Abstract Objectives/Scope A system providing a standardized and automated approach to rapidly screen and rank large well count assets (hundreds or thousands of wells) in a fraction of the time and repeatably, is proposed. The solution enables the proactive management of existing wells by keeping the production enhancement opportunity pipeline full and expediting potential candidates through the Opportunity maturation process (OMP) in an integrated and collaborative framework. Methods, Procedures, Process The solution is based on a hybrid and automated decision-support system anchored in a knowledge-based framework. Hybrid refers to the integration of (1) petroleum engineering analysis methods and best practices with (2) advanced machine learning algorithms for autonomous well performance signature identification, and (3) the operator's business logic driving the economics of the field. Automated alludes to a continuous running workflow requiring minimal interaction, utilizing machine learning approaches such as neural networks, bayesian belief network models, logistic regressions, advanced optimization, etc. Results, Observations, Conclusions The application of the proposed solution led to workover and intervention candidate evaluations now routinely performed on a weekly basis (compared to the previous bi-yearly approval review and approval process across almost 200 well completions, with engineers confirming and validating the system-generated opportunities before escalating them for approval. Moreover, in its early evaluation, the new system has provided 89% in time savings in both the identification and review of intervention candidates and 88% in cost savings resulting from the elimination of manually tedious and routine work. Novel/Additive Information Asset teams are entrusted with proposing enough well production opportunities on a regular basis. The identification of potential workover candidates remains a manual, tedious and repetitive process consuming several weeks of engineers’ time in every iteration. With the addition of the proposed solution in the existing body of literature, asset teams can proactively manage opportunities in their fields.

Abstract Recent advancements in the field of data science, digital technologies and their applications are presenting new opportunities for marine and offshore fleet operators to adopt a more effective asset management strategy that combines advanced data analytics with maintenance and operational experience to reduce unplanned downtime. Advanced data science and analytics enable timely detection of deteriorating equipment behavior, which in turn optimizes the scope of maintenance activities and planning based on asset condition. When used within a reliability-based maintenance program, they further provide the foundational elements for building an enhanced platform for efficient risk-based decision making and better understanding of asset health and performance. This information can be useful for classification societies to be able to make better class related decisions and make the class experience more targeted for 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 It is a common knowledge that the main goal of companies is to supply goods and services to buyers at maximum price for minimum cost. For companies such as energy producers, with complex and dynamic supply chains, this often causes cost control issues. Previously, business models based on VI (Vertical Integration) or outsourcing could mitigate cost increases, but these models have limits. A new paradigm is proposed: use of distributed ledger technology in the form of a blockchain-based supply chain integration solution. By permitting participants in a supply chain to integrate information flows in a secure, quick and automated levels of efficiency that are achieved and cannot be reached by other technologies and do not require participants to change their IT platforms. The main purpose for the creation and management of the "supply chain" is for the seller to provide the buyer the maximum value – whether of a product or service – at the lowest cost. Here is a depiction of the "links" in the general supply chain for energy production.

