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Technical Professional (TP) has been identified as one of the critical positions in PETRONAS that plays an important role in providing technical assurance in business deliveries. The intent of this paper is to describe the methodology and processes that been implemented in PETRONAS Upstream business to develop TP specifically in Operation and Engineering area. An inhouse program known as "Technical Specialist Program (TSP)" has been established as a solid capability development framework for internal talents in Upstream as a structure guidance for the talents to become TP undergoing the progression throughout the 3 levels of TP i.e. Staff, Principal and Custodian level. The program was design focusing on acquiring and strengthening the competencies on technical-know-how, including commercial and leadership elements. The growth of internal talent vs. experience hire talent in TP positions have shown significant improvement post 3 years of TSP implementation which reflected in growth from 35% to 71.8% of TP positions been filled by the internal pool of talent. Subsequently, successor ratio of TP position vs internal talent is progressing gradually from 1:1 to 1:3 as per the company's aspiration. The outcome of this paper will be beneficial and valuable to the industry practitioners for oil & gas industry specifically, as well as any related and relevant industry in developing technical talent for critical positions that requiring niche area of specialization. This paper summarizes the approach, best practices and lesson learnt based on the journey and experiences in developing TP through TSP.

BB field complex redevelopment is an integrated development under PETRONAS Enhanced Oil Recovery (EOR) project. BB fields are producing fields operated by PETRONAS Carigali Sendirian Berhad (PCSB). The BB fields redevelopment is a project to redevelop both B1 and B2 fields and to enable EOR implementation in the B1 field. The B1 redevelopment includes the EOR implementation through immiscible water alternating gas (IWAG), infill drilling, and safeguarding of no further activity (NFA) production. The B1 redevelopment also incorporates some provisions for the B2 field to secure gas supply for B1 IWAG. The B2 redevelopment focuses on safeguarding B2 NFA production. The redevelopment consists of three main elements, 1) EOR IWAG that involves injector well drilling at a new IWAG injection wellhead platform, 2) infill drilling at existing platforms and 3) safeguarding of NFA. Surface facilities scope includes installing a new Central Processing Platform (CPP) for B1 field, wellhead platforms, and intra-field pipelines. The CPP includes 60 kbpd water injection plant capacity, gas compression, gas-liquid separation, and produced water treatment. Modification in the B2 field is to flow gas from the B2 field to the B1 field. Operational readiness is crucial to ensure that the integrated project is executed smoothly. Two cases for changes are new technology deployment for water injection module (WIM) and people capability. It is a big challenge to achieve an effective start-up with minimum delay. There are some important aspects considered includes operation philosophy, Health Safety and Environment (HSE), and collaborative working environment (CWE) implementation. It is important to ensure improving oil recovery through infill and IWAG. Best practices in operation readiness of an integrated project that have many challenges that include process, people, and technology. These best practices may be replicated in any other projects by other companies/operators.

Water injection (WI) to improve oil production and increase reserves had been practiced in Malaysia since 1990s. Currently, around 27 fields are producing with water injection. To better manage these WI fields and gauge the relative performance of these fields, certain Key Performance Area (KPA) and Key Performance Indicators (KPI) were identified. Measurement of these KPA and KPIs serves as a yardstick to compare performance of WI fields and thus provide measures to improve collective performance by promoting replication of best practices and sharing lessons learnt. In the era of digital technology, the periodic measurement of KPA and KPI has been automated using the existing online platform which can remain accessible to all related parties. It provides a platform for data visualization with simple look forward analysis. The WI data is stored in company databank and the performance dashboard can be viewed from existing software. The team managed to overcome the challenges in completing the historical data gap and data hygiene which previously were managed manually and were not integrated. This resulted in historical evaluation of KPAs and KPIs of certain fields. This automation initiative will enable practicing engineers to identify the value leakages and proposed mitigation efforts. Some of the best practices identified such as pipeline pigging optimization, correct biocide dosage, periodic calibration of flow meter and chemical optimization already helped to reduce operating cost in certain WI fields. With these efforts, the company could reduce the operating cost significantly in year 2018. Other than data visualization, the tool provides diagnostic plots such as Hall Plot, Chan's Plot etc. for quick analysis of signs of well/ reservoir health deviations and thus solutions could be provided proactively. On seeing the initial positive results, this tool is being tried for the rest of the WI fields. This paper details how this tool tries to diagnose all sub-optimal areas within various WI project simultaneously, which leads to operational excellence and improvement in oil recovery, by identifying value leakages, providing proactive solutions with replication of thus identified best practices. Additionally, usage of this tool to rank WI performance of different projects can potentially help to initiate competition between different operators for improvement.

