Safety Case in GoM: Method and Benefits for Old and New Facilities

Oil and natural gas producers continuously strive to control costs, and that goal becomes even more important when market conditions are challenging. To maximize the return on their capital investment and continue to extract reserves on legacy fields, many owners and operators are looking for ways to extend the service lives of aging assets. The Neptune Spar was the first production spar platform in the world, when it was installed in 1996. Currently owned and operated by Noble Energy, the unit continues producing at Viosca Knoll 826 in the Gulf of Mexico. As the platform ages, there is an interest in extending its service life to allow continued operation in the field. As requested by Noble Energy, ABS Group initiated a life extension assessment project. This paper describes the process of the Neptune Spar life extension assessments and challenges encountered during the process. One of the critical aspects of the life extension process is regulatory approval. Since the life extension for floating production platforms is a relatively new trend in the offshore industry, the regulatory compliance process is still under development, and this project is providing a significant contribution to the development of guidance and criteria. The purpose of a life extension assessment is to understand the history of the facility and its current physical condition to determine its structural integrity and outline what is needed for the unit to be maintained for safe and responsible extended service. The life extension project began with a roadmap for life extension assessments that included conducting baseline inspections, reviewing historic inspection and repairs records, undergoing gap analyses that compared the spar's current condition with the original design premise and calculations, and performing additional engineering analyses. As part of the regulatory approval process, the U.S. Bureau of Safety and Environmental Enforcement (BSEE) and the U.S. Coast Guard (USCG) require that a Certified Verification Agent (CVA) verify the entire process of life extension and submit reports that document findings and recommendations. ABS served as the CVA. During the life extension assessment process, ABS Group and Noble Energy consistently coordinated with ABS, BSEE and USCG. Based on the life extension assessments, ABS has granted class certificate for the life extension of this platform. The process of the spar's life extension assessment provides industry with a better understanding of the technical requirements for life extension of other floating production assets, which will have a long-term impact on future asset integrity management for these types of facilities in deep water.

Formal Safety Management Systems (SMS) have been required in the USA and elsewhere for the onshore refining and petrochemical industries since the mid 1980's (EU) or early 1990's (USA). While several different versions of SMS exist they are mostly similar in content. Risk based SMS are more modern in thinking than hazard based systems. The O&G and petrochemical industries have reduced occupational accidents by close to a factor of ten over the past 15–20 years. However, major accident performance has hardly improved globally. An exception is the North Sea where major accidents appear to have declined by close to a factor of ten as well as occupational safety. This paper reviews some key additional requirements in the North Sea and why these appear to address major accidents better - by focusing on risks and barrier management and verification focusing on these. The SEMS approach as mandated by BSEE is essential and will be improved by safety culture requirements BSEE is proposing. However, since SEMS is very similar to OSHA 1910, and much less than North Sea requirements, it is likely that achievements will mirror that of 1910 and unlikely that the desired order of magnitude improvement in major accidents will occur. Additional focus on risk and barrier management is still required and this is not part of SEMS. A strong culture for process safety requires a focus on risk assessment and barriers. Background to Safety Management Systems The requirement for formal safety management systems (SMS) in the process industry has been common since the 1980's with earlier development of formal SMS by leading companies. Examples of these include the DuPont SMS, Exxon OIMS - Operations Integrity Management System, BP Getting HSE Right, and the DNV International Safety Rating System. A common feature is that most of these systems were developed in response to some major accident. The insight was that accident causes are not simply technical, but have underpinning management system influences (root causes) and major accidents would recur unless improved management systems were implemented. The major accidents in the 1970's in Europe (i.e. Flixborough UK and Seveso Italy) spurred development of safety case regulations in the Seveso Directive (originally passed in 1984 and coming into force in 1986). This included a requirement for a formal SMS. Major accidents in the 1980's in the USA or affecting USA companies (i.e. Bhopal MIC release, Phillips Pasadena VCE, Marathon HF release Texas City) led OSHA to seek input for new regulations. API issued RP 750 for onshore and RP 75 (1991) for offshore and CCPS issued its Guidelines for Technical Management of Process Safety (1989). These guides were extensively used in the public process leading to development of OSHA 1910.119 - the Process Safety Management regulations (1992). About this time the UK HSE issued HSG 65 - Successful Health and Safety Management (1991). All of these systems used an element based approach to the SMS with 12–20 elements typically. Most had the same content and the differences were primarily textual. These initial processes were followed by other initiatives that continue to current times. The UK HSE Offshore Safety Case regulations (1992) were an extension of the requirements in the EU Seveso Directive and included more advanced risk thinking from the Cullen Inquiry. The EU Seveso Directive was updated on multiple occasions to address new threats as they occurred (e.g. environmental damage: pollution of the Rhine following a fire at Sandoz, and a major cyanide spill from a mining dam in Eastern Europe). A major revision increased the focus on major accidents and changed the degree of justification in the safety case (e.g. as implemented in the UK) from " describe?? the safety systems to " demonstrate?? the adequacy of safety systems. The US EPA (1996) issued the RMP regulations (Risk Management Plan). These were very similar to OSHA 1910, but required Offsite Consequence Analysis for standardized 10 minute worst case events and optional some alternative release scenarios. An RMP document had to be created describing the SMS and safety systems this had some similarity to the EU safety case document. OSHA 1910 required the SMS elements to be in place but not collected into a single document.

