Offshore industry assets are capital intensive and downtime can have severe financial consequences. Additive manufacturing (AM) based supply chains can potentially offer offshore industry stakeholders a strong value and a competitive advantage, from lower costs and lead times to greater flexibility and agility. However, the current adoption level of AM for the offshore industry is very limited, despite the consensus that such technology could have potential applications for spare parts, repair and even new builds. While adoption of additive manufacturing could be a source of positive change, inadequate understanding of requirements regarding approval, qualification and certification processes required by regulatory authorities could hinder the progress of AM adoption in the offshore industry. Currently, there are only a handful of additive manufacturing standards available for early adopters of AM technology. Hence, costly and time-consuming nonstandard testing to ensure the integrity of the 3D printed parts is deterring the wider applications of additive manufacturing in the offshore sector, underscoring the need to develop optimal practice guidelines and standards from design to part build to operation. This paper aims to highlight several key challenges that hinder the adoption of AM in the offshore sector and to propose various solutions that can help to overcome these. Due to its novel approach, the risk-based certification pathway discussed in this paper will help the offshore industry and its supply chain ecosystem to build trust and confidence in the adoption of this emerging technology, which otherwise might not be possible.

With the growing demand in cost reduction on maintenance activities as well as weight reduction solutions, it is necessary to invest in new technology and design solutions in the offshore industry. The use of lean duplex materials has been on-going for over a decade but the application in offshore industry, specifically in new platform design and modification activities, has been quite recent. This paper gives an outlook on lean duplex material and the results of a pilot project developing a grating design which was supported by Oil & Gas Company in Norway with the aim of using lean duplex gratings in the next available modification project. The most commonly used solution in the Norwegian offshore industry is HDG gratings. These gratings are available as ready-use cut-to-length solutions to cover the required surface area from various manufacturers. With the mind-set of developing alternative solutions to existing grating options, selection of a superior material type with favourable characteristics such as higher corrosion resistance, mechanical properties and weldability are some of the key focus points. At the development stage two different Lean duplex grating prototypes have been designed. The primary goal of the design was to meet all the current offshore requirements while reducing the weight on the final product. Having the option of lean duplex as the material choice for gratings provides key advantages in weight reductions and superior corrosion resistance in saline atmosphere resulting in longer lifecycle times. The design focus on lean duplex gratings has been presently limited to the platforms, staircases and walkways, but there are a more possibilities for optimization of the design when balancing the cost / benefits of the following factors: ▪ Design/Weight ▪ Lifetime/ Maintenance – Low Carbon Footprint ▪ Cost This product development can be viewed as an incremental innovation showing the potential where a small piloting scope can have larger implications if applied in larger scale modification projects.

Offshore energy market conditions change rapidly, with consequential demand changes for installation equipment, floating units and support vessels. Newbuilding requires a substantial investment and often takes (too) much time to obtain maximum benefit from an emerging opportunity. Upgrading or conversion of an existing unit can be a good alternative. There are eight different hull types to choose from for floating offshore units. The most common vessel type is the ship-shaped monohull. Within the large pool of existing merchant and offshore vessels, both new and ageing, there are many suitable candidates for upgrades and conversions. Such a new lease of life expands their operational and economical portfolio and serves the offshore industry in reaching spectacular advances in transport, construction and installation performance. When upgrading or converting existing units multiple tiers of capability increase are distinguished. Each tier brings increasing complexity, risks and re-building costs. Options range from life extension and modernization of an older vessel, temporary conversion, capacity upgrade, adding functions, changing the present function, to ultimately the complete transformation of an older merchant cargo vessel into a brand new offshore unit. Major vessel conversions can be competitive with newbuilding options, provided that such a complex conversion project is prepared and managed well. New insights into the market drivers for upgrading and conversion of floating offshore assets are provided. The broad range of offshore vessel modifications presented is an industry first. Some remarkable examples of capacity upgrades, double conversions and complete vessel makeovers are presented.

