Abstract Oil producing companies are targeting minimal modifications to existing facilities in an attempt to increase oil production with minimal capital investment and squeezed schedule, thereby maximizing overall return on investment. Such brownfield works impose numerous execution challenges which are dependent on availability of shutdown window. This paper focuses on challenges involved in brownfield tie-in execution and presents mitigation strategies for performing tie-ins without production shutdown based on recent projects executed by NPCC. Brownfield projects execution has various constraints due to limitations in design modification of existing facilities. Such limitations pertain to existing Facility Layout, Flare System, equipment and adaptation of new standards to existing facilities and various other design /safety compliance requirements etc. During execution of modification works, early tie-in and shutdown requirements are firmed-up in accordance with the Oil Producing Company's business targets and alignment with all stakeholders. Production shutdown is highly undesirable since it leads to revenue losses as well as schedule and cost implication on the project. Hence, brownfield tie-in strategies always aim to keep production shutdown minimal. In order to accomplish timely tie-in execution, it is necessary to freeze the Tie-in Execution Philosophy at an early stage of the design in compliance with the producing company's HSE standards. This can be achieved by resolving all brownfield related challenges specially ensuring the early alignment of all stakeholders regarding the requirement of early tie-in, plant shutdown and low production window and by conducting an early site assessment to ensure that As-built drawings are corresponding to actual site conditions. In one of the Brownfield EPC projects executed by NPCC, various operational mitigation strategies were considered for tie-in execution without shutdown such as providing a temporary flare relief arrangement during Flare Tie-ins, lowering operating pressure to safe limit during execution of Tie-in on Production Oil manifold with single isolation valve, Isolating Produced water system during low production window and continue production with reduced rate by functioning HP/MP Separator in two phase mode during Produced Water Tie-in, lining up an alternative uninterrupted fuel gas header / source during Fuel Gas Tie-in etc. Such strategic methods resulted in execution of all brownfield tie-ins without any production shutdown, thereby avoiding production loss during modification works in an existing facility. Based on extensive experience with execution of brownfield projects, NPCC is better placed in formulation of tie-in strategies that are aimed at avoiding production loss. This paper presents valuable suggestions and mitigation strategies from recent projects executed by NPCC that will serve as Tie-in execution philosophy for operating companies as well as Contractor companies in petroleum industry. These strategies will assist companies’ in effectively optimizing their resources, enhancing the efficiency and profitability of their projects.

Abstract Upper Zakum field is a mega offshore field, in which ADNOC Offshore is investing a lot of resources to bring development target to reality. In order to achieve the company's strategic milestones, over 300 minor and major projects are being implemented utilizing a tremendous number of major and minor resources. This excessive volume of data is communicated daily from each division independently with different templates/format, which isn't reflecting the complete image of operations and development progress status. Therefore, to achieve those strategic milestones, an effective planning process across multiple functions within different organizations and at various locations, along with an efficient tracking system was established. Operation Planning & Support teams developed Upper Zakum 5 years business plan alongside the Integrated Master Activity Plan (IMAP) to identify the required scope ensuring safe guidance of the company towards achieving its targets while sustaining the integrity. IMAP leverages the communication level among all stakeholders, particularly during the planning phase, to enhance the effectiveness and realism of plans, in addition to, providing flexibility in reviewing the plan from different perspectives through the ability to produce various layouts aligned with specific requirements. IMAP website has been established to enhance communication and ensure that all stakeholders have adequate information that supports maintaining consistency in the workplace and preventing any ambiguity. The website provides an efficient and prompt access to review planned activities for a particular project as well as forecasted activities on a particular asset location. IMAP website has ensured the effective distribution of up to date information on each asset location such as objectives, responsible team, resources allocation, material delivery time, execution timeline, and planned shutdown windows. This collaborative approach leads to early discovering of major resources clashes and abolishes them during the planning phase, ensuring the best utilization of resources and completing the required scope within the time boundary; as well as, enhancing the predictions of production, water injection and improve the accuracy of budget outlook; in addition to data-driven realistic decision-making.