Critical Asset Performance Standards (CAPS) are designed to meet operational safety and environmental protection requirements. CAPS define the key aspects of safety-critical elements (SCEs), including equipment, procedures, personnel, inspections and verifications necessary to preserve the integrity of the control measures that reduce the risk of a catastrophic major accident event (MAE). This paper offers an overview of the process involved in developing CAPS for integration into a Safety and Environmental Management System (SEMS) as part of an overall Risk-Based Asset Management strategy that provides regulatory compliance and system reliability. The relationships between SCEs, CAPS and associated maintenance tasks are an important aspect of the design, operation, reliability and safety case of a facility. They ensure that, as far as reasonably practicable, the facility design is in accordance with the latest codes and standards for the facility and complies with any additional requirements defined within the safety case to demonstrate that the risk for MAEs to all personnel working on the facility is maintained as low as reasonably practicable (ALARP). At the end of the CAPS development process, the following information will be available: Comprehensive list of the critical assets and an understanding of their relationship to MAEs; Well-defined performance-based standards for all SCEs; Metrics for trending and continuous improvement efforts; Documented maintenance tasks for all critical assets For each SCE, CAPS are developed to document the minimum performance required of the SCE in meeting its role in preventing or mitigating MAEs. CAPS can then be used as check lists for validation of the design and a basis for ongoing maintenance during operations. It should be noted that codes, standards and best practices are regularly updated in response to incidents that have occurred and it important to incorporate new learning, methods and technologies. Using a proper Management of Change (MoC) process, CAPS can be invaluable tools for assessing impacts to risk as a result of these changes. Performance standards may legitimately change during the life cycle of an installation. Therefore they should remain living documents and be updated as necessary. As with any safety and reliability-related program, a comprehensive approach also includes independent verification and periodic reevaluation for continuous improvement. Leveraging CAPS within a Risk-Based Asset Management strategy provides the framework for setting documented performance standards and establishing traceability to ensure regulatory compliance that ultimately meets corporate objectives for safe operations.

2017-321 The Department of the Interior’s Bureau of Safety and Environmental Enforcement (BSEE) National Oil Spill Response Research and Renewable Energy Test Facility, Ohmsett, plays a critical role in advancing oil spill response capabilities through research, development, testing, and training. Ohmsett’s 10 million liter (l) saltwater wave tank provides an independent venue to conduct research and development with full-size response equipment using real oil, in realistic, repeatable conditions. This paper will discuss recent research and development conducted at Ohmsett, including: Remote sensing of surface oil by BSEE, the National Oceanic and Atmospheric Administration (NOAA), the United States Army, the United States Coast Guard (USCG), and the United States Environmental Protection Agency (U.S. EPA); using acoustics to measure oil slick thickness; creating large volumes of emulsions for Ohmsett tests; mechanical recovery of chemically treated, undispersed oil; skimmer testing in diminishing slick thickness; a USCG and BSEE test of a skimmer ice management system; and an autonomous skimmer development. This paper will summarize the setup and methodology used during recent testing, training, and research conducted at Ohmsett. Reports of BSEE funded oil spill response research can be found at https://www.bsee.gov/site-page/master-list-of-oil-spill-response-research.