Over the past few years the offshore industry has undergone a profound change. Operators, contractors and suppliers have been forced to find new ways of working as the industry landscape changes, putting pressure on price and schedules. These new ways of working are taking shape in the form of alliances and mergers within the service industry, while operators take a more holistic approach throughout project lifecycles with their established contracts and suppliers. This paper will review the changes & how new ways of working minimize interfaces, maximize efficiency and capitalise value-added contributions from the service industry. This paper will also consider how different ways of contracting are evolving to drive the industry to further change regarding how we engage & balance risk between the various industry players. Acknowledging the progress and promise of these new engagement models, Operators have requested Suppliers to engage during earlier stages as opposed to the traditional process previously followed. Early engagement brings project execution expertise and experience while providing an innovative outlet for service providers to submit their best design proposals without the constraints of company-specific requirements. These models also provide opportunities to reduce cost, but more importantly – reduce interface, risk and the critical path of project schedules within this new industry landscape ensuring an earlier return on investment. These changes will require all players in the offshore industry to focus their efforts to achieve additional improvements that go beyond internal processes, mergers, and acquisitions. Although these are necessary to ensure that the industry remains competitive, they alone won’t be sufficient. Operators, Contractors and Suppliers need to also work together to cause and manage a shift in balance between risks and rewards. Finally, changes in one part of the industry (e.g. Equipment / Contractor type alliances) provide new opportunities in other sectors where collaboration has not yet materialised. As such there is a promise of further improvement of cost, risk and schedule when these opportunities are materialised.

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.

This paper discusses the benefits of using Unmanned Aerial Vehicles (UAVs) as inspection tools to support surveys of marine and offshore assets, from a class organization's viewpoint and understanding, based on industry case studies and experiences for both internal and external structure surveys. Capabilities and limitations of using UAVs are compared to current survey methods. Finally, possible future uses of this technology will be discussed. Some specific inspections for marine and offshore assets, such as those conducted at height or in confined spaces, are typically performed by surveyors. These inspections can be expensive, time consuming, and disruptive. This paper presents key challenges driving the need for UAV inspection, and benefits offered by this new technology. General acceptance criteria and requirements of UAV inspection (e.g., data acquisition), based on previous industry experience, are introduced. Available UAV systems are presented, with a brief introduction of typical UAV types. General performance and lessons learned, based on previous UAV field tests, are summarized. Two case studies further highlight field test results. Also, the paper discusses existing and potential data post-processing methods (e.g. regression analysis), and how these methods leverage UAV technology in structure monitoring and inspection. The use of UAVs can help reduce the risk associated with the above mentioned inspections by reducing hazard exposures for workers. Use of UAVs can also have a positive impact on operational activities through increased inspection frequency, improved inspection efficiency and better data collecting capability. With proper utilization, the data collected by UAVs can augment and complement such technologies as photometric processing, structural condition monitoring and failure recognition. All of these can help refine shipyard specifications, enhance repair plans and reduce overall cost by providing greater knowledge of the asset's condition. Currently, the mainstay of UAV inspection is the High-Definition (HD) camera, for photograph and video data collection. However, the impact of emerging technologies on UAVs such as infrared emission sensors, thickness gauging tools, LiDAR scanners, etc., to the Class survey scope requires further study and research.

The offshore industry has always been at the vanguard of technical innovation and this is not about to change. The next wave of technology will not come, however, from new ways to bend the physical world to our will with steel and human power but from bits and bytes through digitalisation. Digitalisation is not new to our industry. Now the technology is cheaper and faster and the amount of data and level of connectivity are increasing exponentially, the application of digital technologies can deliver at an affordable cost. The energy industry is emerging from a lower-price environment in better shape and with more resilience and an increased focus on capital efficiency, cost performance and safety. The industry is also ready for a digital transformation that offers a big, if not the biggest yet, opportunity to improve efficiency in our existing operations even further. This transformative potential has been recognized for some years. What has been missing is a comprehensive approach for applying digital technologies successfully at scale in the oil and gas industry. This reflects one of the significant differences with previous waves of innovation: most of the benefit for existing businesses will come from replication and rapid improvement cycles of across many assets and projects. In addition, digitalisation also opens up the opportunity for new business models that could change the entire industry structure. This paper explores an approach to digitalisation that draws on successful use cases that have already realized significant value in Shell's operations. It identifies the underlying principles of the digitalisation strategy, including data strategy, approach to insourcing versus outsourcing and methodology of scaling up. The required success factors that underpin digitalisation are also explored: capability building for both people and IT/data systems; how to organize the digital deployment; and the required leadership, culture and way of working attributes. Practical examples and insights from Shell's digitalisation journey will be provided.