Abstract In production engineering, managing a mature field, where cost and job complexity increases as the reservoirs further deplete, analyzing a vast amount of data from different sources is required to understand the well and reservoir performance on a timely basis. Analyzing the full picture of the production system behavior and planning timely interventions is the key in managing these fields. As the E&P organizations go through the production lifecycle, it is increasingly difficult to keep this data in a structured format and a place where it can be easily accessed by the end users for their day-to-day workflows. More and more production data end up in Excel spreadsheets and other repositories creating what is known as data entropy. Legacy corporate data archives become a bottleneck in efficient production data management as they cannot scale efficiently. On the data analytics side, production and reservoir engineers often rely on Excel spreadsheets or inefficient home-grown systems which restrict their ability to derive more insights from the data. Then there is the collaboration aspect. Emails and shared-drives become the de-facto form of exchanging analysis and data, but these resources are time consuming and error-prone due to misplacement, duplication and different vintage of several data files. It is contradictory that the E&P industry despite its steady advances with digitalization and adoption of the latest technologies such as Artificial Intelligence and Machine Learning (to mention a few) continues to struggle with these fundamental data management issues. The implementation of a robust production data management system and basic analysis workflows are key to enabling effective digital tools and must be a top priority for any oil and gas organization consolidating their digital journey. This paper talks about the success case of implementing a production data management system for the mature assets of a National Oil Corporation, encompassing 37 years of production data from various scattered archives. The implementation of the system was customized to suit the requirement of the end-users to enable maximum utilization and faster adoption of the technology. The conceptualization, implementation, customization and development of this digital transformation initiative along with lessons learnt and future development possibilities is demonstrated in this case study.

Abstract Increased focus by Upstream Oil and Gas Companies to adapt to the current business environment has led to leveraging upon process simplification, Industry- 4.0 and digitalization programs for enhancing the field operations, reduce deferments and standardize planning processes inline to operational excellence. Objective is to lean current processes through developing lesser decision stage gates and providing input data bank for faster decision making, thus transforming the way of working into "value based" and improving on efficiency. In current business environment, digital solutions are being favorably viewed as enablers instead of disruptors, as was considered in the past. Digital solutions encompass development of model based technical workflows, lean business process workflows, robust planning methodology and integrated performance dashboards to enable informed and optimal decision making. Through this paper, experience from various Oil and Gas Upstream Operators in their journey of digitalization and in business and technical process simplifications will be shared, based on author's work and interaction with different oil and gas operators.

Abstract ADNOC Onshore operates a sour field on South West of Abu Dhabi with the wells to the northeast of the field exhibiting generally higher H2S content than wells to the southwest. Congestion of the field is recognized as a major issue affecting safety, access to existing reserves and operability since the early 2000. The congestion is caused by the high density of surface facilities resultant of numerous interfaces in the field (stakeholders), making well surface location finalization very challenging and impacting directly on subsurface congestion (by risking or impairing access to lower staked reservoirs - subsurface collision), rig moves, field connectivity, etc. This poses serious challenges to future developments if the approach of business as usual were to continue. The field has been producing from several oil and gas reservoirs but accelerated plans for oil and gas long term developments extended the exploration to other new reservoirs, increasing the challenges on reservoir exploration (brown field vs green field approach), on safety (exponential increase in number of wells, reservoirs with higher H2S content, etc.). It also increases surface and subsurface congestion, as the complexity of producing from more staked reservoirs increases. Decongesting the field and controlling the associated congestion of on-going projects is a key activity to manage space for future development, sustainable operation and business continuity. So far, the evaluation of a certain project options in terms of footprint impact has been qualitative in the sense that the decision is made based on the congestion observed on Enterprise Geograhic information System (GIS) map and in order to quantify footprint use and achieve a trustworthy comparision mechanism, a Geograhic Iinformation System (GIS) based congestion factor calculation tool had to be developed. This paper covers the development of the Congestion & Connectivity tool as an important milestone in ADNOC Onshore's initiatives to quantify and address the congestion issues on surface and consequently on subsurface and extend to other ADNOC Onshore in the long run.