Relevant to maximizing oil recovery, water injection is implemented for reservoir pressure maintenance and to maximize oil sweeping. The water injection involves both surface and subsurface matters. Since the objective is reservoir pressure maintenance and oil sweeping efficiency improvement, the subsurface domain includes reservoir engineering, geology and geophysics as well as the production technology. For surface operations, the water injection operation includes water injection source, water plant operations and water injection infrastructure. Water injection bottle neck and water quality issue may occur and damage the water injection efficiency. An idea of molecule to molecule (M2M) water injection performance review is raised to conduct a comprehensive and collaborative water injection review that involving many and outreach parties such as reservoir engineers, geologists, geophysicists, operation engineers, production chemists, production technologists, maintenance engineers, production planners and process engineers. The opportunity to include technical providers, partner representatives and host government representatives is taken in order to allow an effective discussion and quicken the maturing of relevant solution proposals. Comprehensive end to end review from the point of water source up to the point of producer is done to identify problem at each point, threats and improvement opportunities at every single node within the whole chain. With the M2M, water injection performance review has effectively provided an effective collaborative working environment as well as a learning avenue for young professionals that are involved in water injection matters. Many action items are resulted from the exercise and they are having high impact including safeguarding potential cost of USD 10 million per year for the water injection plant and infrastructure operations. In the short run, no disturbances for oil production and in the long run, the oil recovery can be maximized. Due to some limitation, this paper discusses only the surface water injection operations.

This paper highlights the study on examining sustainable business performance determinants includes proposed variables of organizational learning culture and digital organizational culture. Organizational learning culture and digital organizational culture have been used in some previous studies but they were not recognized as determinants of sutainable business performance. The organizational learning culture is relevant in anticipating challenges and pressures while the digital organizational culture is relevant to the digital transformation. The empirical synergy of both supports sustainable business performance is quantitatively tested using the PLS-SEM tool and inputs of 207 samples collected from the Malaysia upstream petroleum industry. The results show that supports from organizational learning culture and digital organization culture on sustainable business performance are positive and significant. Digital organizational culture mediates the relationship between organizational learning culture and sustainable business performance. This research enriches the theory and literature on sustainable business performance and the role of organizational learning culture and digital organizational culture. It also provides fundamentals for industry practitioners and policymakers for relevant decision making and improvement.

Abstract Peninsular Malaysia Operations (PMO) plays an important role in supplying gas demand throughout the region since the gas business commencement in 1980's. Currently about 600 MMscfd gas is supplied by PMO. At the moment, three non-associated gas (NAG) fields, namely DYG, RSK, and TBC contribute to about 50% of the total gas supply from PMO. Apart from producing NAG, the RSK and DYG fields also serve as network hubs to evacuate gas to the Onshore Gas Terminal (OGT) through two independent gas delivery systems: Joint Delivery System (JDS) and Resak Delivery System (RDS) respectively. The two JDS and RDS gas streams are mixed at OGT and then delivered to the customer processing plant, with a CO2 maximum limit of 8% by mole. Apart from the many operational challenges to sustain gas production, meeting the gas specification proves to be a difficult task, especially for the RDS where TBC gas (with about 30–40% CO2) is to be blended with RSK gas (itself producing about 23% CO2).The TBC gas was put on stream in 2011 and an Acid Gas Removal System (AGRS) was deployed to reduce CO2 content. Prior and upon commissioning of the AGRS facility, feed of CO2 level into the gas network was managed by optimizing the flow rate. This paper describes some major challenges in sustaining the gas production supply and meeting the gas quality requirement. The major operational challenges include subsurface uncertainty and problems, maintaining gas compression reliability, AGRS operations and optimizing the usage of gas pipeline network. To complete the analysis, some commercial aspects are also discussed in the paper. Introduction This section consists of two parts:overview of gas business in Peninsular Malaysia andoverview on RSK/DYG field operations. The first part would be introducing the gas market in Peninsular as well as the strategy of fulfilling the gas demand. The second part would be describing the RSK/DYG field operations as the focus of this paper.

