 from raw gas and its transportation in liquid and supercritical form for storage. Study estimates components of sequestration mechanism, effect of heterogeneity on transport in porous media and height of stored CO 2 in depleted reservoir and migration of plume vertically and horizontally. Generation of chemical product using separated CO 2 for industrial use is highlighted.

The concept of minimum economic field size (MEFS) has been used by explorationists for almost four decades. MEFS is often the only filter to distinguish between a commercial and a non-commercial discovery—far before a wildcat well is drilled—to test a prospect for a working petroleum systems hypothesis. As simple as it gets, the concept started to lose traction in the 21 st century as subsurface targets became more and more challenging. In the case of tight hydrocarbons, it is fairly common to observe a P90 case net present value (NPV) to be negative, a P50 case to be positive, and a P10 case to be negative again. The reason for this outcome is that a whole set of full-cycle factors, in addition to the field size, affects prospect commerciality. Their uncertainty ranges can match or exceed resource estimate uncertainty. These factors include, but are not limited to, initial productivity of development wells, estimated eltimate recovery (EUR) per well, decline curve parameters, capital investments, operating costs, and the project phases’ durations. A new way of handling the full universe of risks and uncertainties faced by modern explorers is already available in the new generation of industry-leading integrated prospect risk, resource and value assessment software. Innovators and thought leaders can already substitute MEFS with a commerciality threshold (CT) that neatly mimics board considerations at the final investment decision (FID) stage gate. Others can consider the economic chance of success (ECOS) estimated with a probabilistic full-cycle mindset, as an additional metric valuable for risk management purposes. Using fictional case studies inspired by real-life assessment situations, we discuss the additional value creation by a CT-powered workflow as compared to an MEFS-based one and explain the reasons for the key differences. The discussed workflow does not eliminate nature-specific uncertainties; neither does it reduce the geological risk. However, it helps to better understand human-controlled risks and prepare management exploration decisions with a greater degree of confidence.

Field development for brownfields nearing their economic thresholds is always challenging, especially in offshore environments. As an operator, innovative approaches are necessary to reduce capital expenditures (CAPEX) and create attractive projects. A marginal cluster consisting of three fields, namely PN, NL, and PR, is expected to reach its economic limit in the next 2 years. This paper elaborates on single-trip completion technology as a catalyst for drilling one infill well in the PR field development project. In 2017, one appraisal well was drilled in a western area of PR field to validate the presence of oil. The scope of work included evaluating reservoir productivity and acquiring bottomhole fluid samples. A drillstem test with four multirate tests was executed for this reservoir. A horizontal development well named PA-02 was proposed and categorized as an extended-reach drilling well because of the drilling complexity. Most offshore wells in shallow-water environments are completed with a conventional well completion run that takes two or more trips, which normally takes more than between 5 and 8 days. Given expensive daily rig rates, the ability to reduce completion installation time was deemed vital to the economics of the project. If the installation incurs additional unnecessary project costs, it can cause the project to be economically unattractive. Using a collaborative approach, an interventionless, single-trip sand control system was designed and selected as the optimal completion solution to meet project demands. Radio-frequency identification (RFID) technology is one of the key enablers for the single-trip completion as it offers the utmost flexibility in both activation and contingency methods to deliver the necessary project cost reduction. At a time of uncertain global crude oil prices, the RFID-enabled single-trip completion concept discussed in this paper has become a beacon of light for operators in an otherwise dark period by allowing previously marginal or sub-economic projects to become viable. This technology has resulted in operational time savings of at least 27% compared to typical conventional two-trip completions in Malaysia offshore environments. Minimizing operational risk is also foreseen by reducing installation to a single integrated upper and lower completion trip. Selecting this RFID-enabled completion facilitated full deployment in one trip in the high-angle well, which eliminated the deployment of a tractor service for a 67% cost savings in this aspect alone. This method represented a paradigm shift in operational efficiency and will now be the operator’s strategic completion methodology when developing marginal fields. The deployment represents the first application of a single-trip completion in an economically challenging brownfield in the Malaysian offshore environment. The reduction in operational time and resultant savings in CAPEX proves that a single-trip completion offers an exceptional alternative to conventional methods in the shallow-water offshore environment.