Abstract Prevention of workplace accidents remains a challenge to the Oil and Gas industry to avoid interruptions to business, safeguarding their employees and maintaining their reputation. The Oil and Gas Industry is challenged by repetition of incidents, despite addressing root causes of incidents. Typically incident investigations highlight gaps in the implementation of an HSE Management System and often corrective actions include revision of procedures, more training, enhancements in work planning, design review and procurement of new tools. Analysis of over 500 Oil & Gas incidents investigation was carried and the repetition of incidents was noted despite addressing the identified gaps and further linkage of human factors with causes and corrective actions was further analysed. An analysis of findings and causes of incidents was carried out and human factors such as incorrect decision, improperly performed action, improper lack of action and presence of error inducing precursors were re-mapped to assess effectives of the investigations. It indicated that over 80% of drilling incidents were due to human factors and the following were the repetitive human factors issues leading to majority of incidents: Work load and task decision Motivation and attention Competence and learning Communication Remapping of conventional causes with human factors guidelines, highlighted consistent patterns of causation of incidents where multiple human factors criteria were formerly overlooked, led to these losses. Based on the analysis, the incident investigation training curriculum was revised to include human factors and error recovery, which was often, if not totally overlooked, was identified as a theme for corrective actions. It was noted that corrective actions (75%) were ineffective, as those actions were not directed toward human factors. It has prompted organizations to change the way incidents were investigated and the need of linking system causes with specific human factors deficiencies. It was found that 80% of drilling related incidents within ADNOC were triggered by unsafe actions and 62% of unsafe actions were due to human error & mistakes and 40% of drilling incidents were triggered by inattention/lack of awareness/unintentional human errors and violations by individuals, supervisors and by the group amounted to 15% of all immediate causes; and ack of knowledge of hazards present accounted for 14% of all immediate causes. Inadequate Identification of Worksite/Job Hazards accounted for 13% of overall drilling incident root causes and root causes associated with Human Factors contributed to 50% of all drilling incidents. This approach has led to changes in incident investigation curriculum in areas such as interviewing witnesses, identification of errors and identification of corrective actions. List of incident causes has been disintegrated to focus on type of error and error inducing factors. This novel approach focused on causes and provided efficient corrective actions to avoid recurrence of incidents. Analysis indicated that employee's low risk perception was due to lack identification of work site/job hazards followed by lack of leadership were the predominant root causes of incidents.

Abstract This paper illustrates integrated data management and architecture philosophy in an integrated digital oil field (DOF) production & reservoir ecosystem comprising of workflow automation implementations. Data availability, gathering, quality, validation & integration are the practical challenges where activities of extracting insightful information consumes 30% total project and sustainability efforts. The philosophy has been summarized based on challenges faced and lessons learned in four giant brown fields. The adopted data management framework is fully aligned with DOF workflows project delivery framework of four phases. The first phase comprises of establishing approach for model-based production workflows and data strategy. The second phase involves descriptive data analytics, mainly focused on data- preparation, data-review and data validation at source (E&P, Production, Engineering & Historian/DCS databases), where information is identified, highlighted and communicated with key project stakeholders and users. Considering current state of data, a user-control driven automation mechanism is adopted such as for hydraulic model building and implemented during third phase framework development. During this phase, users perform various diagnostic analysis using initial calibration of the model to pinpoint and prioritize data quality issues that need to be resolved. This phase also includes configuration steps for standardized naming conventions, which are critical to avoid integration issues between reservoir, wells, facilities & forecasting models. The last phase is maintaining and sustaining the integrated model based DOF workflows, where some events occur on regular basis (new well-tests and surveys) taken care by workflow automation however other events occurrence is governed by planned operational activities such as new wells drilled, workover activities, facility upgrade and modifications, RMP activity schedules etc. An automated data-tracking-system was implemented to assist on timely updates. A standard asset framework and tag naming standards in real time historian automates real time data retrieval in DOF workflows. The integrated framework defined for well measurement validation and structured approach helped not only in improving data confidence level but also in recognizing true well health condition. The presence of integrated digital oil field workflows further enhanced data validation process by bringing in physical correlation which exists among various operational parameters. The fully automated workflows have reduced manual data errors by 10% to improve efficiency. However, at the same time, semi-automatic approach was taken in which data integration with external data sources were established, but a manual option was enabled until all data gaps are identified. Several improvements have been suggested to field operators and data management teams to improve data entry processes. Real time data asset framework has reduced 70% efforts from engineers for tag configuration activities. The Authors describe holistic perspective encompassing closed loop of data acquiring, validation, integration, architecture, real time asset framework & automation and feedback to realize and increase optimization opportunity.