As a result of intense pressure to reduce costs in offshore oil and gas operations, there has been a surge in support and use of ruggedized unmanned surface vehicles (USVs or ASVs) for several standard tasks in Exploration and Production (E&P), Inspection, Maintenance and Repair (IMR), and Survey operations. As illustrated in several recent case studies from marine construction, seismic, pipelay, hydrographic, and environmental applications, this technology is no longer in development mode, but has in fact become a key element in the re-tooling of the offshore industry for more efficient and safer operations. This paper addresses and reviews a number of important design considerations for ASVs being used in the offshore oil and gas industry. Applications which will be elaborated will include pipeline route surveys, ROV tracking/touch down monitoring, LBL array box-in and calibrations, as-built geophysical surveys for pipelines, unmanned seismic energy source operations for reservoir monitoring, marine mammal acoustic and visual monitoring, and hydrocarbon leak/seep detection operations. Included in this paper are case study observations and data from projects offshore Europe, Gulf of Mexico, the Mediterranean Sea, and Alaska. These results in several cases will also be presented to provide a clear comparison between standard methods showing the cost savings achieved by use of this technology. In all cases, the decreased project costs were made in parallel with no loss of data quality. In some cases, an improvement in data quality over standard methods was made, along with the decreased operational costs. The use of unmanned surface systems in offshore oil and gas operations has become a proven cost reduction tool. A growing number of contractors and operators are now using this technology with good results. In some cases, operators are now specifying this technology be offered by their contractors in order to reduce costs, with measurable results. The decrease in at-sea man hours has also provided a significant risk reduction aspect.

Over the last 40 years there have been a number of high profile disasters in the global oil and gas industry that have left a permanent scar on the sector's psyche. While the US oil and gas industry has been vigilant in developing programs to improve the safety of the drilling and completion process, it has yet to completely embrace the International Offshore Emergency Response (ER) Framework that is widely used by other oil and gas producing regions around the world for handling major emergencies. It is absolutely right that industry works as one to ensure all risks are identified but with recent industry studies suggesting up to 80% of accidents in the offshore sector are the result of human error – and an acceptance that it is impossible to entirely eliminate human fallibility –are we gambling with people's lives by not giving the same commitment towards ensuring workers know what to do in the event of an emergency? The ER Framework was created to ensure all personnel travelling or working offshore are trained to respond appropriately in the event of an emergency. Underpinned by competency based training with specific learning outcomes, it provides the safeguard that all personnel regardless of employer, discipline or experience, know what to do and when to do it. This presentation will look at how the framework was developed by the oil and gas industry for the oil and gas industry, how the lessons learned in other hydrocarbon hubs around the world helped shape them and the perceived barriers that exist in the US. It will consider the interconnection between standards and examine how basic training like H2S or Tropical Helicopter Underwater Escape Training are essential for all workers travelling offshore; and explore the impact of the gap between operators and contractors in the training and management of specialty roles such as helicopter landing officer in effectively controlling an emergency. It will also consider how advances in technology and changing environmental factors are influencing the continual review and development of industry standards. The standards are driven by the needs of employers to help create a safe and competent workforce. They help major employers and SME's around the world prepare for, respond to and maintain control throughout the development or escalation of an emergency situation. The presentation will conclude that while significant strides have been taken, for a country which has led the world in so many ways we lag far behind others in the use of common industry standards. The question every oil and gas leader must ask themselves is: If the worst happens, don't you want to know that you have prepared every one of your people to the highest level you possibly could?