Sand production is one of the operators’ intimidating challenges as the cascading effects can cause significant damages to the surface equipment and often lead to costly clean-up effort. Its effects are further amplified in gas wells with higher gas velocities lead to more detrimental effects on the facilities. Consequently, the facilities will deteriorate, leading to uncontrolled hydrocarbon release which compromise the operation safety considerably. Hence, sand detection devices such as acoustic sensors are extremely crucial to detect sand production as early as possible prior to any undesirable damage. This paper highlights the selection reasoning and advantages of permanent acoustic sensors as well as the method in maximizing the data value through integration with digital field monitoring. Various sand monitoring equipment are available in the industry and its selection is mainly driven by operators’ purpose with cost-benefit analysis. The multi-disciplinary team collaboratively decided on a holistic approach of utilizing the permanent acoustic sensors to its maximum potential. Integration of permanent acoustic sensors with digital field monitoring further improves the investment return as the sensors can provide real-time sand production data. Effective real time sand monitoring can be performed by both offshore and onshore crews where immediate countermeasure can be deployed if abnormal readings detected. When handling sand prone wells, proactive measures have been proven to be more effective if compared to reactive measures. Each well production potential can be maximized by installing sand sensors to ensure safe operating envelope without sand production as well as to trigger alarm if sand detected. The key to unlocking the potential is to ensure data is effectively transmitted to the command center and to the office via our digital field system. The operators are also trained on the next course of action such as beaning down the wells to safe operational envelope in case of sand breakthrough. The value of the acoustic sensors outweighs the total cost involved as real-time sand monitoring system helps to safeguard surface facility integrity considerably.

This paper discusses the workflow and method of selecting optimum number of infill and injection wells based on incremental recovery. Normally, for infill wells study, a ‘creaming curve’ method is used to evaluate the optimum number of wells against incremental recovery from the field. However, in the case of determining number of infill wells together with water injection wells, a more comprehensive approach is needed. One needs to evaluate the pressure depletion rate from existing and infill wells together with the dynamic of the producer-injector pairings as well as the sweeping factor. The paper is based on infill and water injection development plan for a brown field in Sabah basin which located in Malaysia. To maintain operatability of the field in the future, several new infill and water injection wells options are evaluated for optimum field life oil production. Unlike infill or producer-only assessment, the same ‘creaming curve’ approach for combination of infill and water injection wells is less effective as large number of simulation runs are needed to sample the combination of these wells that generate optimum oil recovery. This has proven to be challenging especially when the models are large which is normally the case for brown fields and it requires extensive computational hours. In the first part, a modified approach bringing some pre-analytic assessment of producer-injector pairing is being used. The pairings are first ranked based on streamlines visualization, drainage tables and their respective contributions towards oil recovery. The ‘creaming curve’ is then built based on the highest contribution as well as the sequencing of the pairings. The second method mentioned in this paper is the numerical approach through multi-objective optimization using assisted history matching and uncertainty tool. With the help of optimizer, the number of simulation runs can be drastically reduced when only best combination of infills and injectors for each total number of wells are considered. Both alternative methods will be compared with the full computational runs, sampling every single combination of wells. Finally, the optimum number of wells with the combination of infill and water injection wells are analysed based on cumulative oil recovery against the Net Present Value (NPV). This case study therefore demonstrates how alternative methods can be used to resolve the optimum number of infill and water injection wells to avoid lengthy and very large numbers of simulation runs.

PSC fiscal system serves as a framework to determine the sharing of petroleum revenues between stakeholders. Understanding its behavior is essential, given the nature and duration of upstream projects. The paper rationalizes fiscal systems that can promote a balanced, progressive, and robust revenue-sharing mechanism. The impact and efficiency of three typical fiscal regimes are assessed by observing how they react to different scenarios and outcomes, which could be either better or worse than the initial expectation. The three typical fiscal regimes are fixed-rate, production sliding scale sharing, and profitability-based sharing. The early days’ fixed rate sharing system is rigid and does not effectively address the different scales of upstream project investments and the associated uncertainties. The production sliding scale sharing is a partially progressive system that addresses production level variation but does not respond to the variation of other value drivers such as actual cost, price volatility, and project schedule. The profitability based fiscal term represents a progressive win-win system that is more robust, self-regulating, and balances stakeholders’ value objectives. Profitability-based sharing also promotes subsequent field developments. New investment lowers the profitability ratio, which in turn increases contractor profit share percentage. This mechanism results in higher incremental value to the contractor when developing the next field. Compared to the fixed-rate and production sliding scale based sharing, the profitability based sharing could provide a fiscal balance system that is self-regulating, progressive, and more robust. It fits nicely with the oil and gas industry known for the inherent risks and wide range of uncertainties throughout the life of the project. The profitability-based system could be further enhanced to encapsulate the multiple claw-back provisions by switching from the traditional stair-step sharing to a steeper linear sharing with the appropriate ceiling, floor, and triggering points. The linear representation of profitability-based sharing could also complement the various available PSC management control provisions to mitigate the potential cases of opportunistic gold-plating. The sensitive feature of linear sharing could help deter such manipulation. (334)

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.