Abstract Objectives/Scope The complexity and volume of data generated during a major CapEx Project is huge. There can be hundreds of thousands, potentially millions, of documents and records with repeated references to the same data in different formats. The success of a project relies on effective sharing of this data to ensure all team members get the data they need to do their tasks. This only gets more complex as project teams manage changes and details evolve through the life of the project. Maintaining control of the schedule and budget for a Mega Project depends on understanding the status of all this information. This paper discusses how a data-centric approach to project data paired with robust engineering information management and contextualized in a Project Command Center, acts as a digital project hub to ensure Project teams can stay on top of their information and ensure project success by keeping schedule and costs on track. Methods, Procedures, Process The Digital Project Hub is the "Google Maps" of a Mega Project, using click-through, contextual 3D models and hot spotted 2D drawings to get access to relevant engineering. Digitalization of engineering systems enables this approach, leveraging common identifiers from systems with related attributes, status and relationships associated with it. The Project Command Center acts as data aggregator with API’s/Gateways that allow for data to be published from multiple systems into a single portal. The Hub is a true data aggregator, leaving all records in their originating systems, acting as a read-only publishing site. The system can then be used for reporting, searching, filtering and running consistency checks and analysis between systems of record to catch potential misalignment in data, and inconsistencies in naming conventions, formats and other key data points. Results, Observations, Conclusions Traditional file and document management systems consume a huge amount of project resource. Typically project team members can spend between 30-50% of their day looking for the data. Having the data readily available in the Project Command Center virtually eliminates this delay. Projects are also impacted by the accumulated inefficiencyimpacts created as teams/individuals wait for the data they need to complete their tasks, and by the rework caused by errors that are propagated across records in different systems. Novel/Additive Information The approach described here is unique in the industry as it offers a true view of a project, sSimultaneously accessing data from multiple teams, crossing contractual and scope boundaries. The Project Command Center becomes the central location to visualize the entire project, enabling collaboration between teams, from engineers to operators. Coupling technical information with status and relationship information enables multi-dimensional filtering and pivoting of project data. The result is a central location where data: is up to date and correct; searchable; visible in context; trustworthy; and easily accessible. Note: The above abstract was updated on August 25, 2020 to reflect a solution name change from ‘Digital Hub’ to ‘Project Command Center’.

Abstract In drilling engineering, Key Performance Indexes (KPIs) are import aids for management optimization and technical improvement, such as drilling time, monthly footage, rate of penetration and non-productive time, etc. Almost all oil companies have deployed database systems to manage drilling information, where maybe millions of daily reports are incorporated. While in international oil companies, some shortcomings of conventional data management system are gradually shown: reliability decreasing of data analysis reports during transferring in different levels due to manual intervention, huge amount of unstructured data in losing risk, low automation of KPIs analysis, low tolerance of data processing procedure to poor quality data, various data standards of different fields, poor performance in KPIs visualization. To solve the above problems, an integrated and intelligent drilling KPIs analysis system based on modern data science techniques were developed and deployed in an international oil company. The system architecture was designed in 4 sections: unstructured data processing unit, database and management system, KPIs extraction engine and data visualization dashboard. Unstructured data processing unit was designed to convert reports form heterogeneous data sources to the main database, including Excel, pdf and isometric databases. A 5-layers data quality control procedure was designed to ensure the reliability of data for KPIs analysis. Specified extraction algorithms was designed considering several realities, such as reports or data missing, and data error. A distance-based model to evaluate the similarity of two wells by well properties was developed, providing an intelligent way for benchmark and knowledge sharing between wells. A drilling anomaly detection model was developed by deep learning and natural language processing to solve the problem of ununified coding system in different fields. A data visualization dashboard with high efficiency, reliability and flexibility was designed to provide information for different users. By deploying the system, tens of thousands of daily reports from heterogeneous data sources were automatically incorporated to the main database, and millions of dollars of manually processing cost were saved. The data analysis standard was unified by the system, making it possible for benchmarking and knowledge sharing in different oilfields. Thousands of wells’ information was activated by the system, and the outputs provide support for management optimization, technical improvement, drilling performance benchmarking and feasibility evaluation of new investment. The time for users to analysis the KPIs of a field was shorten form several weeks to almost zero and the data quality was validated and improved in real time by the feedback of KPIs analysis. A 7-layer convolutional neural network was trained based on 1700 wells’ data to detect anomaly in daily reports with accuracy of 85%. A new distance-based model was developed to evaluate the similarity of two wells.