There is a limit to disruptive innovation in oilfield technology. Blowout preventers (BOP) show how hard it can be. A decade ago on 20 April 2020, the Macondo disaster made a powerful case for change when this last line of defense failed to stop a blowout that caused explosions and a fire that killed 11, destroyed the Deepwater Horizon drilling rig, and set off one of the largest oil spills ever in the Gulf of Mexico. Scathing reports from investigations and staggering payouts from lawsuits against BP and other companies highlighted the shortcomings of machines that failed to serve as the last line of defense when natural gas surged onto the drilling floor, setting off a series of explosions. The investigations highlighted a long string of errors that led to the avoidable crisis. There was a failure to verify the cementing, missed signs of gas building up in the well, and a delayed decision to activate the BOP until the explosions already may have severed the hydraulic lines to the wellhead. But the simple explanation for it all: The shear rams failed to sever the pipe and seal the well. In the aftermath, well-control standards and regulations were rewritten and expanded. The changes required that old recommendations became requirements, and new ones were added, including a strong push toward real-time monitoring. The reports did not propose fundamentally redesigning BOPs. But for engineers with an inventive streak, this looked like a call to rethink the driving force behind these hydraulic devices where the fundamentals have changed little since the first patent was issued nearly 100 years ago. The arguments for rethinking BOPs included a 2003 study by West Engineering Services that found shear rams failed 7.5% of the time based on an estimate of the typical force required to cut pipe at the time. The force needed rises as casing gets tougher, water depths deeper, and well pressures higher, according to the study funded by what is now the US Bureau of Safety and Environmental Enforcement (BSEE). A Det Norske Veritas study for Transocean completed before the Macondo blowout found 11 situations where a BOP was activated in an emergency among the 15,000 wells drilled from 1980 to 2006. The BOPs only worked six times during that period, according to a story in The New York Times published in June 2010 - while the industry was scrambling to find a way to stop the Macondo leak. Different Perspectives The innovators range from startups to major offshore drillers. A Norwegian engineer started a company to sell a design for all-electric BOP stacks and an offshore drilling contractor developed an electric motor to retrofit into a BOP body. Engineers with military and space experience created cutting devices powered by gas generators using solid chemical propellants that send out high-pressure streams of gas when ignited by an electrical signal, similar to the deployment of an airbag or the thrusters on the Space Shuttle (this technology has been around for a long time).