PETRONAS Upstream is cognizant of the need to provide a unified digital production platform to the entire upstream community. The digital platform enables the community to perform analytical, collaborative monitoring & surveillance, and optimization to sustain production and improve our operations. Digital Fields (DF) is a modern digital platform, integrating data and analytical services, that provides smarter insights and shed light on potential insights that contribute to better-informed decision-making and improves the way of working. A big data ecosystem and strong infrastructure is the foundation of this digital platform, allied to existing business processes, it allows frictionless secure flow of data, high performance, scalability to support business operations. Digital Fields platform provides the following features: Scalable to all PETRONAS fields operated in Malaysia as well as International assets Solution architecture that allows fast implementation of new solutions and insights A common company-wide platform with the same familiar user interface and user experience The critical aspect to liven up a digital production platform is to identify first the available data sources. Some fields have the luxury of transmitters and sensors installed at the well head, topside facilities and export pipelines where the data can be easily retrieved from the SCADA system for data acquisition. Some other fields with less real-time data luxury would keep their operational data inside some operational reporting documents. A smart report ingestion solution was developed with the means to transform unstructured data from the operational reports, which empowers the users with multiple options for data upload and consumption while ensuring a single, traceable and auditable source of truth. Digital Fields leverages the combination of Daily Operation Reports (DOR), data with different frequency, such as real-time data, with engineering models changing the way the users consume data and provides proactive actionable insights to accelerate tangible values for the business organization. The solution establishes the foundational digital capabilities for field operations and speeds up data-driven value opportunities from operational data and analytics at scale.

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.

This paper describes a step change by well completion group in adopting Single Trip Liner Open Hole Completion (STRIP-LOC) technology, basis of selection, design, and operation approach. This has contributed to the reduction in initial well cost estimates thus benefited overall project cost. The technology adoption signifies the importance for continuous design improvement, operational optimization, and capital expenditure reduction, while not compromising with technical and HSE standards.

This study is to propose a transparent mechanism among host governments and international oil companies (or IOCs) so an amicable "win-win" situation can be achieved on the negotiation of the petroleum contracts for the development of marginal fields. Marginal field has various definitions. It can be a field with recoverable reserve not exceeding 30 million barrels of oil or 500 billion standard cubic feet of natural gas ( Abdul Razak 2011 , Malaysian Petroleum Income Tax Act 1967). It also can be a field, somehow "stranded", needs an oil price of US$60/bbl to be commercial ( Aziz 2019 ). Or as simpe as it can be, a marginal field in Nigeria is any field being left unattended for more than ten years from the date of discovery ( Auwalu 2020 ). In this paper, the author recommends that a marginal field be difined as any undeveloped field with a zero present value at 10% discount rate (or PV10 Value = 0) based on the average commodity price of previous 12 months’ first-day-of-the-month prices. This definition is conformable to the SEC pricing guidelines for publicly traded IOCs in the U.S.A. (Scheig n.d.). Host governments endeavor to bring foreign fund and technology to develop their hydrocarbon resources effectively for the benefit of national welfare. IOCs are eager to expand into other promising areas for more hydrocarbon reserves in order to strengthen the balance sheets. A well-designed petroleum fiscal regime can thus achieve the balance between host governments and IOCs ( Tordo 2007 ).