Abstract Typically, Owners beef up their Project Management/Controls organization and develop Project Execution concepts once a development concept has been selected and Basic Engineering gets well under-way. It is observed that Owner's Schedule & Cost influence is high, while expenditure of either is low during Concept & Planning phases as against during the Execution phase. This work proposes elaboration of a number of key project dimensions, collectively called integrated Front-End Loading (iFEL), enabling PM diligence during Conceptual and Scope development phases, overcoming the traditionally limited visibility to PM added value in these phases by not limiting PM resource investments, while keeping the ever-evolving scope, risk, complexity challenges in perspective. A purpose-built Project Management Organization (PMO) implementing the above methods and administering the various procedures during the Feasibility/Concept, pre-FEED (Front End Engineering Design) and FEED phases can assume control of the value levers, improve predictability of the desired project outcomes and set the project on course for EPC (Engineering, Procurement & Construction) execution success as demonstrated by reference project(s) that adopted this approach. This work proposes establishment of a dedicated, technically competent and scalable PMO during Pre-EPC phases to oversee front-end scope definition, maintenance of a list of big-ticket decisionsto be landed during each phase, securing of key resources, contracting strategies, formulation of a proactive management response system and overall value assurance. The PMO can then suitably scale-up and assume back stopper duties during EPC(M) (Engineering, Procurement, Construction Management) follow-up, delivering on project promises that led to the investment decision.

Abstract As capital projects execution is increasingly transformed through digitalisation, there are further opportunities to optimise the efficiencies and effectiveness of Engineering, Procurement, and Construction (EPC) phase maintenance, and integrity management programme development. This paper presents a model for the development of lifecycle maintenance and integrity management programmes during the EPC phase. The approach comprises a fully integrated solution for all required work scopes. This model is embedded within an asset management build platform and has been designed to encourage collaborative working and maximise efficiencies during execution. The approach enables the provision of clear information to the EPC project team highlighting the critical path data requirements and schedules. This provides enhanced definition of Computerised Maintenance Management System (CMMS) build processes, smoother project management, improved consistency and accuracy of the asset register, hierarchy build, materials, inventory content and linkages. Requirements for manual data scraping from engineering drawings, datasheets and vendor documentation have been substantially reduced. Instead, the approach maximises opportunities to standardise and digitise much of data handling and capture required for successful programme development. The model incorporates simple, robust rulesets for lifecycle maintenance and integrity management strategies, which consider aspects such as: class code, equipment sub-categories, materials, and operating context. This has resulted in consistent, standardised programme development and implementation, while accounting for owner/operator specifications and requirements. Furthermore, the data deliverables and outputs can be used as a basis for CMMS management of change during the subsequent operating phase.

Abstract Over the past decade, breakthroughs in digital technology have rewarded a variety of industries with a step change in productivity and efficiency. Despite this, the drilling industry has yet to benefit on a large scale from these advances and a significant amount of value remains untapped. This paper details the effort of a service company to leverage modern technology by introducing a drilling automation system in pursuit of achieving a higher degree of consistency and efficiency. The drilling automation system described in this case study was deployed in the Middle East on two onshore gas drilling rigs in 2019. The deployment was an opportunity to validate the potential of modern drilling automation technology and prove its ability to consistently deliver value. Since the company had extensive experience in the region, the Middle East was selected as the preferred location for field trials. This ensured that the value of automation could be precisely quantified as performance benchmarks were well documented and available for comparison. The automation strategy relied on an intelligent decision management system capable of dealing with constantly changing drilling conditions in order to implement efficient, consistent, and standardized well construction operations, while enhancing safety and reducing NPT. When given authority, the system would take control of the rig surface equipment to enable full automation of most drilling actions and engage optimization engines to monitor and adjust parameters to maximize performance. The system was leveraged to eliminate the variability innate to humans and deliver consistent results, while consolidating the improvements, performance gains, and lessons learned that otherwise would tend to disappear or erode over time or through personnel replacement. Throughout this document, insight is provided into the technology itself, the deployment process, implementation challenges, the agile development model, and the results achieved. In addition, as the introduction of automation is a major departure from the traditional human operated drilling process, an emphasis will be placed on the results of the change management strategies utilized.

