Like most business sectors, the oil and gas industry had to adapt to virtual meetings and working from home in the new reality of the global COVID-19 pandemic. This has introduced new complications to completing activities that traditionally require personnel to be on site and collaborate in teams. This paper reviews digital initiatives that allow workers to collaborate virtually on EHS (Environmental, Health, & Safety)-driven practices such as safety audits and engage remotely for improved morale. Specifically, the paper reviews the recent implementation of digital connectivity solutions for remote workers to join virtual ‘Safety Walk and Talks’ in processing facilities and offshore platforms. It also reviews programs to promote connectivity between workers, including virtual town halls and online coffee-hours conversations. While these digitally enabled remote engagement initiatives are still relatively new, they have quickly provided benefits to the safe operation of offshore assets and the morale and mental wellbeing of the workforce. The first virtual ‘Safety Walk and Talk,’ which was conducted in Indonesia, brought together a cross-functional team that was split between a few in-person attendees and a majority of people joining virtually from remote locations. While the digital connection was not seamless, this first-of-its-kind virtual meeting proved the concept. The process improves EHS metrics by minimizing travel of teams to and from the site. It also keeps more people out of potentially hazardous work environments and minimizes exposure to coronavirus or other health hazards. Other digital connectivity measures such as virtual town halls and worker-submitted videos have increased engagement between management, workers, and teams located around the globe. A virtual ‘Coffee Roulette’ program, in which workers spin a virtual wheel that connects them with other employees for informal chats, has allowed people to make new connections and feel less isolated.

This paper presents an evaluation of the topsides and jacket removal programme for Miller Platform decommissioning, which was developed not only to fulfil the UK’s laws and regulations but also to minimise the risks in safety, environment, technical execution, society and economics associated with the removal activities. Retrospective conceptual comparative evaluations of different removal methods are presented for both topsides and jacket removals to achieve safe, effective and economical solutions. The removal methods evaluated include the piece-small removal method, the piece-large removal method with a heavy lift vessel (HLV) and a marine fleet, the piece-large removal method using a HLV with extended lift operations, and the single-piece removal method with a specialist single lift vessel (SLV). The piece-large removal method using the HLV with the extended lift operations was chosen for the Miller topsides and jacket removal. The selected removal method was the first of its kind for a large structure suspended above the waterline, with no damping effect from the water column. The Miller removal programme described in this paper was successfully delivered in summer 2018. An overview of the engineering and planning execution is given.

Over the last decades, a number of mooring incidents have been reported in the public domain by conference papers and safety alerts. Mooring chain corrosion and fatigue have been reported as dominant incident triggers for these mooring incidents. Corrosion development is closely related to the locations of the mooring site. Fatigue is related toenvironmental conditions as well as mooring configuration for the mooring line load. This paper provides a review of the environmental conditions and water quality at offshore mooring sites. Important factors affecting mooring line load and load bearing capacity (mooring line degradation) are investigated. The ship-shaped FPSOs,as a dominant type of floating installationsand with more than two hundred of them currently in service,are the focus of this paper. The performance and uncertainties associated with the mooring system of the ship-shaped FPSO are evaluated.The paper provides recent industry advances onmooring performance simulations, monitoring and mooring incident identification techniques. It is recommended that risk-basedmonitoring and inspectionof mooring system can play an important role in improving mooring reliability and operational efficiency. The key elements includeidentifying critical directions of environmental loads, most loaded mooring lines, and the segments of the mooring line thatsubject to heavy corrosions. Systematical data collection, data sorting,data sharing and optimization of algorithm for anomalyidentification play important roles in effective monitoring.