Abstract Objectives/Scope: Please list the objectives and/or scope of the proposed paper. (25–75 words) The intent of this paper is to recognize and address the challenges that downstream companies face across their value chain including a history of having siloed businesses processes that have created ‘value leaks’. We propose an unified operations management approach that orchestrates all activities across the value chain as part of an enterprise digital transformation strategy. Business process can be deeply transformed when operations, supply chain and process optimization are connected in a collaborative environment. Methods, Procedures, Process: Briefly explain your overall approach, including your methods, procedures and process. (75–100 words) Refineries are at different stages in their digital transformation journey and have built their business workflows over many years across multiple point solutions. We propose a digital transformation strategy for operations across five key characteristics, that is: Comprehensive: an enterprise solution across all layers of the value chain that breaks down business silos and creates collaboration Flexible: allows businesses to start at any point in their own transformation journey with solutions for each specific component of the value chain Connected : opens new possibilities and workflows to drive unique business process improvement Modern: leveraging latest technologies for the best user experience, an agile performance and focus on reducing cost of ownership Transparent: visualisation and advanced analytics that improve management decision making across the value chain Results, Observations, Conclusions: Please describe the results, observations and conclusions of the proposed paper. (100–200 words) Across a refinery's value chain there are significant benefits that can be realized by approaching digital transformation across their operations enabling end-to-end value chain optimization including: Supply Chain ($20-150M/year): ○ Crude Purchases - Reduced cost of purchases, reduced maintenance ○ Planning, Scheduling and Logistics: Increased throughput, increased yield Process Performance ($10-50M/year): Longer equipment life, increased availability, increased quality, increased yields Blending and Oil Movements ($5-50M/year): Reduced giveaway, no rework, minimum inventory, minimum downgrades, higher fuels agility Energy Management ($5-25M/year): Reduced energy conversion cost, reduced energy consumption cost, reduced cost of crude for energy Production Management ($2-5M/year): Reduced accounting losses, reduced inventory, reduced hydrogen and steam consumption, increased throughput Operations Management ($2-5M/year): Reduced unplanned shutdowns, increased yield, reduced hydrogen and steam consumption, increased throughput Novel/Additive Information: Please explain how this paper will present novel (new) or additive information to the existing body of literature that can be of benefit to and/or add to the state of knowledge in the petroleum industry. (25–75 words) This paper is novel as it takes a wholistic look at a refinery operations value chain and eliminating existing value leaks end-to-end. It recognizes how existing systems have been built-up on outdated technology and siloed business process and proposes a path forward bringing operations, supply chain and process optimization together as a key element of a digital transformation strategy. The paper also explores how AI & prescriptive models pave the future for optimization.

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 paper elaborates the utilization of a novel 6 × 6 Occupational Health Hazard Risk Rating matrix developed for oil and gas operations,enhancing the determination of occupational health hazards as comparedto a5 × 5 matrix in terms of clarity on severity and likelihood criteria. This paper describes how severity ratings were redefined, and how likelihood ratings were divided into qualitative and quantitative approaches. To establish the severity rating definitions, health effect ratings were benchmarked from international industrial hygiene association guidelines, peer-reviewed literature, and hazard rating categories from oil and gas operations. The qualitative likelihood scheme was developed considering evaluation methodologies for various physical and ergonomic hazards, as well as formulation of control bands for biological and chemical hazards. The quantitative likelihood scheme was based on the concept of the 95% upper UCL of hazard exposure data and evaluating it against its OEL. From the previous five (5) Severity of Harm categories (i.e., Minimal, Minor, Moderate, Major, Extreme), six (6) classifications were developed (i.e., Notable, Minor, Serious, Major, Catastrophic, Disastrous) specifying documented health effects posed by a workplace health hazard. From the previous five (5) Likelihood of Harm categories (i.e., Rare, Unlikely, Possible, Likely, Almost Certain), six (6) qualitative likelihood classifications were formulated (i.e., Very Low, Low, Medium/Moderate, Moderately High, High, Very High) considering current evaluation schemes for physical and ergonomic hazards and control banding for biological and chemical hazards. In addition, six (6) exposure bands were created by defining specific exposure rating categories based on an estimate of the 95% UCL relative to a health hazard’s OEL. Finally, the previous five (5) risk ratings (i.e., Extreme, High, Medium, Low, Negligible) were consolidated into four (4) risk levels (i.e., High, High-Medium, Medium and Low), with each level differentiated according to the control measures required and the exposure monitoring frequency requirement for the workplace health hazard. The health hazard risk rating matrix is envisioned to make health hazard risk assessment process simple, more accurate, user-friendly, and consistent with international best practices for the following reasons: use of 95% UCL is the most appropriate metric to evaluate exposures on the upper tail of an exposure distribution as it acts as a reference point in assessing the exposure profile’s arithmetic mean with a health hazard’s OEL; new severity rating definitions mirror the actual health effects posed by a health hazard; and qualitative likelihood rating is reflective of globally accepted exposure assessment methodologies and control banding schemes.