Abstract Oil and gas projects often experience delays in startup due to an ineffective transition from construction to commissioning and startup activities. Traditionally, engineering, construction and procurement (EPC) contractors are responsible for a project from detailed engineering through commissioning and startup of the facility. This paper will compare how engaging a dedicated completions and commissioning team early and independently from the EPC contractor can impact a project's risks, cost, predictability, and successful startup. The authors examined the lessons learned from an engineering and construction company with specialized completions and commissioning capabilities when contracted to join traditional EPC projects after those projects reached a state of distress—often due to schedule overruns. The lessons learned consistently demonstrated that the EPC contractor had not properly considered the commissioning and startup sequence, tasks, and requirements during the detailed engineering and construction phase of the project, thus losing the opportunity to mitigate risks associated with these activities. A key contributor to the risks was the lack of commissioning and startup experience amongst the EPC engineering and construction personnel, given the unique nature of the facilities, licensor, and vendor technologies. The budget and schedule are often overrun at the final stage of the project, resulting in a confrontational relationship between EPC contractor and client. To avoid this dynamic, an end user could consider engaging a commissioning and startup specialist contractor under the leadership of the client-appointed Commissioning Manager. Utilizing alternative procurement models for such a contract include Day rates for competent and skilled personnel who join with end user to form integrated teams Day rates for competent and skilled personnel in addition to a fixed fee based on agreed performance metrics and set management/running costs Appointing a dedicated commissioning and startup contractor early in the life cycle of a project ensures there is a focus on the primary goal of a successful startup of the project. Early engagement facilitates Early trust building with construction counterparts Identification of 3D-model design improvements to aid commissioning through modifications in construction and fabrication phase to maximize schedule and budget savings Identification and sharing of commissioning subsystem boundaries, being part of design reviews with construction to align system sequence priorities Identification of temporary systems to allow for early order of commissioning consumables, mitigating schedule impact Running of what-if scenarios for the commissioning and startup phase A growing trend is to combine a training program with the commissioning and startup contract. This ensures the end user workforces are trained and introduced to the new facility through integration with the commissioning team for orientation and through practical work experience on the new assets/units. This increases the chances for continued success during steady state operations, as the operations team will have been actively involved at site during the commissioning and startup phase.

Abstract The brownfield projects deal with existing facilities/assets to upgrade or modify. These projects can be minor (e.g., change a few cable trays) to major (e.g., remove an old gas turbine). These projects are smaller in Capex spending compared to new greenfield projects, and sensitive to completion schedules, because of the facility's operational/production state. Normally some of the work is performed during shutdown of the facility, so there is economic pressure to resume operations as soon possible. Eighty percent of these projects are schedule-driven, and cost is relatively high if benchmarked with green field projects, which are usually cost-driven projects. There is a need to plan and execute these projects to optimize the cost and schedule, to achieve company's financial goals and production targets simultaneously. These strategies may vary from project to project, and there are many common actions that can be applied to all brownfield projects. It is a challenge for the project management team (PMT) to execute a brownfield project within the planned budget and schedule, due to uncertainties and constraints. In this paper we will discuss the risks and challenges faced by brownfield PMTs, and how to mitigate risks with planning and execution strategy at different stages of the project life cycle: i.e., concept selection, FEED, detail engineering, project proposal, contract award, execute construction, and commissioning of the facility.

Abstract The continuous and rigorous endeavor in identifying key project successes or failures has been one of the most celebrated effort within the fraternity to advocate good project management implementation. Although the delivery method is unique from one project to another, perceivably there is no right or wrong formula that ensures outright success. It is often regarded that having an exceptional project manager leading a team that pays attention to collaboration between the project team and the contractors or manufacturers, guarantees a successful project delivery. What is rarely looked upon is the contribution of the operations and maintenance personnel embedded as part of the team, which plays a vital role to the smooth and seamless transition from the task-oriented project, to the product-oriented operations and productions phase. Early involvement of this sort enables majority of the pain points anticipated during commissioning, start-up and finally during the handover period to be addressed much earlier during detailed engineering and construction phases. The accomplishment of the recently completed Spheripol and Spherizone polypropylene units as part of the giga-project Refinery and Petrochemical Integrated Development (RAPID) which is located within the Pengerang Integrated Complex (PIC) in Malaysia, gives us the best insight on how project delivery can improve and flourish by putting the emphasis on small things that matter. Standing at USD 27 billion, PIC, the largest downstream investment by PETRONAS in Malaysia, consists of an integrated refinery and petrochemical complex, supported by several facilities which includes a raw water supply and treatment plant, an air separation unit, a cogeneration plant, a deep-water terminal and a regasification terminal. Like other plants complexes, it also has its own centralized utilities facility. Not many would think that setting the operational elements and getting the operations personnel involved as part of the team prematurely, will minimize technical gaps once the facility starts its operations. However, this unique approach has proven to be effective and successful for a major integrated project like RAPID. The operational elements mentioned above include progressive participation and deployment of operations and maintenance personnel during front end and pre-award of execution contracts, assurance reviews (engineering, constructability and safety) and mechanical completion walkdowns. This gradual involvement evolves into a full leadership role during commissioning up until the process of starting up the plant. This study will show how the close collaboration between projects and operations teams, towards the successful delivery and integration of RAPID polypropylene plant can never come too early.