Additive manufacturing (AM) is estimated to grow significantly in the next few years, the potential for AM is significant, however, AM is not the plug and play technology that it appears to be, AM works for specific applications, the first question that should always be asked is ‘does it make sense to make the product using AM compared to more traditional methods of manufacture’. The hype around AM has led many traditional manufacturers to assume that the manufacturing controls and material properties for a given material produced by AM processes are similar (if not the same) as those required and resultant from a conventional manufacturing process (such as a forging). There are many individual steps involved in the process of manufacturing a part by AM. In order to have confidence in the integrity of the part each of these individual steps must be carried out correctly and can greatly reduce production cost and time, yet there is no standardized way of proving to manufacturers and regulators that printed products are safe. LR is working with a number of partners, to consolidate research and development efforts, alongside real-world AM practices, to create new product certification guidelines - paving the way for widespread adoption of the technology. The purpose of the guidance document is to provide industry with goal-based certification guidelines for the manufacture of metallic parts/components using additive manufacturing (AM).

Space is an extremely harsh environment that does not naturally support life. The challenges faced by the Space Program since its inception in the 1960's span from extreme temperature ranges, to pressurized systems, low pressure environments requiring remote operations, and countless other obstacles, including training of personnel for dealing with these hazardous environments in a controlled and safe manner. This paper provides an overview of the shared challenges, gives an overview of NASA's collaboration and innovation initiatives, and presents technologies and solutions envisioned to be beneficial to offshore industry.

The high-specification 18 ¾ blowout preventers (BOPs) of today have a maximum design pressure of 15,000 psi and a maximum design temperature of 250°F. However, the industry is preparing to push the threshold one step higher in both pressure and temperature. Existing 18 ¾ BOPs cannot accommodate new oil and gas discoveries that impose higher pressures and higher temperatures than the applicable American Petroleum Institute (API) standards can address. For many reasons, including safety, these high pressure and high temperature (HPHT) discoveries (>15,000 psi, >250°F) cannot be developed without design and manufacturing standards above and beyond existing standards and industry practice. However, developing these standards is difficult because the task requires the application of design methods not commonly used before in the industry. In this paper, a technology qualification methodology based on API and American Society of Mechanical Engineers (ASME) accepted design codes was used to define a design approach for HPHT subsea BOP stack equipment and systems. The methodology includes quantification by the development of equations and qualification by the development of processes. Design equations are validated by confirming that the appropriate API and ASME Boiler and Pressure Vessel Code (B&PVC) design standards are applied. Once defined, the correctness of their application is verified. Once the design is complete, other processes must be defined to assure that the design is manufactured, operated, and maintained as required. Qualification and acceptance-testing criteria are developed during the process per the existing API standards and additional requirements. Other API requirements used in conjunction with the manufacturer's procedures enable the BOP to be fabricated as specified. The BOP is but one component of a drilling system that must operate over time. Risk studies are required to confirm that the BOP, its controls, its supporting equipment, and the rest of the drilling system will operate within the required performance envelope. Additional risk studies will be defined in the development of maintenance procedures. The application of the methods described enable HPHT subsea BOPs to be designed and built using existing codes as well as newly defined methods. Other methods described in this paper examine the performance of BOPs and controls as an integrated system and how it can be best maintained. Design standards for HPHT BOPs can be drafted on a foundation of existing API and ASME codes and in conjunction with the methods identified. The development of design standards for HPHT 18 ¾” BOPs was inhibited by a lack of industry application and experience, as well as a lack of service history, but with new HPHT discoveries now in development, such standards are needed. This reticence to develop standards was further enforced by the absence of a clearly-defined design approach. This paper presents a methodology for qualifying this complex equipment that can be built and operated safely, so that the industry can continue to push the operational envelope of subsea development.

Abstract Decommissioning Costs can be reduced. Many costs are higher than needed due to decisions made during the initial engineering and construction of an offshore oil or gas field. Five years of decommissioning data, throughout the world have been studied. Key areas have been identified where decisions made during design have affected the eventual decommissioning costs. Examples of possible decommissioning cost savings are listed. Economics for 60, 000 barrels of oil per day oil field show that a reduction in decommissioning costs of 50% can increase the Project Net Present Value by 13%. The five stages of decommissioning an offshore development are described with the cost percentage split for each stage using North Sea data. The major cost drivers of a decommissioning project are stated. For each of the major cost drivers practical examples are given as how the costs could be reduced during design by changing the design. These changes will increase the choices for removal. The scope of the decommissioning studies during conceptual and detailed design are listed. Finally the missing technologies will be listed as experience has shown that cost reduction and safety can be enhanced if new technology could be developed. The guidance for project design reviews is provided to direct designers and engineers so they can consider decommissioning as part of their work.