Digital data collected by the oil and gas industry supports many, if not, most of its activities. Data integrity, security, mining, analysis, and transfer are critical to the industry. Related topics such as the use and management of massive data sets ("big data"), data value and ownership, cybersecurity, cloud computing, machine learning, and virtual twin modeling and simulation represent only a small subset of the derivative uses of digital data being contemplated by the industry. Why are they important for the O&G Industry? These are imperative discussion topics for the oil and gas industry because of the potential for significant improvements in safety, asset security and environmental stewardship. The opportunity for improvements in performance, availability, efficiency and profitability demonstrated in other industries holds promise for the oil and gas industry, as well. OTC is the world forum for revealing innovations, solutions, ideas, and emerging technologies. To continue this mission, an OTC program subcommittee was formed to organize panels over a three (3) year span to discuss these topics and their relevance to the oil and gas industry. A cohesive and coordinated approach sets the path to similar efforts that tackles other critical topics to increase the knowledge base and benefit from the experience accumulated in other industries, thus avoiding mishaps. The "Big Data" panels were populated by high level executives and technologists from all sectors such as: Operators, Service Companies, Equipment Manufacturers, EPC, and Academia. Each panel was built in three sequence stages: the first to raise awareness, the second to discuss challenges and successes, and thirdly to have an overview of success case studies and the future. The 17 panelists were requested to ponder and present their view of challenging topics: What is the current level of maturity for data collection enablers (i.e., sensing, transmission, storage, transformation, and processing) in the industry? Who "owns" data? How is ownership determined, protected, and transferred? Once data has been collected and its ownership established, what we do with it? How do we extract knowledge and value from collected data to benefit the operations, gain efficiencies, and improve safety and security? What are the business propositions that sensed data collection, storage, and analysis bring to the table? How much data is gathered? How much is repeatedly stored? How much collected data is transformed into actionable knowledge (data "yield")? At what level does a data set become "big data"? What makes big data useful and unique? How important is data security? How securely data is handled now? How securely should it be handled? How effectively data is analyzed? What data analysis methods and tools should the industry be adopting that aren't now being used? This paper will summarize the development of the topics and the answers to these questions providing valuable insights to the future of Big Data and Data Analytics for the Energy Industry, strategies being implemented by major energy players, and the role and actions needed to be taken by professional societies.

NASA pursuit of human missions Beyond Earth Orbit (BEO) to the moon and eventually Mars will pose many new challenges. These missions are characterized by increased risks to human performance due to stress, fatigue, radiation exposure, and isolation. Fundamental changes in spaceflight operations will be required as well. A very critical part of future missions will be assisting the crew with problem-solving and contingency resolution using next-generation smart spacecraft systems. Human Systems Integration (HSI) must be included as part of the systems engineering process. Gateway 1 will serve as part of the proving ground for maturing technology such as autonomous systems and space operations procedures to help meet moon mission goals and prepare humans for missions to Mars. For deep space missions, risk factors affecting humans such as mission duration, distance, and physiological/psychological effects, must be considered. A human is not a simple component but rather a system in a systems-of-systems application-a system influenced by cognitive and biological factors that are difficult to model/analyze. System complexity will demand an integrated approach that requires multiple viewpoints, including the understanding of the astronauts' capabilities and limitations to enhance safety, performance, and satisfaction on the interaction between all system users in a variety of environments to achieve acceptable mission goals and performance. HSI will play a vital role in the development of these future missions. This paper provides a discussion of HSI used at NASA and the critical role human factors engineering will play in the HSI process for future missions along with the challenges. Industries such as oil and gas (O&G) could benefit from the content of this paper to help improve the safety and operations of deepwater/oil and gas exploration activities. NASA engineering and human systems subject-matter expert personnel reviewed challenges reported in space-related environments for long space duration missions and identified similarities with the challenges encountered in deepwater exploration. The researchers noted the space industry's current solutions and proposed a system development view to solve future deepwater exploration challenges using HSI principles. This paper discusses the results of the review.

The first phase of the giant Johan Sverdrup project started-up in October 2019, several months ahead of schedule, more than 30% under budget and with a very good safety record. This paper focuses on the execution of phase 1 of this mega-project – from the concept selection and engineering phase, to the global contracting strategy, through the construction across up to 30 building sites globally and until the end of the completions phase offshore Norway – attempting to explain what went well and why, and highlighting potential lessons of relevance to other offshore mega projects on the NCS and globally. Among other things, the paper looks at the impact of different variables in explaining the improvements made during the execution of the project – market effects, procurement strategies, scope optimization and execution performance. The paper then shows that while market effects played an important role – in part reflecting a project being sanctioned at the beginning of the recent oil and gas downturn – the true driver of the success of the project is found elsewhere. As phase II of the Johan Sverdrup development is already underway, the paper also looks at efforts made to sustain these drivers of success into the second phase of the project. The paper also describes which parts of the improvement journey that may not be necessarily replicable in the next stage of the megaproject.