Drilling and completing wells for hydrocarbon production comprise the major cost of well operations. Slim-hole drilling can significantly reduce drilling costs, making low producing reservoirs economically viable. However, a number of challenges are associated with slim-hole wells. A major challenge encountered while deploying lower completions in long horizontal slim-hole wells is stuck pipe, as the wellbore diameter is less than six inches, allowing restricted clearance between the wellbore and completion equipment. Stuck pipe incidents can cause significant non-productive time (NPT), additional high costs, and the possibility of compromising the well objective. Stuck pipe incidents may require sidetrack operations in the worst cases, which may considerably change the planned well design and delay the overall project, along with increasing costs. Drilling in the minimum stress direction with heavy mud weight and high overbalance pressure adds to the challenge in deploying completions in HPHT slim-hole wells. While deploying the lower completions in slim-hole wells, many factors come into play and each factor has a critical role in the success of the operation. After conducting a detailed study on several HPHT slim-hole gas wells in Middle-East region, a risk matrix was developed for a specific well-bore diameter, by identifying some common variables. Based on potential chance of occurrence, a certain value was assigned to each variable. The risk mitigation plans are driven by the risk matrix variables. Using this risk matrix, the occurrences of stuck pipe incidents in critical HPHT slim-hole wells that initially tend to have high chances of stuck pipe were significantly reduced. The risk matrix presented in this paper successfully mitigated stuck pipe incidents from occurring and has saved millions of dollars in associated costs. The matrix played a key role in operator's drilling operations and was adapted in operations as an important tool to evaluate final wellbore conditions prior to selection of the optimum completion type. This paper presents a highly effective risk matrix that significantly minimizes stuck pipe incidents during drilling/completion operations of slim-hole gas wells.

Way of working is continuously changing in O&G field thanks to digital solutions and the possibility to have consistent data driven analysis to support decision-making process. Well Construction cycle from planning to execution and post well analysis is evolving as well, since data are at the base of all the analyses allowing higher operational safety, more efficient engineering, better real time optimization and more effective comparison of performances at the end of operations. Eni Well Operations Department has invested a lot in advanced analytics tools able to extract value from historical and real time data focusing the attention first of all on data coverage, quality and reliability, that are extremely important enablers to let the tools work and perform analyses, and then on proper data transmission system from different rig site locations towards a centralized database. High frequency performance measurement and data intelligence tools allow reaching the technical limit, predictive analytics help in reducing downtime while drilling and well simulation software enhances not only planning phase but also operational real time follow up activities. Applications of digital solutions have run in 2019 on most challenging activities with tangible results in terms of safety improvement, operational efficiency and time and cost savings. Almost 50 wells (more than the totality of most complex wells as per Eni classification) have been analysed in real time with both advanced analytics and predictive algorithms achieving: avoidance of specific Non Productive Time events (about 25% of NPT reduction), with a major impact on operational safety better performances throughout development projects, thanks to an improved learning curve and a reduction of Invisible Lost Time (average of 2,5% of time saving per well) enhanced real time monitoring and early detection of well events, leading to a faster decision making and adoption of corrective actions (anticipated actions by average 6 hours) The development and the application of these tools have been made possible thanks to a proper Data Management System. In fact, several initiatives have been put in place to provide proper data gathering, data transmission, data quality check and assurance and data storage. This paper will show in details how the results have been obtained starting from creating an appropriate data infrastructure up to real case of application along 2019 Eni drilling activity. The extensive use of digital tools, both in Geographical Units and Headquarters, has been proven to provide effective support to plan, monitor and evaluate performances during all well operation activities.