Abstract Following the beginning of the offshore industry in the late 1940s, APIstructural standards for offshore structures made their first appearance in thelate 1960s. As the offshore industry moved out of its initial cradle in theGulf of Mexico and expanded to other regions of the world, it becameincreasingly obvious that while some of the basic principles developed andadopted by the industry could be readily and effectively exported to othergeographic areas, differences in environmental conditions, working practicesand political and commercial realities provided a strong drive towardsprogressive generalization and globalization of the standards developmentactivities. The early 1990s saw the start of an ambitious effort to develop worldwideoffshore structural standards under the aegis of ISO, with API and the USindustry providing a strong support and commitment to the initiative, alongsideother countries with an active offshore industry, such as, in no particularorder, UK, Norway, France, Italy, Brazil, etc. The ISO effort has by nowproduced the first generation of the ISO 19900 suite. For many reasons, as described in this paper, the development of the APIstructural suite and the later ISO effort followed a different historical path, leading to a different document portfolio architecture. As part of its supportto the global initiative, over the past 6 years the API Offshore StructuresCommittee has undertaken a coordinated and very intense effort to redesign itsdocument portfolio, leading initially to a substantial alignment of the twosuites of standards, with a view to achieve a progressive merger. This paperprovides an update of the status of this effort, and some general guidelinesfor the use of the document portfolio. Introduction Wells in lakes, marshes and in shallow, near shore, ocean waters have beendrilled and produced since the late 1800s in several areas of the world(California, Louisiana, Venezuela, Caspian Sea, etc.). However, it was theoffshore platform installed in 1947 on a Kerr McGee lease in the Gulf ofMexico, out of the sight of land, that marked the beginning of what is todayreferred to as the offshore industry. In the early years, fixed platforms and submersible drilling barges weremainstays of the industry. Structures were designed incorporating land-baseddesign practices modified to suit the new, unfamiliar environment. Steel andconcrete structures had been designed, built and utilized for years on land andin marine environment applications of both fresh and salt water environments, most notably port and harbor facilities as well as piers extending from land. However, moving offshore introduced a whole new set of design, construction andoperating challenges. Storm driven waves had a considerable effect on fixedplatforms, while winds became an increasingly critical factor floatingstructures, which made their appearance in the 1960s. Velman and Lagers providea comprehensive historical discussion on the development of the offshoreindustry (1). While the design of fixed offshore structures required a significant extensionof standard practices for land structures, the practices for floatingfacilities had a historical precedent in the form of classification societyrules. In the very early days of the late 1940s and 1950s, rules for strengthand stability developed by classification societies could be applied to bargesutilized in offshore operations. Given the early reliance on class rules foroffshore barges, it became almost natural to leave it to class societies topromulgate new standards for floating facilities, rather than expecting the oiland gas industry to complete this task. As a consequence, the appearance of thefirst purpose-built drilling semi-submersible, the Ocean Driller, in 1963, ledto the first offshore industry floating standard developed by class societies, which addressed mobile offshore drilling units (MODUs).