The offshore O&G production has been increasing considerably in the last five years. Therefore, to guarantee the safety of their operations, the O&G companies are being pushed by regulators agencies to establish a robust and efficient safety management system, particularly in Brazil, where the Petroleum National Agency published, in 2015, the SGSS (Technical Regulation of the Subsea Systems Operational Safety Management System). The new regulation forced Brazilian Operators, such as Petrobras, to promote a couple of initiatives, in order to increase the safety of their offshore operations. One of these initiatives has its focus into eliminate or minimize the risks in operational phase, maximizing the potential to avoid them during engineering design phase, where the ability to influence safety is higher than another project phase. One of the challenges of this approach is related to the fact that, in general, and regarding operational safety, the engineering design works in a passive way, in other words, the safety improvements in the new projects only are applied if a strong operational safety issues feedback process is established. Operators have been noted that this operational feedback to design engineers is not the only way to achieve a high level of safety in their operations and facilities. There is a consensus that the engineering design shall work in an active way, being more predictive than corrective, in order to avoid operational issues. The objective of this paper is present a new approach regarding the operational safety focused on engineering design phase, establishing new process, methodologies, actions and closing the gaps between design and operational teams to enhance operational safety.

As the Gulf of Mexico (GOM) fleet of Tension Leg Platforms (TLPs) ages, the need for more explicit Integrity Management (IM) and life extension guidance, particularly for the tendons, has grown. Recent industry efforts have developed Structural Integrity Management (SIM) guidance for fixed and floating systems, but tendon-specific guidance is less detailed. The Bureau of Safety and Environmental Enforcement commissioned the study described in this paper to develop this guidance including providing greater definition of IM and life extension processes for tendon systems, and describing an approach for demonstrating the reliability of tendon systems subjected to fatigue degradation. Four primary objectives are addressed: 1) tendon IM, 2) tendon life extension, 3) tendon fatigue, and 4) tendon component post-service testing. These topics were addressed through the input of subject matter experts, interfacing with TLP operators, and developing analytical tools. The study looked at current industry practice for the design and management of tendon systems; how current SIM approaches can be applied to the unique features of TLP tendons; what are the critical features of tendons to be addressed as part of a life extension program; tendon fatigue factors of safety; how reliability approaches can be used to better define risks related to operating beyond the original service life; and how forensic testing of recovered tendon components can be used to gain a better understanding of tendon performance expectations.

More than before, society and standards require "risk-informed" decision-making. The paper demonstrates the benefits of implementing reliability concepts in offshore geotechnical design. Reliability-based approaches will assist preparing engineering recommendations and decision-making. The paper gives an overview of basic concepts of reliability-based design, discusses the advances of hazard, risk and reliability in geotechnical engineering and illustrates their use with case studies from offshore practice. Risk and reliability evaluations can vary from simple statistical evaluations to full probabilistic modelling of the hazards and consequences for a single or a system of offshore installations. The examples include pipeline siting, jack-up mobile units, piled foundations and the reliability of code requirements. The paper discusses the strengths of the reliability-based approach and key issues such as tolerable and acceptable risk and the selection of characteristic value. The paper concludes that reliability-based approaches offer a useful complement to deterministic analyses, and enable analyzing complex situations with uncertainties in a systematic and more complete manner than deterministic analyses alone, both for design and for reevaluation. Managing geotechnical risks should today become a natural part of the engineer's work.