Global economy faces various challenges, ranging from pandemics to economical instabilities, from rapidly growing regional economies to the nations aggressively competing to be cost competitive for capturing the global markets. Ripple effect of these factors directly impact the global energy demand and hence make the Oil & Gas commodity as one of the volatile business sector. To embrace the uncertain market conditions from increased energy demand to abrupt global Lockdowns as the world faced in 2020 due to COVID-19, companies face challenges to survive by re organizing, managing, aligning and integration of multi discipline, multi-functional and multiple-location activities and strive to achieve organization goals and business objectives. An integrated approach for managing various critical activities and accordingly the business impact analysis are the main pillars of a successful business continuity plan. In offshore upstream business one of the main challenge usually faced by Management & stakeholders is to have one consolidated long term look ahead plan comprising of Brownfield / Green field major activities related to Production enhancement (Drilling and hook ups), Projects, Asset Integrity, major Maintenance, Planned Shutdowns/turnaround, Reservoir Management & Monitoring etc. in order to provide precise input while preparing the 5 Years Business plan, Yearly Budget of Business Unit & frequent Inputs while finalizing the 3 monthly FSOPR. A rigorous road map is essential with effective interaction among the stakeholders to optimize the multiple planned outages, in field movement of Barges & Rigs, clashing of different construction activities, effective follow ups & progress monitoring for proactive look ahead with effective resource planning, OPEX & CAPEX Budget optimization. Master Integrated activity planning (MIAP) is a proven approach for dealing with complexity and uncertainty when operating complex production systems. MIAP is driven by the need to deliver on production forecasts, optimize the decision making for the planning, scheduling and execution of activities impacting production, mitigate the risk associated with major shutdowns or bringing projects online and optimize interfaces to allow engineering, drilling, projects, maintenance and operations etc. to work together seamlessly. MIAP provides opportunity to Maintenance support team to view the upcoming major maintenance activities with an opportunity to align with corrective maintenance, Plant modification, projects tie-ins while avoiding required plant shutdown. This allows activities to be scheduled effectively and optimized the multiple shutdowns. Major Maintenance / Major Overhaul execution planning can start well in advance of the actual start of the activities. In addition to that, MIAP provides the opportunity for site and maintenance support teams for closely track spare parts availability of critical equipment. MIAP provides opportunity to identify and assess if any SIMOPS operation is required by looking at the plan where Drilling Rig is available with producing tower and take necessary preparations considering all HSE and facility integrity standards requirements.

Recent advancements in the field of data science, digital technologies and their applications are presenting new opportunities for marine and offshore fleet operators to adopt a more effective asset management strategy that combines advanced data analytics with maintenance and operational experience to reduce unplanned downtime. Advanced data science and analytics enable timely detection of deteriorating equipment behavior, which in turn optimizes the scope of maintenance activities and planning based on asset condition. When used within a reliability-based maintenance program, they further provide the foundational elements for building an enhanced platform for efficient risk-based decision making and better understanding of asset health and performance. This information can be useful for classification societies to be able to make better class related decisions and make the class experience more targeted for operators.

Objectives/Scope: Please list the objectives and/or scope of the proposed paper. (25–75 words) The intent of this paper is to recognize and address the challenges that downstream companies face across their value chain including a history of having siloed businesses processes that have created ‘value leaks’. We propose an unified operations management approach that orchestrates all activities across the value chain as part of an enterprise digital transformation strategy. Business process can be deeply transformed when operations, supply chain and process optimization are connected in a collaborative environment. Methods, Procedures, Process: Briefly explain your overall approach, including your methods, procedures and process. (75–100 words) Refineries are at different stages in their digital transformation journey and have built their business workflows over many years across multiple point solutions. We propose a digital transformation strategy for operations across five key characteristics, that is: Comprehensive: an enterprise solution across all layers of the value chain that breaks down business silos and creates collaboration Flexible: allows businesses to start at any point in their own transformation journey with solutions for each specific component of the value chain Connected : opens new possibilities and workflows to drive unique business process improvement Modern: leveraging latest technologies for the best user experience, an agile performance and focus on reducing cost of ownership Transparent: visualisation and advanced analytics that improve management decision making across the value chain Results, Observations, Conclusions: Please describe the results, observations and conclusions of the proposed paper. (100–200 words) Across a refinery's value chain there are significant benefits that can be realized by approaching digital transformation across their operations enabling end-to-end value chain optimization including: Supply Chain ($20-150M/year): ○ Crude Purchases - Reduced cost of purchases, reduced maintenance ○ Planning, Scheduling and Logistics: Increased throughput, increased yield Process Performance ($10-50M/year): Longer equipment life, increased availability, increased quality, increased yields Blending and Oil Movements ($5-50M/year): Reduced giveaway, no rework, minimum inventory, minimum downgrades, higher fuels agility Energy Management ($5-25M/year): Reduced energy conversion cost, reduced energy consumption cost, reduced cost of crude for energy Production Management ($2-5M/year): Reduced accounting losses, reduced inventory, reduced hydrogen and steam consumption, increased throughput Operations Management ($2-5M/year): Reduced unplanned shutdowns, increased yield, reduced hydrogen and steam consumption, increased throughput Novel/Additive Information: Please explain how this paper will present novel (new) or additive information to the existing body of literature that can be of benefit to and/or add to the state of knowledge in the petroleum industry. (25–75 words) This paper is novel as it takes a wholistic look at a refinery operations value chain and eliminating existing value leaks end-to-end. It recognizes how existing systems have been built-up on outdated technology and siloed business process and proposes a path forward bringing operations, supply chain and process optimization together as a key element of a digital transformation strategy. The paper also explores how AI & prescriptive models pave the future for optimization.