A team led by the Gulf Coast Carbon Center at the Bureau of Economic Geology, Jackson School of Geosciences at The University of Texas at Austin, has been funded by the National Oceanographic Partnership Program (NOPP) through and in cooperation with the U.S. Department of Interior (DOI), Bureau of Ocean Energy Management (BOEM) to generate a Best Management Practices (BMPs) document on sub-seabed geologic sequestration of carbon dioxide (CO2) below the U.S. outer continental shelf. The team consists of scientists, engineers, lawyers, and business managers from academia, private industry, and State of Texas government from the following institutions: (1) Gulf Coast Carbon Center at the Bureau of Economic Geology (BEG), (2) Det Norske Veritas (USA) Inc (DNV), (3) Wood Group Mustang and sister company Wood Group Kenny (Wood Group), (4) Texas General Land Office (GLO), (5) Harte Research Institute for Gulf of Mexico Studies at Texas A&M University-Corpus Christi (HRI), and (6) The University of Houston Law Center. Individual team members have expertise in carbon sequestration monitoring, CO2-pipeline design and construction, and domestic and international offshore environmental policy. The BMPs will be reviewed by external experts after it is generated and before being submitted to BOEM. The purpose of the BMPs will be to provide technical guidance to BOEM and BSEE (U.S. DOI Bureau of Safety and Environmental Enforcement) to establish regulatory guidelines for offshore components of future U.S. Carbon Capture and Storage, which is sometimes referred to as sequestration, (CCS) industry. Sub-seabed geologic sequestration (GS) is the process whereby CO2 captured from large volume industrial sources (e.g., power plants, oil refineries) will be (1) compressed to supercritical state and transported via pipeline to offshore injection wells, and (2) injected into geologic strata deep (thousands of feet) below the seafloor. Objectives of the CO2 injection will be for “pure sequestration” (i.e., long-term storage of CO2 in subseafloor saline reservoirs) or sequestration combined with enhanced oil recovery (EOR). Sub-seabed geologic sequestration is very different from ocean dumping (i.e. dissolution of CO2 into circulating seawater) or injection of CO2 into deep water, shallow sub-seabed sediments. Some researchers proposed in the past that shallow subseafloor depths (<; 1,000 ft) were sufficient for permanent CO2 storage in deep marine environments (>; 11,000 ft water depth) (e.g., House et al., 2006). However, the shallow sedimentary subseafloor environment could become unstable and allow release of CO2 into ocean water, the end result of which would be ocean dumping. One mechanism of seafloor instability could be the release of gas from hydrates owing to pressure and temperature perturbations that may be introduced by shallow drilling and CO2 injection. Furthermore, the logistics of transporting CO2 hundreds of miles offshore to areas with sufficient water depths for storage in shallow subsea sediments would probably not be economically feasible. We want to emphasize that subseabed GS of CO2 is not ocean dumping. One of the biggest concerns for onshore GS is the potential to impact shallow drinking water resources. Injecting CO2 deep below the seafloor will avoid this potential consequence. But there are sensitive marine environments of concern in offshore settings, protection of which is critical. Environmental monitoring of marine ecosystems (nearshore, along CO2 pipeline corridors, and outer continental shelf) and subseafloor geological strata in which CO2 will be injected will be a large component of the BMPs. Topics being included in the BMPs, a draft of which will be submitted to BOEM in June of 2013, are: (1) site selection and characterization, (2) risk analysis, (3) project planning and execution, (4) environmental monitoring, (5) mitigation, (6) inspection and auditing, (7) reporting requirements, (8) emergency response and contingency planning, (9) decommissioning and site closure, and (10) legal issues. Where possible, we are using existing regulatory, policy, and technical guidance documents as a starting point for the BMPs. We think the most likely location for initiation of U.S. offshore geologic sequestration of CO2 will be in the western or central sectors of the Gulf of Mexico where extensive offshore oil and gas infrastructure already exists. Academic members of our project team are actively working on criteria for site selection [1]. However, private industry is also assessing the feasibility of offshore geologic sequestration below the Atlantic seafloor [2].

Task. Issues devoted to the delimitation of methods and procedures of related scientific areas: risk management, economic security, management and risk management are studied and researched by many authors. This gives rise to thoughts about a single basic basis for the listed scientific movements. So, the author, in order to avoid constant repetition of listing the scientific directions under consideration in the article, calls them directions, economic categories, etc., but the problem raised by the author of the article is the differentiation of the main elements, in particular methods, procedures, goals, objectives, principles between the studied categories, namely risk management, economic security, management and risk management. The purpose of the article is to systematize the listed elements and consider their duplication in the scientific areas under consideration. Model. The author systematizes, on the basis of those reviewed by modern economists and analysts, as well as classic scientific works, the basic elements of risk management, economic security, management and risk management. An attempt was made to find an answer to the question «are there specific developed methods and techniques for risk management of an organization that would distinguish it from the risk management system and other scientific areas?» Conclusions. Economic categories: risk management, economic security, management and risk management are considered as a single process in economic research, and therefore economists do not have a clear opinion and understanding of the differences between these categories. Practical significance. A comparative analysis of the essence of the main elements of risk management, economic security, management and risk management allows us to determine the most appropriate methods and procedures for the practical application of risk management in organizations. Allows you to develop an understanding of the implementation of risk management principles in organizations to achieve their goals. Originality. The list of goals, objectives, procedures and principles of risk management, economic security, management and risk management has been clarified, expanded and systematized.