Pul-A field is an oil producing field located about 260 km offshore Terengganu, eastern Peninsular Malaysia in a water depth of about 77 meter in the South China Sea (Refer to Figure 1). The field is equipped with oil and gas processing plant, gas injection facilities and gas compression system. Pul-A was brought to production in March 1978 with an average oil production of 1,400 barrels oil per day (BOPD). The oil production peaked at around 35,000 BOPD in 1979. Previously produced water was treated using a corrugated plate interceptor (CPI) unit prior to discharge. The water treatment is required to ensure the effluent water quality is in compliance with regulatory effluent discharged water requirement of maximum oil content of 40 parts per million (ppm). The CPI unit was down several times in 2005 and 2006 causing twenty daysproduction deferment with an estimated opportunity loss of USD 6.8 Million. In line with the effort to maintain the oil production by flowing high water cut wells, a new produced water treatment technology was chosen to replace the existing CPI unit. The new equipment is a vertical separator that is equipped with acombination of induced gas and cyclonic fluid motion to improve solids, water and oil separation. Pul-A team successfully installed the new equipment with challenging modifications and tie-in work in aging facilities. The unit that was commissioned in October 2010is capable of treating produced water up to 15,000 barrel water per day (BWPD).

D Field is a major oil field located about 130 km offshore Terengganu, eastern Peninsular Malaysia with a water depth of 76 meters in the South China Sea (Refer to Figure 1). The facilities within the field include oil and gas processing plant, water and gas injection facilities, gas compression system and a Floating Storage and Offloading (FSO) where the crude oil is exported (Refer to Figure 2). The field was brought to production in March 1991 with an average oil production of 45,000 barrels of oil per day (BOPD) and peaked at approximately 75,000 BOPD. Water injection has been implemented for pressure maintenance and as part of the field life journey; water alternating gas (WAG) injection will be introduced to enhance oil recovery within the field. Fulfilling the WAG requirement particularly on gas injection, an additional gas compression module called the Compressed Gas Capacity Enhancement (CGCE) was installed to increase the gas compression capacity. In March 2010, D field has successfully completed two major jobs, the CGCE module installation and field turnaround simultaneously under a campaign called ‘D-field CGCE Integrated Turnaround’ (DuCIT). CGCE module installation comprises of the installation of a 900 metric tonne module onto the existing platform and the turnaround execution manages to complete planned activities including surface facility maintenance and well related works within the same period. DuCIT involved two major parties, D field Operations and the CGCE Project Management. With a huge challenge in coordinating a total of 400 personnel and controlling concurrent activities in a high risk operation, the team manages to complete the turnaround ahead of schedule with zero Loss Time Injury (LTI). DuCIT has been recognized as the best turnaround adhering to the requirements of PETRONAS standards on plant operation and capability. Analysis presented in this paper describes important key success factors in DuCIT execution; they are 1) proper turnaround planning, 2) developing excellent teamwork and 3) prominent operation coordination. The paper also describes the mitigation plans that were in place.

A Field is an offshore field located at offshore of Peninsular Malaysia, facilitated with an integrated oil and gas processing plant, water injection facilities and gas lift infrastructure. The field was brought to oil production in end of 2001 and achieved the peak production of about 120 Mbopd in 2005. In early of 2002, it started gas production at an initial rate of about 300 MMscf/d which is currently maintained at about 300–350 MMscf/d. The crude oil production peak was followed by a moderate decline over the next three years. Besides crude oil and gas production, the field also produces condensate as by product while producing gas. It was recognized that a proactive field management strategy was required in order to minimize any further production decline as the field production forecast showed a declining trend. Since A Field is one of major gas contributors, its gas production sustainability is very important to fulfill the gas demand in the region. The current gas sources in A Field are natural gas reservoir as the main source and the associated gas from oil production. It was recognized that subsurface and surface integrity is the key success for sustaining A Field gas production. The integration is important to ensure proper planning and execution for gas development within the A Field area as well as sustaining the crude oil production. There are several alternatives to maintain gas production. The analysis presented here describes the use of an integrated approach involving multi-disciplines to achieve the most suitable decision and maximize value creation focusing on A gas sustainability.