Project schedule delay and cost overrun have become a normal matter to witness and at a certain point, it textures almost likely that it would be an inevitable result. Such result could be avoided if we identify the causes of delay and try to mitigate the challenges early phase in the project. An effective Project Manager manages all aspects of EPC project and he must understand the causes of problems. This case study aims to explore problems faced in EPC projects that lead to cost overrun and schedule delay, and to explore good practices to minimize impact on overall project. The methodology adopted consists of survey, interviews and case study approach. A survey was used to collect the common causes of EPC Project delays and cost overrun. An interview approach used to find out significant delay and success factors together with effective management practices collected from survey. Later, case study approach is used to validate the information gathered previously and to understand the relation and consequences of each factor. The interviewee were project managers, project controls manager, construction manager, discipline engineers, subject matter experts and client representatives, etc. from several EPC contractors and clients. There are several causes of EPC projects delay and cost overrun and every project may have its own challenges but many found to be common among projects. Sometimes, it may be a single trigger event that leads to delays or a combination of events. The case study reveals that major factors contributing to schedule delay and cost overrun are mostly related to project complexity, aggressive unrealistic schedule, weak or poor planning and control, inherited bidding inaccuracies and estimation mistakes, ineffective leadership and poor decision-making, absence of project management practices, etc. Also, design changes, delay in placing POs, lack of team competency, late client approvals, late vendor information, delay in PTW issuance, inadequate construction resources, quality issues and reworks, and ignoring previous project's lesson learned. Further most, poor risk management, poor interface management between project stakeholders contributes to cost overrun and delays. This case study findings may be helpful to EPC contractors, clients, project sponsors, project managers, construction managers and other stakeholders to understand the major factors, causes and problems that they may face during EPC project lifecycle and how to overcome such challenges effectively. This case study can be viewed as a lesson learned approach. This study will guide them in developing and adopting necessary effective and efficient project management practice to complete the EPC projects within budget, on schedule with good quality, and safety. Stakeholders’ awareness about causes of delay give them more options and improve capability in problem-solving throughout the project life-cycle.

Objectives/Scope A system providing a standardized and automated approach to rapidly screen and rank large well count assets (hundreds or thousands of wells) in a fraction of the time and repeatably, is proposed. The solution enables the proactive management of existing wells by keeping the production enhancement opportunity pipeline full and expediting potential candidates through the Opportunity maturation process (OMP) in an integrated and collaborative framework. Methods, Procedures, Process The solution is based on a hybrid and automated decision-support system anchored in a knowledge-based framework. Hybrid refers to the integration of (1) petroleum engineering analysis methods and best practices with (2) advanced machine learning algorithms for autonomous well performance signature identification, and (3) the operator's business logic driving the economics of the field. Automated alludes to a continuous running workflow requiring minimal interaction, utilizing machine learning approaches such as neural networks, bayesian belief network models, logistic regressions, advanced optimization, etc. Results, Observations, Conclusions The application of the proposed solution led to workover and intervention candidate evaluations now routinely performed on a weekly basis (compared to the previous bi-yearly approval review and approval process across almost 200 well completions, with engineers confirming and validating the system-generated opportunities before escalating them for approval. Moreover, in its early evaluation, the new system has provided 89% in time savings in both the identification and review of intervention candidates and 88% in cost savings resulting from the elimination of manually tedious and routine work. Novel/Additive Information Asset teams are entrusted with proposing enough well production opportunities on a regular basis. The identification of potential workover candidates remains a manual, tedious and repetitive process consuming several weeks of engineers’ time in every iteration. With the addition of the proposed solution in the existing body of literature, asset teams can proactively manage opportunities in their fields.