The mechanical recovery of oil in ice-infested water presents unique and difficult clean-up challenges. Ice can impede the movement of spilled oil making it less available for removal by the active components of oil recovery skimmers. Ice and slush that is recovered with oil can jam the skimmer, pump inlets and hoses and can provide an environment for enhanced emulsion formation. Low temperatures increase oil viscosity, further complicating processing and pumping of recovered product. In response to these challenges, the U.S. Department of the Interior's Bureau of Safety and Environmental Enforcement (BSEE) recognized the need for comprehensive programs of testing and research in the area of oil spill response in icy waters. BSEE has supported and sponsored a number of testing and research programs at the Ohmsett facility involving oil in cold water and ice. During the winter of 2013, BSEE sponsored an oil-in-ice spill test at Ohmsett titled Skimmer Tests in Drift Ice: Ice Month 2013 at Ohmsett. The tests involved ten commercially available skimmers that represented a range of skimmer types. Testing was done in the Ohmsett test basin using a controlled test area with fabricated ice. To the best extent possible, test variables such as water temperature, oil characteristics, oil slick thickness, ice coverage and size distribution, and skimmer operations were controlled. Performance determinations were made for oil recovery rate and oil recovery efficiency as per the general principles and guidelines of ASTM F2709. Tabulated results for the same are presented. At lower ice coverage (30% ice), there was no significant mechanical impediment for most skimmers. However, ice can interfere with the flow of oil to the skimmer periodically even in this coverage. At higher ice coverage (70% ice), there was significant impediment to skimming, with most skimmers having dramatically lower rates and efficiencies. It was also observed that with longer exposure to skimming under these conditions, operators became more proficient with regard to recovery performance. This indicates the importance of training and practice for effective skimming operations.

One of the documents that a drilling operator must submit with the Application for Permit to Drill (APD) to the Bureau of Safety and Environmental Enforcement (BSEE) is the Well Containment Screening Tool (WCST). The data are submitted via eWell by the operator during the APD process. The results of the screening tool are used to demonstrate that the well is adequately designed to contain uncontrolled flow. Worst Case Discharge (WCD) loads are considered as survival loads, and the exposed tubulars must satisfy a design factor is 1.0, for both burst and collapse loads. Two levels of screening are performed in the WCST. Level 1 screening assumes BSEE specified hydrocarbon gradients and ensures that the well can be fully shut-in without causing underground flow. If the well fails Level 1 screening, or if the well contains an unconditionally trapped annulus, Level 2 screening is required to ensure well integrity during unrestricted flow, and subsequent full shut-in. In both levels, the mechanical integrity of the tubulars is one of the three categories that the WCST does screen. BSEE does not provide guidelines on what tubular ratings should be used to account for the effects of downhole temperature. Using manufacturer provided ratings will be less than conservative, since they are valid at room temperature. The burst rating should be derated for the temperature at the depth of interest, because yield strength decreases with temperature increase. The collapse rating should be derated not only for the temperature, but also for the axial tension, if it exists, at the depth of interest for the WCD load. The temperature derated burst and collapse ratings can be estimated when expected WCD temperature is known. The tension derated collapse rating requires a complete examination of the load. The current version of the WCST does not facilitate this task; and the results can lead to a potentially non-conservative conclusion. This paper discusses the impact of temperature and tension on WCD loads and how to use the WCST more accurately.