This paper investigates the critical areas at every stage in the lifecycle of the floater that may have been overlooked by classification bodies as well as owners and operators. These areas result in compromise of safety, integrity and operational capability leading to direct costs and opportunity loss costs, from cost for revenue deferment, repairs, third party engagement and risking the reputation and integrity of the COMPANY. The findings reveal the primary cause of breach in critical areas is the lack of a check and balance mechanism that should be imposed by owners and operators of the floaters to Classification deliverables instead of completely depending on Classification Society. Certain optional certification by Classification Society should be made mandatory to avoid such failures. Based on research and analysis of past floaters’ failures, a set of floaters’ integrity and assurance guideline should be developed and adopted by owners and operators to ensure safety, integrity and operational capability is always maintained and continuously monitored throughout the lifecycle of the Asset. Investigation on a number of case studies was conducted by collecting various data at all phases of the project (i.e. development, front end engineering, detail engineering, construction, transport and installation, hook up and commissioning, operation and maintenance, and decommissioning and demobilization & preservation). This paper emphasizes the need for Classification Society, owners and operators to conduct mandatory internal reviews, as a form of check and balance to avoid instances of overlooked critical areas. Ensure cohesive decision making by classification society, owners and operators of floaters to circumvent instances of overlooking the identified critical areas resulting in hazardous work environment and revenue deferment that have caused operators to be accountable and owners to be responsible. The Floaters’ Integrity and Assurance Guideline should provide an accountable process for all phases of the project throughout the life cycle of the asset.

Recent advances have made it possible to include augmented reality (AR) technology in the subsea intervention process to overcome problems commonly encountered during remotely operated vehicle (ROV) operations in deep water. Newly developed AR technology uses a state-of-the-art 3D engine to accurately model subsea assets and a geographic information system (GIS) to precisely determine the relative location of assets in the field, creating a virtual 3D visualization of the subsea facilities. ROV operations are enhanced by superimposing the virtual environment onto the live feed of the ROV's pilot camera. Merging real-time camera images with AR and other data streams augments visibility, improves safety, increases efficiency, and reduces overall costs. The use of AR technology for subsea operations is enabled by advanced software to digitalize subsea assets, cloud computing to run applications and store data, satellite communications to link offshore operations to onshore decision-makers, command centers that support remote operations, and simulation techniques for pre-job planning and ROV pilot training. Since testing began in 2015, the AR-enhanced process has been applied in deepwater fields in the Gulf of Mexico and North Sea. Looking ahead, it is expected that the experience using AR and structured data sets for improved subsea activity will lead to fully autonomous operations controlled by artificial intelligence to achieve project objectives with lower risk and greater efficiency.

Over the past decade, projects across the oil and gas industry have been plagued by cost and schedule overruns, exacerbating underlying cost escalation. Rising project costs must be addressed to ensure long term viability of the future capital programs. Standardization is widely recognized as part of the solution, and individual companies have been progressing standardization of specifications within their own businesses. However, the standardization journey is only just beginning: the oil and gas industry still lags others such as the automotive and aviation, as individual companies each maintain their own amendments on otherwise established industry or international standards. Joint Industry Program 33 (JIP33), now in its third phase, aims to unlock significant value and drive a permanent reduction in project costs through the development and use of industry-level, global technical specifications for procurement of bulk materials, packages, modules and potentially, even projects.

Technology has transformed the energy industry over the last 60 years. It has made processes more efficient, employees more productive and crucially, it has improved the safety of both workers and facilities. In a mature industry, such as oil and gas, operators and owners are faced with the challenge of safely and efficiently managing their ageing plant and assets. This challenge is compounded by poor historic records and information, and the potential loss of knowledge as the current workforce retires. Coupled with the increasing requirement for high levels of design assurance and confidence in solutions, and the constant pressure to deliver value, faster and cheaper; companies are constantly looking at the latest technological advances, and to other industry sectors, for possible solutions. This paper explores, through case studies, how the latest digital modelling and visualisation techniques are being innovatively deployed to enhance design, delivery and operations in the oil and gas sector. SNC-Lavalin have been uniquely deploying these technologies into the nuclear sector, where access time is highly-limited due to nuclear radiation. This learning has been brought to the oil and gas sector, and is an exemplar of cross-industry working and knowledge transfer.