Aging facilities are a common issue within the oil and gas industry. This research demonstrates a practical approach to aging life extension, taking into account risks and constraints, such as budgets, resources and offshore field-level logistics. The case study reviewed is Mubadala Petroleum's (MPs) small, but aging, upstream offshore oil facility located in the Gulf of Thailand, known as the Jasmine/BanYen field. The field includes six offshore platforms, subsea pipelines and a Floating Production, Storage and Offloading asset (FPSO). The field, which commenced production in 2005, was initially expected to have a relatively short field life, and as a result, the facilities were genially specified for only a 10-year lifespan. As the field exceeded expectations in term of volumes and longevity, it became clear to MP management that a practical and cost effective life extension plan was necessary. As such, this research describes the approach to taken by MP to extend the life of the Jasmine/BanYen facilities. The approach taken by MP was closely aligned with the recommendations and best practices proposed by several regulatory authorities with extensive experience in managing aging offshore oil and gas facilities, such as the United Kingdom's (UK) Health and Safety Executive (HSE) and the Norwegian Petroleum Safety Authority (PSA). As such, the facilities were first functionally decomposed into a number of subsystems, such as Wells, Structures, Pipelines, Topsides, Risers and Floating Assets. A target life extension period was specified, which was followed by a series of focused risk assessments to determine the levels of risk expected during the life extension period, with the critical gaps identified. Each risk assessment involved specialist resources related to the subsystem under review, such as structural engineers, process engineers, marine engineers, instrument engineers, as well as technical safety and environmental engineers. For any risks that were deemed unacceptable, a mitigation plan was suggested and associated costs developed. Finally, a phased master plan was developed that took into account constraints while prioritizing actions based on the determined risk levels. The implementation of the plan was challenged by the intricacies of offshore logistics, including constraints on supply boats, Persons On Board (POB) etc., and budgetary constraints, which were considerable given the relatively high operational expenses of the field and the low oil price environment. As per the risk assessment, high priority activities were determined to be with respect to FPSO, well integrity and the integrity of subsea pipelines. The platform structures and topsides were considered to be lower priority, as they had already been verified for the life extension period by the company's Asset Integrity (AI) program. Additionally, MP also has a robust Safety Critical Element (SCE) system in place which is an integral part of the AI program, and as such there were no unexpected revelations with regards to the condition of the SCEs. Obsolescence was determined to be a low priority since the equipment on the platforms are relatively new, and most of the Original Equipment Manufacturers (OEMs) provided assurance on the availability of spare parts for the main equipment items. Highlights of the life extension plan are as follows: Production flexible riser connecting the steel pipeline network to the FPSO has been replaced Pipelines inspections are ongoing, and repairs are being prioritized The design life of platform subsea structures has been extended based on fatigue analysis Subsidence analysis has been carried out on all platforms and indicated no major anomalies Platform power generation facilities are progressively being upgraded A comprehensive well integrity systems have been implemented and critical activities such as barrier testing and well repairs are being carried out regularly Repairs to the hull of the FPSO have been carried out

In one of the green fields in Abu Dhabi a large unanticipated drop in reservoir pressure was observed just after initial production was started. Consequently, it was decided to conduct a comprehensive investigation in order to understand the field's complexity and the reason behind the pressure decline. Solutions for such challenging developments requires solid cross-discipline efforts. Field A has 3 stratified reservoirs producing for several years. Production started with natural depletion anticipating water aquifer will have strong impact on production. Although experiences from neighboring fields suggest that aquifer might play a key role in development mechanism, unfortunately a large pressure decline of around 600 Psi was observed after one year of production which would eventually approach facilities pressure thresholds. An integrated reservoir management team was established to give quick response in the shortest possible time implementing reservoir management best practices into an "Accelerated Pressure Restoration" WI project. The clear objective of WI implementation was to resurrect reservoir pressure with improved sweep efficiency extending plateau rate and increasing recovery factor, thus allowing wells to produce as per designed rate with natural lifting as long as possible. Based on the gathered data, new reservoir simulation results were obtained. Subsequently a ranking of the different production forecast scenarios were created. Various scenarios were generated including assessment of different production levels on natural depletion and water injection including implementation of artificial lift at a later stage of development. Based on technical feasibility, economic evaluation, reserves recovery, production plateau and facilities utilization, the well trajectories/completions were designed and hence proposed the most adequate water injection scheme for implementation. The water injection project follows a simplified VAP (Value Assurance Process), reducing the overall timeline of the project delivery and accordingly improving economics. Implementing water injection scheme at an earlier stage significantly increases NPV (Net Present Value) of the overall project and RF (Recovery Factor) when compared with the base case FFDP (Full Field Development Plan). Furthermore, drilling the water injection wells will give a clear picture of the structure and reservoir properties in the flank shedding light on just how complex these reservoirs are. During this study, major risks and uncertainties were recognized aiming to de-risk any further field development.