Abstract This paper will discuss proven methods that can be utilized to develop an optimum well surface facility program, which will reduce the overall program cost, schedule, and labor risk. Well surface facilities are currently custom designed and constructed (with each design being slightly different), and as a series of projects rather than a single program. The custom design for each project increases the cost and construction timeline of the well site facilities. Although there may be slight production design differences in the sub-surface design, the surface facilities can be standardized by understanding the sub-surface production design ranges. The key to optimizing well surface facilities is to standardize the equipment and components within the facility and maximize the use of building blocks or modules. The following four methodologies can be used to develop an optimal well site: Standard Design Package and Catalog Development This method involves developing standard design packages for the building blocks of a well site and generating a standard catalog for the well site program. This standard catalog will reduce the engineering hours on repeatable well sites and reduce the project timeline up to 75%. Implementation of Standardized Tagging Developing standardized tagging for the well site program will provide a system for equipment and instrumentation to be purchased without a specific well site location. This method promotes agility in the design, purchasing, fabrication, maintenance, and operations of asset procurement. In addition to procurement, it also allows for an effective asset management program for operations and maintenance, as both the tags and vendor data are standardized. Program Level Contracting and Procurement Developing a standard vendor data library will reduce the overall timeline required for equipment and instrumentation production cycles, eliminate duplicate information, and reduce data handling costs. This will create opportunities for phased delivery and bulk purchase pricing discounts based on the yearly requirements. Another key component of this method is developing subcontractor partner relationships that are aligned for program delivery. Optimized Modularization and Construction The standard design packages can be fabricated and assembled as pre-assemblies or modules. Site labor will be moved offsite, reducing labor risk, and pre-assemblies or modules can be standardized, fabricated, and assembled independent of the well site location. This method will allow for both program flexibility and mentality, as well as provide future flexibility to enable the relocation and reuse of modules from decommissioned sites to new sites. Standardization and modularization methods have proven benefits for well surface facility programs that include, but are not limited to the following: Reduced cost, including significantly reduced home office costs Reduced schedule, including removing engineering, material, and fabrication from the critical path Increased well program flexibility Improved cost and schedule certainty Strict Change Management and value improvement system An optimal well surface program utilizing the standardization and modularization methods can realize the benefits described and reduce the facility total installed cost from 10% to 30%, depending on the extent of standardization utilized versus traditional project executions.

Abstract Smart field instruments (sensors & valve positioners) are the main digital data source required for modern day predictive data analytics tools and frameworks. Apart from communicating the measurement value, there are many additional features available within the smart field devicessuch as sensor diagnostics, remote set up, commissioning, trouble shooting and calibration, all within the same 2 wire used for the signal communication. This paper summarizes the challenges faced in the journey of realizing the benefits of smart field instruments diagnostics using Highway Addressable RemoteTransducer (HART)open protocol as part of Instrument Asset Management System (IAMS).