Peninsular Malaysia Operations (PMO) is one of three domestic regions of PETRONAS Carigali Sendirian Berhad (PCSB) located in offshore of Peninsular Malaysia. The operations cover six of main operation areas namely PPD-D, PPD-F, PPD-L, PPD-P, PPD-S and PPD-T. Those operation areas have a wide operation ranges: from green to brown fields, from single to multiple products, from onshore terminal to offshore Floating Storage and Offloading (FSO) and Floating Production Storage and Offloading (FPSO), from heavy crude to light crude and from big to small fields. PPD-D area is gas producer; PPD-F, PPD-L, PPD-P and PPD-S areas are crude and gas producers while PPD-T area is onshore crude and gas terminals. PPD-F area is scatter small fields facilitated with one unit of FPSO and one unit of FSO; PPD-L area is a big oil field facilitated with water alternating gas (WAG) injection facilities, gas lift infrastructure and one unit of FSO; PPD-P area is scatter medium to small brown oil and gas fields facilitated with processing plant, water injection facilities, gas compression, gas lift infrastructures, crude pipeline and gas pipeline and PPD-S areas is a big oil and gas fields, facilitated with integrated gas and oil processing plant, water injection facilities, gas lift infrastructure, crude pipeline and gas pipeline. In some oil fields, water injection is applied for reservoir pressure maintenance while water flooding and Enhanced Oil Recovery (EOR) technologies are implemented to maximize oil recovery. Some fields are still producing naturally while in most brown fields, gas lift is suitable to assist the crude production. Production operations comprises of three functions: production planning, field production operations and production logistics. The main scope is crude and gas production and evacuation from the well up to the terminal or exporting point. As the think tank in production operations, production planning consists of three functions: production analyst, field and integrated production planning and hydrocarbon accounting and allocation. In day to day works, production planning is focusing on crude and gas production achievement. Field production operation as the heart of production operations, handles day to day offshore routine activities, process performance improvement, process plant upgrade and new production facility installation. Considering the importance and urgency of capability building, production operations has taken significant measures in developing and helming competent engineers in order to achieve and maintain excellent production operations as well as to sustain technical talent development. Analysis presented in this paper describes important keys in competency development; they are 1) capability mapping, 2) skill development process and 3) measurement and feedback.

Angsi Field is an offshore field located in offshore Peninsular Malaysia, developed with an integrated oil and gas processing plant, water injection facilities and gas lift infrastructure. The field was brought to oil production at an initial rate about 30 Mstb/d in end 2001. In early 2002, it started gas production at an initial rate of about 300 MMscf/d of gas which is currently maintained at about 300-400 MMscf/d. Crude oil production peaked in 2005 and was followed by a moderate decline over the next three years. Besides crude oil and gas production, the field also produces condensate while producing gas. It was recognized that a proactive field management strategy was required in order to minimize any further production decline and maintain excellent production operations as the field production forecast showed a declining trend. Four key levers for sustaining Angsi's production were identified, namely: 1) prudent reservoir management and reliable water injection; 2) continuous production improvement and unfailing well integrity; 3) facility optimization and operational improvement; and 4) maintenance of high equipment uptime and infrastructure integrity. On top of those four levers, prudent and integrated production planning was very important in managing the integration of sub-surface and surface aspects. Various sub-surface and surface technologies were sourced with a target of sustaining production and maximizing oil and gas recovery. The lookback analysis presented here describes the use of an integrated approach in production planning and creativity in resolving problems involving reservoir management & well integrity and production operations through teamwork building.