Historically, the preferred method for restoring production on oil producers in a mature field in South Europe (Field A) was bullheading a matrix acid stimulation treatment. Even if successfully implemented, bullheading treatments at matrix rate are not always optimum and, for Well A, it was decided to diagnose the producing interval first to deliver a better selective stimulation treatment through coiled tubing (CT). This paper presents a novel approach implemented and discusses its associated benefits. Real-time (RT) fiber-optic (FO) CT (RTFOCT) technology was selected to diagnose this well for such benefits. These include accessibility of the producing zone (horizontal section), pumping capabilities, and versatility in executing different well interventions using single equipment. The technology is composed of a FO cable preinstalled into the CT pipe and a modular sensing bottomhole assembly (BHA). In addition to be the telemetry medium for the sensing BHA, the FO can be used as a sensor for distributed temperature and acoustic sensing (DTS and DAS). Having access to downhole information in RT helped to implement the decision-making process more quickly. DTS and DAS were used to evaluate the reservoir performance before perforating and assessing well performance, post perforation and stimulation. The sensing BHA helped ensure accurate placement of the perforations and stimulation treatment using a RT casing collar locator (CCL) and gamma ray (GR). Monitoring the bottomhole tension and compression allowed the operation to be performed in a safer and more reliable environment. RTFOCT allows interval diagnostics, stimulation treatment, and evaluation in a single CT run. Having the RTFOCT available also allows quick reaction to unexpected well problems, making diagnosis and remediation easier and faster. Moreover, one of the main goals for well monitoring and field management consists of production optimization activities designed to decrease Water Cut (WC). This has been made possible thanks to the detailed downhole dynamic characterization of the specific water flooding zones coming from RTFOCT, which allows Operator to stimulate the matrix in the right zone to enhance well performance, as well as design focused Water Shut-Off (WSO) interventions. The focus of the paper lies in the capabilities of the Operators to effectively manage this new tool in order to perform downhole analyses in real-time. This enables potentially problematic or complex scenarios to be identified early on, allowing time to react before they fully develop, thus increasing the percentage of success of the planned job, as experienced in the case study presented.

The paper elaborates the utilization of a novel 6 × 6 Occupational Health Hazard Risk Rating matrix developed for oil and gas operations,enhancing the determination of occupational health hazards as comparedto a5 × 5 matrix in terms of clarity on severity and likelihood criteria. This paper describes how severity ratings were redefined, and how likelihood ratings were divided into qualitative and quantitative approaches. To establish the severity rating definitions, health effect ratings were benchmarked from international industrial hygiene association guidelines, peer-reviewed literature, and hazard rating categories from oil and gas operations. The qualitative likelihood scheme was developed considering evaluation methodologies for various physical and ergonomic hazards, as well as formulation of control bands for biological and chemical hazards. The quantitative likelihood scheme was based on the concept of the 95% upper UCL of hazard exposure data and evaluating it against its OEL. From the previous five (5) Severity of Harm categories (i.e., Minimal, Minor, Moderate, Major, Extreme), six (6) classifications were developed (i.e., Notable, Minor, Serious, Major, Catastrophic, Disastrous) specifying documented health effects posed by a workplace health hazard. From the previous five (5) Likelihood of Harm categories (i.e., Rare, Unlikely, Possible, Likely, Almost Certain), six (6) qualitative likelihood classifications were formulated (i.e., Very Low, Low, Medium/Moderate, Moderately High, High, Very High) considering current evaluation schemes for physical and ergonomic hazards and control banding for biological and chemical hazards. In addition, six (6) exposure bands were created by defining specific exposure rating categories based on an estimate of the 95% UCL relative to a health hazard’s OEL. Finally, the previous five (5) risk ratings (i.e., Extreme, High, Medium, Low, Negligible) were consolidated into four (4) risk levels (i.e., High, High-Medium, Medium and Low), with each level differentiated according to the control measures required and the exposure monitoring frequency requirement for the workplace health hazard. The health hazard risk rating matrix is envisioned to make health hazard risk assessment process simple, more accurate, user-friendly, and consistent with international best practices for the following reasons: use of 95% UCL is the most appropriate metric to evaluate exposures on the upper tail of an exposure distribution as it acts as a reference point in assessing the exposure profile’s arithmetic mean with a health hazard’s OEL; new severity rating definitions mirror the actual health effects posed by a health hazard; and qualitative likelihood rating is reflective of globally accepted exposure assessment methodologies and control banding schemes.