Summary This paper describes the experience to date with safety management systems (SMS's) and describes their implementation after the Piper Alpha disaster and Lord Cullen's report. It also shows the gradual expansion of these systems toward fully integrated health, safety, and environment (HSE) management systems. Our company policy, which was clearly stated before publication of Lord Cullen's report, is that work should not start until the appropriate controls are in place. Work based on this policy and on objective-setting SMS's within Shell IntI. Petroleum Mij. (SIPM) E&amp;P coordination started in earnest soon after the publication of the report in Nov. 1990 and has continued without interruption since that time. Objective-setting systems may be defined as systems where the company management sets its own objectives or goals on the basis of functional rather than prescriptive requirements and then goes on to demonstrate how such goals have been, or are being, met. The paper ends with a projection of what may be expected in the future. Introduction Following the Piper Alpha disaster and the in-depth public inquiry led by Lord Cullen, the recommendation was made that all offshore installations on the U.K. continental shelf should have safety cases similar to those already required under the U.K. Control of Industrial Major Accident Hazards Regulations. This recommendation was given effect by means of the safety-case regulation within the U.K. with a Nov. 1993 deadline for the submission of safety cases. Shell Expro, as a major operator in the U.K. sector of the North Sea, had already begun work on its safety cases before publication of the Cullen report and was one of the companies that contributed to the so called "voluntary" safety cases before this date. It was apparent to E&amp;P management within SIPM that the SMS and the safety case provided better assurance of safe operation and were of real value to Shell operations worldwide. (In this paper, Shell is sometimes used for E&amp;P companies of the Royal Dutch/ Shell group in general, and Shell E&amp;P is used if experience was gained through technical service agreements supported by SIPM E&amp;P). It was also clear that a worldwide move toward such systems would take place. Thus, application of these systems was both good business and appropriate for all Shell E&amp;P operating companies. As a direct consequence, an integrated project team (both project engineering and operations) was set up to implement SMS and safety cases throughout Shell upstream operations worldwide.

Previous papers given to SPE conferences have described the Shell Group approach to Safety Management Systems and to Safety Cases. Their extension to HSE MS and to HSE Cases has also been addressed. Since 1984 the Enhanced Safety Management (ESM) programme within Shell companies has led to a significant improvement in the management of safety but it was only when structured management systems (based upon an understanding of the business processes) were introduced that true integration of HSE as a line responsibility became a reality. This paper describes the THESIS software package and the way that management systems have been made 'live' and how workforce involvemerU can be demonstrated. The paper starts with the premise that "...work should not start before it is confirmed that essential safety systems are in place and that staff are accountable for this requirement. Where we cannot ensure safety, then operations should be suspended...".Line management needed a way of making this a real part of the job and of providing workplace personnel with an essential understanding of the risks that they face. In Jakarta we stated that "Many of the early Safety Cases reviewed failed to provide a clear message that the operation's safety management system has benefited from the assessments made in preparing a Safety Case. They were regarded as paper exercises and a sterile documentation of what had been done, often by engineers or consultants. Without some form of 'energising' the system becomes just another book on the shelf. Since Jakarta we have been completing wotk on relational database software aimed at changing the Safety Case from being a paper document to a software based 'System' from which on-line reports can be extracted that add value to those managing the risk of the business. Changes to the electronic document can be readily undertaken and whilst still not painless the development and updating of a Safety or HSE Case is now much reduced in terms of time and effort enabling it to remain alive. With the critical HSE activities and tasks specified and related hazards and effects identified and linked via a relational database, it is possible and realistic to provide to the workplace clear reports that describe the necessary controls in terms of the tasks that actually provide those controls.

Beaches are basically managed mirroring user’s perception and normative requirements to obtain performance standards or distinctions made on well-known Quality Management Systems and/or Environmental Management Systems. However, when these systems are used in the management of these natural public goods, present practices do not fit with the Ecosystem Approach Strategy (EA) launched by United Nations at the end of last Century. To overcome this reality, an application of the Ecosystem-Based Management System (EBMS) was developed recently as a formal way to practice this approach at the beach social-ecological system. The EBMS is a stepwise process that combines environmental quality and risk management system theory with the EA principles. The EBMS is composed of three interactive pillars: Managerial, Information and Participatory. The Managerial pillar is the “engine” of the EBMS, following the classical Plan-Do-Check-Act managerial policy scheme. As a part of the Planning phase, a factual approach to decision making is suggested: DEMA (DEcision-MAking) tool. DEMA is a formal prioritization tool intended to help managers to determine, based on a social cost-benefit analysis and the vision established for a particular social-ecological system, which projects should be the first. DEMA uses risk management theory to decide what future activities should be selected in the policy cycle to avoid those identified risks that could impede us to get the desired vision for the beach under management. DEMA is using a framework of indicators related to the identified ecosystem services given by these systems, valuating and rating them to further prioritization of actions.