This paper shows how the ISO 14224 standard, enterprise resource planning (ERP) software, and Big Data Analytics can be used to optimize safety and profitability in oil and gas, renewable energy, and in other asset-intensive industries. It also presents a logical approach for prioritizing application of digital capabilities for assets (e.g. equipment, systems and installations). ISO 14224 promulgates a standard data structure for collection and exchange of reliability and maintenance data for equipment. This data structure also can be used effectively to document failure scenarios for operating facilities. When equipment reliability and maintenance (RM) data and failure scenarios are recorded as relational data in ERP software, they can be combined with other enterprise data and digital field data to give a real-time status for each risk control. Individual scenario risk can then be easily aggregated to present real-time risk status for global operations or any subset thereof. This helps companies set priorities based on their bottom-line: HSE, production throughput, and profitability. Operating and producing companies have already completed risk assessments as part of operational preparedness/readiness for new facilities, in which equipment and system failure scenarios are included in various ways. These risk datasets typically require reformatting to make them relational, which is done by explicitly identifying equipment and risk control measures by their unique identifiers and by defining evaluation criteria for risk control measures. ERP data need to be made object-specific, e.g. inspection results and malfunction data should be recorded explicitly by technical tag. Reliability and Maintenance data quality management practices are a key consideration. Additional topics pertaining to compliant use of ISO 14224 standards for risk management include its roles in (1) technology development and technology qualification, (2) improving design and condition monitoring for equipment by use of operational and failure data, with an example given for electric submersible pump (ESP) systems, and (3) improving equipment RM data quality and thus enabling better risk awareness and data-driven decision-making. This paper will show how the international standard ISO 14224 can be applied in conjunction with digital technology and enterprise software to give oil and gas companies a global real real-time view of operational risk and a risk-based approach to optimizing safety and profitability.

The integrity management of Campos Basin platforms, subsea systems and wells and its risks control due to ageing process are key priorities for HSE. With this awareness, Petrobras is implementing initiatives to improve the production viability of mature fields and to extend the life of current facilities. This paper will describe some of these initiatives, which include: carrying out platforms maintenance campaigns using UMS (Units for Maintenance and Safety); subsea facilities and platforms life extension studies; well integrity evaluations; compliance with the new regulatory aspects of ANP (Brazilian National Petroleum, Gas and Biofuels Agency); development of business decision-making methodology based on break-even point; implementation of decommissioning projects of non-operating structures that have reached their technical and economic limit. As an example, it will be presented the extension of the concession contracts for the Marlim and Voador fields until 2052, which were originally due to expire in 2025.

Malikai TLP is a Deepwater manned platform operated by Shell. The Malikai TLP began construction in 2013. The Malikai TLP brought a huge challenge and complexity in terms of materials, quality control and assurance, interfaces between different contractors and subcontractors, construction and installation requirements and competent and experienced personnel. During the constructions phase, there were 3000-4000 workers based at site working together to build the TLP. There were significant amount of hazards that could be realized due to the types of construction and installation related activities such as working at height, working over water, confined space, working with electrical equipment, blasting, painting, grinding activities, scaffolding, lifting and handling of heavy equipment to name a few. The hazards at the site could have led to severe consequences including fatalities, physical injuries, burns and electrocution. With this realization, the Company implemented numerous measures to address the health, safety and environmental concerns including the welfare, competency and safe working environment for the workers. This paper presents an overview of the measures taken with the hope of achieving GOAL ZERO that emphasizes no harm to any personnel working at the site.

In this paper, the sources of uncertainty in the design of buried offshore pipelines against upheaval buckling in cohesionless seabed soils are combined and propagated within a reliability-based framework. The objective of this effort was to assess the inherent risk for pipelines that are designed as per standard practice, which is based on semi-empirical approaches that assume vertical or inclined slip line models within the overlying soil mass. A comprehensive database that consists of 143 laboratory experiments involving uplift of pipes through sand beds was compiled to assess the model uncertainty. The statistics describing the model uncertainty could be used by researchers and practitioners when assessing the risk of upheaval buckling of pipelines in cohesionless seabed soils. Results of the model uncertainty analysis indicate that the models of Schaminee et al. (1990) and Bransby et al. (2002) result in predicted soil uplift resistances that are on average 21% and 41% smaller than the resistances measured in the laboratory tests, respectively. The two methods also exhibit large model uncertainties with respective coefficients of variation (COV) of 0.39 and 0.37 for the ratio of measured to predicted resistance. The methods by White et al. (2001) and DNV (2007) are less conservative and less uncertain, with average under-predictions on the order of 2% and 9%, respectively and COVs on the order of 0.30 and 0.32. The reliability analysis results indicate that the probabilities of failure are sensitive to the design factor of safety, with probabilities of failure decreasing from around 1% to 0.001% as the factor of safety is increased from 2 to 3. For any given factor of safety, the probability of failure was found to be sensitive to the method used to predict the uplift resistance, and insensitive to the relative density and the temperature and pressure values adopted.