Abstract This paper is to highlight the success offshore installation campaign of D28JT-A and D18JT-D platforms utilizing Jack-Up Rig (JUR) and the technical challenges during offshore execution. The installation work limitations and difference in installation sequence are also presented in this document. Light Weight Structure (LWS) has become one of the novel alternatives and cost-effective solutions for marginal field offshore facility in the recent years in meeting tight budget for Final Investment Decision (FID). The basic concept of LWS is to design the topside and substructure that could be lifted by JUR for installation. Hence, a minimal facility design approach was selected for this project due to limited capability of the selected JUR. While the basic principle of load out and transportation remains the same, methodology and systems used to execute the offshore installation campaign are vary significantly. This concept has posed numerous technical and operational challenges. PETRONAS Carigali Sdn. Bhd. (PCSB) has undertaken the development of D28JT-A and alliance with partner for D18JT-D development. Both projects are located at offshore Sarawak in Malaysia. D28JT-A and D18JT-D are wellhead platforms utilizing design one and built many concepts where both platforms were similar in design with only difference in weight. Both platforms were installed by the same JUR. The installation work required high precision engineering and execution especially during topside lifting considering the close proximity (≪ 1 meters) between substructure and topside. Position Monitoring System and Weather Monitoring System were essential and closely monitored for safe work execution. Transportation marine vessel dynamic positioning (DP) system checks were conducted prior approaching the substructure. Both Topsides were lifted and set down within 3.25 hours. These projects had successful HSSE track record with zero LTI or incident. It is proven that the installation of light weight structure by JUR is technically feasible and become a benchmark for future projects especially for marginal field development. Utilization of JUR for offshore platform installation significantly reduce the offshore installation cost due to JUR daily charted rate (DCR) and sharing mobilization and demobilization of installation and drilling campaigns. This paper should be an interest for marginal field development utilizing "fit-for-purpose" design facilities.

Abstract Will oil and gas operating companies or EPC industries attempt to invest in a new project in this difficult market situation, when they are not sure about the success of the projects due to high uncertainty of the market and changing priorities of the market? Any success of the organization/project expects business value such as measurable improvement to revenue, profits or net income, automation to improve productivity, new product release, reduce inventory costs or some other targeted outcome. Our paper delves into the interconnection between the above two statements. The Standish Group 2015 CHAOS Report (ref- 1 ) states that, out of 50,000 projects in the study, 71% failed to meet the major success factors viz: on time delivery, completion within budget, and satisfactory results. The problem is even worse for big projects. When 91% of Medium-sized projects failed, the failure for larger projects reached a whopping 94%. That is scary since PwC reported that capital projects and infrastructure spending between 2014 and 2020 could reach $29 trillion. Does this mean that $27 trillion is at some risk? That's crazy! Are we doing anything about this? This 71% failure rate reflects the expected outcome of all project including small, medium, and large. A project/organization that does not meet or exceed expected business value is considered as a failed project/organization. Our view of project success is relatively straightforward. If you do what you are asked to do as per the project scope, then you should be on time and on-budget. If you deliver what you have committed to deliver, then you should achieve or exceed the business value promised. Of course, this is in the assumption that the bid is made properly. Proper bidding is very important for the successful execution of the project up on award. Clear understanding of the scope, identifying the major risks if any, defining the execution strategy including the execution centers (100% local, 100% overseas or blend of local and overseas execution centers) etc. are the important aspects that should be well thought of and defined in detail in the proposal submitted to client. An efficient hand over of the proposal to the execution team up on award should be done to ensure that the assumptions, execution strategy etc. are effectively communicated to the execution team.

Abstract One of the major challenges of oil and gas mega projects is the claims management process. This paper will discuss how claims, which arise during the lifecycle of a project, can be managed by both the contractor and by the procuring entity. This is particularly relevant to the industry with the recent Covid-19 events and its impacts. This paper will evaluate and discuss key risks in the implementation of a project – including project cost escalations as well as time overruns and delays to completion of the project or its milestones – and the management of claims in relation thereto. This paper will also discuss how risks may be allocated where a project may be derailed. Secondary impacts will also be considered such as a compromise on quality and potential defects. Lastly, this paper will cover how formal disputes, which arise when claims cannot be adequately resolved, may be brought about and the best position the procuring entity and the contractor can put themselves in for such proceedings. This paper shall conclude that an optimised "life cycle" approach to procurement is essential. From the beginning of the project, companies should carefully consider how risks are allocated, and from a practical perspective, what the most material risks are that are either likely to occur or could have a significant impact on the project, to ensure in particular that management of those potential risks and impact are adequately addressed in the project documents. During the life of the project there mustbe efficient contract management, it is crucial for the project management team to proactively manage claims in real time to avoid disputes. Lastly, it is key that the company is prepared for formal dispute resolution proceedings by reviewing its position regularly and keeping options open. This paper draws on our legal expertise based on our vast experience in the field. Based on this experience, this paper applies that knowledge to what is critical in the management of claims throughout the lifecycle of the project. This will assist companies to allocate risk accordingly, mitigate and manage claims and prepare for potential formal disputes.