Preventing the environmental risks linked to contaminated sites and guaranteeing the safety of human settlements are some of the challenges and tasks involved in the construction of world-class city clusters in the Guangdong-Hong Kong-Macao Greater Bay Area. Due to differences in the political systems and land property rights between Guangdong, Hong Kong, and Macao, as well as in the levels of urbanization, industrial structures, and environmental management capabilities of the nine cities in the Pearl River Delta, the risk management and control mode of contaminated sites varies considerably within the Greater Bay Area. In this context, an analysis of the features of risk management and control in the contaminated sites of typical cities can help strengthening technical communication and cooperation, optimizing risk management and control systems. This article briefly describes the risk management and control systems adopted for polluted sites in China; in particular it elaborates on the features of these systems in Guangzhou, Shenzhen, Dongguan, Hong Kong, and Macao, which have been subjected to monitoring, contamination assessments, and renovation procedures. During our study, the risk management and control systems adopted in different cities have been analyzed and compared; moreover, we elaborated thoughts and suggestions for land planning, policy feedback, information disclosure, and alliance mechanisms. We conclude that, overall, Hong Kong and several cities of the Pearl River Delta have established effective risk management and control systems for the polluted sites, which take into account certain local characteristics. However, with the further development and reuse of contaminated sites, the building of a world-class urban agglomeration in the Guangdong-Hong Kong-Macao Greater Bay Area will require safer, more refined, and more efficient risk management and control strategies. We highlight the need to exchange information among researchers in order to promote technical exchange and cooperation. This is particularly important for the risk management and control of polluted sites distributed within the two regions and nine cities of the Guangdong-Hong Kong-Macao Greater Bay Area, sine it would allow their safe reuse and efficient development.

Drilling operations in the Gulf of Mexico (GoM) area, are characterized by high geological uncertainty, which requires optimum engineering, planning, and early risk detection. The expertise and technical knowledge must be complemented with a strategy that accomplishes a continuous and detailed risk evaluation and self-verification process, covering all drilling stages - design, execution, and evaluation. The objective of this paper is to describe how a risk management system was implemented within an integrated services model, resulting in a higher level of operational efficiency. The strategy is based on the technical risk evaluation and determination of initiatives to become effective and efficient during both planning and execution cycles. From the risk identification perspective, establishing different strategies and technologies to minimize the occurrence of undesirable events and defining mitigation measures to reduce the impact, with the inputs of Subject Matter Experts (SMEs) to determine the most appropriate technologies to de-risk operations. Project schedule management is part of the considerations, looking to facilitate the technology implementations and applications across the integrated project and align with the well scope and operational complexity. The implementation of the Risk Management strategy in projects operating under shared risks drilling modality, facilitates the definition of shared risk appetite, objectives, and key performance indicators. The time and cost estimation are the main input for the integrated services provider (ISP) and the Oil and Gas Operator in their performance partnership. This paper will describe different digital solutions that aid in risk management and performance optimization. Key initiatives employed were around resource optimization and dynamic update and reviews of a well’s critical path.

On 9 September 2012, Noble Discoverer, a Royal Dutch Shell’s drill ship, began drilling in the Chukchi Sea 70 miles off the Alaska coast, signifying the return of active offshore exploration in the US Arctic (Broder, 2012a). Another Shell drill vessel, Kulluk, commenced drilling in the Beaufort Sea on 3 October 2012 (Shell, 2013). Yet Shell’s foray into the US Arctic offshore was brief — the exploratory drilling in the Chukchi Sea lasted just over a week and in the Beaufort Sea for three weeks (Krauss, 2012). Shell’s 2012 US Arctic campaign was also unproductive. After spending over US$4.5 billion, Shell had only two top holes to show for it at the end of the season.1 The main reason why Shell was not allowed to drill into the hydrocarbon-bearing reservoir is because it was not authorized to do so by the US government. The drilling permits issued by the Bureau of Safety and Environmental Enforcement (BSEE)2 were limited to drilling top holes because Shell failed to deploy the Arctic Containment System fully tested by BSEE before commencing drilling activities (DOI, 2013, p. 16).