This paper showcases the tailored initiatives undertaken in a different economic climate in view of low oil price in maturing and capturing potential development opportunities for a large-sized, brownfield asset. The subject field is mature, having over 250 wells with over 20 years of production history and approaching its end of economic life. The study emphasized pursuit of a fast and cost-effective approach in identification of several potential behind-casing recompletion opportunities in addition to multiple infill drilling opportunities. From well log observation to seismic interpretation, and from material balance to simulation modeling, the approaches utilized were tailored based on the level of reservoir complexities. Lower cost, lower risk, behind pipe opportunities had previously not been a focus or thoroughly assessed since the company had focused on infill drilling opportunities. A robust execution plan, minimizing rig moves, was also prepared to synergize the ongoing and planned infill drilling campaigns in the field. An infill drilling well proposal was approved as part of the 2014 Field Development Plan (FDP) update with regulators. This plan was subsequently deferred due to drop in oil price resulting lower economics. However, with the field approaching the end of its economic producing life, a revisit of potential opportunities was conducted by a multi-disciplinary team. Results of the more recent opportunities identification and successful drilling campaigns have revived the proposal for the infill well given the synergies with rig utilization. The team went through a simplified governance process on the FDP, revisiting the simulation model and proposed to drill a horizontal infill production well instead of dual-string deviated well (originally envisioned for long string as an infill producer in the target reservoir and short string completed as a water injector in a different reservoir). Due to further well performance analysis, injection support on the other reservoir was no longer deemed necessary. The team analysis for arriving at this optimization as well as the behind-casing recompletion opportunities will be shared in this paper. This is a case study on how assimilated and innovative approaches undertaken in a different economic climate can be crucial to accelerate a brownfield re-development to extend the economic life of a mature producing field. A multi-disciplinary team applied creative thinking and cooperative efforts to a mature field to revive economic viability. Revisiting previously identified opportunities in the context of a low oil price environment and a simplified regulatory governance process, cross functional and cooperative technical and financial team work were important in facilitating timely decisions needed to move forward. A similar approach will be undertaken for future work in other fields.

Optimizing multiple assets under uncertain techno-economic conditions and tight government policies is challenging. Operator needs to establish flexible Plan of Development (POD)s and put priority in developing multiple fields. The complexity of production and the profit margin should be simultaneously evaluated. In this work, we present a new workflow to perform such a rigorous optimization under uncertainty using the case study of PHE ONWJ, Indonesia. We begin the workflow by identifying the uncertain parameters and their prior distributions. We classify the parameters into three main groups: operations-related (geological complexity, reserves, current recovery, surface facilities, and technologies), company-policies-related (future exploration plan, margin of profit, and oil/gas price), and government-related (taxes, incentives, and fiscal policies). A unique indexing technique is developed to allow numerical quantification and adapt with dynamic input. We then start the optimization process by constructing time-dependent surrogate model through training with Monte Carlo sampling. We then perform optimization under uncertainty with multiple scenarios. The objective function is the overall Net Present Value (NPV) obtained by developing multiple fields. This work emphasizes the importance of the use of time-dependent surrogate approach to account risk in the optimization process. The approach revises the prior distribution with narrow-variance distribution to make reliable decision. The Global Sensitivity Analysis (GSA) with Sobol decomposition on the posterior distribution and surrogate provides parameters’ ranking and list of heavy hitters. The first output from this workflow is the narrow-variance posterior distribution. This result helps to locate the sweet spots. By analyzing them, operator can address specific sectors, which are critical to the NPV. PHE ONWJ, as the biggest operator in Indonesia, has geologically scattered assets, therefore, this first output is essential. The second output is the list of heavy hitters from GSA. This list is a tool to cluster promising fields for future development and prioritize their development based on the impact towards NPV. Since all risks are carried by the operator under the current Gross Split Contract, this result is advantageous for decision-making process. We introduce a new approach to perform time-dependent, multi-asset optimization under uncertainty. This new workflow is impactful for operators to create robust decision after considering the associated risks.

Major reservoirs in Field A namely A-2, A-3U, A-3M, and A-3L, are deposited within a multi stacked channel complex system within Group I in Malay Basin. These reservoirs were previously understood based on existing data to have no or very minimal vertical communication between them and are treated as separate systems. In 2018, three wells were proposed to drain the attic oil in the north region of A-3U reservoir. When drilling these infill wells, it was discovered that the pressure has exceeded initial reservoir pressure although the reservoir has been idle for almost a year prior to the drilling. The results of the multi-rate test of two of the three infill wells that are less than 1 km apart are significantly different from one another. Post drilling, more tests were executed to investigate the connection between the sand. Studies were also done by incorporating the static and dynamic reservoir modeling data. Based on the result of the tests and studies, it was concluded that all of the major sands are connected at some areas. This new finding on the connectivity might be able to explain the additional volume needed to history match some of the reservoirs. Establishing stratigraphy concepts of a reservoir particularly in a channel complex system is an ongoing process, in this case, a brown field of almost 20 years of production. All data including new well data and dynamic data plays a vital role for a better understanding of the reservoir. It is essential to incorporate the updated geological understanding into the static model to have a representative simulation for better history matching and prediction. Moving forward, instead of building a separate grid model for each reservoir, a larger framework consist of intercalated reservoir grids will be built with this new geological understanding for dynamic simulation.