Greater complexity in offshore assets has introduced operational changes that impact the ways in which services are provided. Keeping pace with this evolution has led to an increased interest in emerging technologies that can be used in inspection tasks. Implementation of wearable technologies provides a way to capture and visualize information more efficiently, streamline inspection services, and integrate on-site, real-time information capture, thus allowing for more informed and rapid decision-making as well as alternative approaches to planning, execution, and reporting. Wearable devices can both collect and deliver data in the field, creating a synergy that enables the focus to remain on the task at hand while being able to automatically obtain access to relevant resources. Wearable technology allows field personnel to immediately and effectively capture, share, and collaborate with real time information, hands free. Wearables can also bridge time and distance constraints imposed by having a worldwide enterprise, and enable more informed, real-time decision making. With advanced visualization and augmentation, contextual data can be super-imposed on reality providing interactive job aids, ease of access to asset history, and current state asset health with digital capture of records/narratives. This technology can provide faster, more dynamic intelligence and direction to help quickly identify specific areas of interest for targeted inspection applications. Incorporation of wearable technologies follows a phased approach. The first step is to look at ways of improving current systems and identifying what processes can be adjusted for increased efficiency and safety. The second phase leverages the use of sensor technology in collecting and analyzing data to improve processes by enhancing data capture and providing additional connectivity. The third phase focuses on creating new processes and developing broader capabilities by building a knowledge base from collected and analyzed data. This phase requires data to be collected, categorized and indexed to identify patterns. The end result of following a structured implementation process is the ability to incorporate ambient intelligence and augmented reality to enable risk-informed decision-making and support efficient execution of inspection tasks. This paper will primarily address phase 1 activities as well as discuss the driving factors for the use of wearable technology in the offshore industry, the current and future capabilities and use cases for wearable technology, as well as experience, lessons learned, and next steps in the implementation process.

For Continued Service (Life Extension) approval in the GOM, both BSEE and USCG require a review of the process and submittals by an independent third party. This has been referred to as a CVA review for lack of a better term, which is a Certified Verification Agent. However, the scope of a CVA review during a Continued Service Assessment does not typically warrant the extensive scope of the full CFR definition of a CVA as required for the design and installation of a new offshore facility, but guidance has not yet been provided by USCG or BSEE. As a result, there is currently uncertainty within the industry as to what the CVA role is for Continued Service and it is being applied using widely varying approaches, ranging from a simple review of the overall assessment documents and references to active participation in the entire process influencing decisions on analysis and mitigation requirements. Drawing upon the authors experience conducting Continued Service Assessments in the different roles of operator, assessment contractor and CVA, this paper describes the important role of the CVA as part of the Continued Service Assessment team, the CVA activities and interfaces, as well as the varying degree of required independent oversight for different proposed continued service circumstances. This paper focuses on structure, marine systems, moorings and, to some degree, risers. Topside process or process safety are not discussed although there is an analogue process that is conducted as part of an overall Continued Service Assessment.

The oil and gas industry loses approximately $300 billion profit annually to poor operating performance. Outdated technologies and work practices are largely to blame because they lack the predictive capabilities of modern automation. When oil and gas producers adopt modern technologies and adjust work processes, they can recover a significant portion of these losses and realize top quartile performance in production, reliability, and safety. Examples illustrate this. In response to low commodity prices, the oil and gas industry has rationalized operations and procedures over the last few years. However, estimates are that the industry still loses hundreds of billions of dollars annually to poor operating performance. Much of that can be recovered by emulating the practices of the industry's best performers. The top quartile of oil and gas producers deploys technology, processes and people in a purposeful orchestration to boost production, cut costs and improve safety. They define a strategy, analyze inefficiencies, prioritize opportunities, and then select technologies that can scale and leverage existing investments. Doing this substantially boosts the bottom line.