ADNOC is continuously enhancing its capabilities to manage its oil and fields efficiently by better planning, execution and operations that drives field development decisions, well performance, and safe operations. In this regard, ADNOC envisages to leverage the evolving Oil and Gas 4.0 technologies to enhance the well planning decisions of the sub-surface and drilling team through data-driven and AI methods. Effective well planning and operations require collaboration between different subsurface teams and drilling team leveraging multidisciplinary data, historical events and risks and constructing integrated drilling and sub-surface model for collaborative planning and keeping the model live. This requires having a live sub-surface model that is kept close to the field reality while reducing uncertainties. However, extracting key learnings, knowledge and experience from a variety of sources and reports is intense and requires lot of manual processing of data. An AI-based solution leveraging data analytics, natural language processing and machine learning algorithms is developed to automatically extract knowledge from a variety of data sources and unstructured data in building a live intelligent model that enables effective well planning, predicting operational hazards and plan mitigation. The solution systematically extracts, collects, validates, integrates, and processes a variety of data in different formats such as well trajectory, completion, historical events, risk offset well information, petrophysical data, geo-mechanical data, and technical reports. Newly acquired data comprising drilling events, geological and reservoir properties are integrated continuously to keep the model live and digital representation.

The aim of this abstract is to focus on the Maintenance Management System (MMS) that was implemented at ADNOC LNG to accomplish operation excellence, effective decision-making regarding maintenance activities, and utilization of the Risk Management Process to assure asset integrity and major production revenues. Risk-based MMS is a continuous improvement (CI) system to proactively prevent failures through the early identifications of risks, failure modes, failure criticality, and risk mitigation by utilizing cost effective predictive maintenance tasks and routines. Risk-based MMS effectively provides support for high critical decisions to assure asset integrity, minimize plant trips, avoid unnecessary forced shutdowns, and guarantee safe operations. Asset Integrity Management (AIM) is important in the oil and gas business because it ensures reliable assets, performance, efficiency, cost effectiveness, sustainable production revenues, and achieve business objectives and operational excellence. Maintenance, Operations and Engineering are the key partners and custodians to assure asset integrity in compliance with HSE. The very close interface between the three result in high levels of asset reliability and availability. In 2016 ADNOC LNG's Maintenance Division deployed the Maintenance Management System (MMS) driven by the Risk Based Reliability Approach. The objective was to perform consistent maintenance activities and asset integrity assurance by identifying risks and mitigations to reduce the risks in early stages to As Low As Reasonably Practical (ALARP). The MMS Policy and Strategy was developed on the foundation of the risk-based approach in line with ADNOC LNG's corporate objectives, ADNOC's code of practice, and internationally accepted best practices. The alignment of MMS with the Risk Based Approach was achieved by ADNOC LNG through successful implementation of Streamlined Reliability Centered Maintenance (SRCM) as a risk-based reliability asset integrity management tool. SRCM implementation achieved +98% reliability, cost reduction, work force utilization, proactive maintenance, and sustainable production. SRCM is mainly for rotating equipment, electrical equipment, and instrumentation. RBI (Risk Based Inspection) is already utilized for static equipment. The combination of both RBI and SRCM are successfully assuring the integrity of all assets at ADNOC LNG. The key topics, which will be focused on, are criticality assessment, risk management, and asset integrity management reliability system SRCM (Streamline Reliability Centered Maintenance). The main challenges to implement MMS were: receiving the team's buy in, making sure the team was aligned with MMS policy and strategy, and cultural challenges. The system was successfully deployed with consistent processes and procedures helping maintenance end users perform in accordance to best practices.