S Field field started enhancement planning and redevelopment recently by using an innovation EOR program called GASWAG, Gravity Assisted Simultaneous Water and Gas, in the selective oil-bearing sands. The initial program includes 6 infill producers, 2 water injectors, 3 gas injector wells and approximately 15 potential well reactivations to increase recovery by 7%. Since GASWAG is a new program in this region, it requires well and reservoir monitoring system to be implemented to have better understanding of complex behavior of water and gas injection and its effect on EOR performance. The main objective of the EOR Integrated Operation (IO) workflows solution, is to determine as quickly as possible if EOR performance is deviating from plan. This will be accomplished by earlier detection of EOR performance exceptions (compared to process without IO functionality), so that corrective action cycle time can be reduced, thereby reducing production deferment. Well Surveillance & Operational: a workflow to monitor, analyse and manage EOR wells production/ injection performance using real-time and in-time data together with updated well model. This Workflow focus on well and zones monitoring by using the well model and existing measurement. In addition, the existing IO workflows are integrated with EOR-Operational and feeding online data to this WF which is consistent with operational safety limit and KPOs. All operational data required for reservoir and production engineering were extracted either from well model, measurement or other workflows to the same well interface. Additionally, production and injection well surveillance and alarming system is implemented to benchmark the current operational condition deviated from plan or operational limit. Updated dynamic model and optimizer tool are used to define the optimum choke size of each reservoir layer for injecting or producing wells. This workflow was built and implemented successfully. It is designed based on very comprehensive technical aspects and KPIs from reservoir management, production engineering, facility constraint, well integrity to operational optimization. A single interactive visualization interface via web-based is implemented which cover all necessary production and reservoir data needed for collaborative decision making. The EOR well surveillance IO workflows will assist in automating computation of injection and production well health and performance. This solution benefits the asset team by allowing early detection of underperforming injection and production wells. Main challenges in S Field was, it is divided by several jackets thus require movement via vessel for manual data gathering. Unpredictable and adverse weather heavily challenge this activity. By having IO would help to improve data hygiene and collective data on daily monitoring. Additional functionality of the well surveillance workflow includes the monitoring of zonal rate and pressure, which are considered as main reservoir performance parameters. Operations, production, and reservoir engineers, as well as technical & business owners benefit from these workflows to steer the EOR operation.

2020 marks another challenging year for O&G sector, with the operators being in an uphill battle to survive the plunging oil price. With CAPEX rationalization underway, future field development may only be prospective via implementation of low-cost Field Development Plan (FDP). As well cost is a significant component of development CAPEX, low well cost must be pursued, by designing fit-for-purpose wells. For relatively shallow (≈2000 m-MD in meterage drilled) wells, a simple well design consisting of only two-hole sections (excluding Conductor) shall be considered. This design approach though, may require the Surface Casing to also be the Production Casing (if only Production Liner will be ran in the production hole section or if open hole completion is feasible or if cemented monobore completion strategy is adopted). This aspect of casing design (having Surface cum Production Casing) does indeed pose well integrity concerns as the quality of cement behind the Surface cum Production Casing is uncompromisable to ensure no gas can breach to surface. This paper discusses the design measures than can be incorporated into the well trajectory, cementing plan, and production surveillance in order to support the feasibility of Surface cum Production Casing concept.

An oil-bearing structure in the southwest of Bozhong Sag in Bohai Oilfield contains large oil and gas reserves. It will be a key area for Bohai oilfield to increase reserves production. The main target layer in this block is the fractured granite formation in buried hill. Exploration work in this block is faced with many operational problems such as "deep burial, high temperature and high pressure (HTHP), low penetration rate, difficult reservoir protection, and low accuracy interface determination". Through technical research and field practice, aiming at "all well sections drilling rate speed-up, operation safely and efficiently, and releasing production capacity", a set of key technology system suitable for offshore oilfield deep exploration is formed. Since the application of this technology system, it has effectively improved the efficiency of well construction, greatly reduced the cost of exploration and operation, facilitated the discovery of oil and gas in multiple mid-depth strata. It has achieved a good operation effect on social and economic benefit.