Abstract Projects related to the offshore industry are often involved with the realization of complex infrastructures in sensitive marine environments. These projects show serious concerns about the preservation of environmental values, strong demands on assessment of impacts, strict controls on work methods and extensive monitoring programs during project realization. Generally, the contractor is responsible for minimizing the environmental impacts caused during project realization. Various impacts relate to dredging operations. This has readily inspired Royal Boskalis Westminster NV to develop a series of innovations aiming to mitigate the direct impact of dredging activities. Sustainable and cost-efficient realization of such projects can only be achieved on the basis of thorough understanding of dredging processes and their impact on the natural environment and state of the art environmental management and monitoring strategies. Turbidity increase is the most common environmental effect of dredging operations. Boskalis has recently been involved in various projects (e.g. the construction of LNG terminals and pipeline-landfalls) that involved stringent limits to dredge-induced turbidity. By applying preparatory numerical environmental modeling, real-time monitoring control and implementing strict environmental management procedures Boskalis has proven to be able to control the impact of dredging works and realize complex projects in a sustainable and cost-efficient manner. From these recent projects, various lessons were learned that helped to improve the management of environmental impact related to dredging works. These lessons are: Each project is unique. Restrictions and lessons learned at one project should be used with great care for the next project; Dredging-induced impacts should be evaluated for each project in relation to the surrounding ecosystem. Environmental restrictions should be based on the resilience of the local ecosystem, while accounting for natural fluctuations; Monitoring programs should be designed in an adaptive manner, to allow for review of the procedures and make adjustments if appropriate; Environmental monitoring should be integral part of project planning, to avoid unforeseen delays and costs. Recent projects have demonstrated Boskalis' capability to successfully apply complex environmental monitoring strategies in present-day dredging practise. When communicated to the outside world, monitoring data were found to facilitate stakeholder involvement and public information purposes. In this way, environmental monitoring is of direct relevance for the success of marine infrastructure projects and their appreciation by the general public.

Abstract The commercial nuclear power industry has developed and applied improved methods for safety and performance management since the accident at Three Mile Island (TMI) in 1979. These include methods for risk management, identification and application of lessons learned, risk informed regulation, and safety culture improvement. Methods have also been developed to identify strategies and procedures to manage severe accidents - e.g. events outside the design basis that formed the envelope for the initial operating license. The combined implementation of all these technical, organizational, and regulatory changes has led to a significant industry-wide improvement in the performance of nuclear power plants in the US since TMI. This paper summarizes these developments in the nuclear industry, describes a recent application to risk informed safety culture assessment for a Canadian nuclear power station, and explores the potential to apply these methods for design, operation, and regulation of offshore facilities as part of the industry response to the Deepwater Horizon accident. Nuclear industry practices prior to Three Mile Island From the beginnings of the commercial nuclear power industry in the United States in the 1960's the primary unifying concept for demonstrating safety was the Design Basis Accident (DBA). A design basis accident is a postulated event that the plant must withstand. The Safety Analysis Report (SAR) for each facility was required to demonstrate that the plant could withstand the occurrence of specific prescribed DBAs. Examples include loss of coolant accidents (LOCAs), reactivity accidents, steam generator tube ruptures, loss of offsite power, etc. In addition to forming the basis for demonstrating that the plant could be operated safely within a prescribed " safe operating envelope,?? DBAs also established (perhaps inadvertently) the basic paradigm for the development of emergency operating procedures. Similarly, the design of instrumentation was intended to provide information up to but not beyond the conditions expected during a Design Basis Accident. Hidden within the emergency procedures were the assumptions that plant operators would be able to accurately diagnose the event in progress, and their major role would be to monitor the performance of automatic systems and only intervene when automatic systems failed to actuate or to restore normal conditions once the automatic systems had carried out their assigned functions. Finally, there was likely an unconscious assumption that events more serious than the design basis accident would not (or perhaps could not) occur, and that if a plant could withstand the DBAs then safety was assured for other conceivable accident sequences. Unfortunately, as we shall see later, these numerous, often unspoken assumptions were fundamentally flawed.

Abstract Following the Piper Alpha disaster in UK 6 July 1988, with 167 fatalities, a major shift was called for in the Safety Regulatory Scheme in UK. Among changes introduced were requirements to Safety Case. In Norway, a similar scheme had already been in practical use for some years. Other countries as Australia have later introduced similar regulations. In some countries as e.g. China, Brazil and Indonesia, some Operating Companies are following similar schemes although not specifically required by the regulations. For mobile drilling Units (MOU) the IADC has developed a global Case Guideline which is recognized by Authorities, Owners and Operating Companies. The challenge is to ensure that the Safety Case is addressing the critical safety aspect of the operations, applying state of the art methodologies and data and keep the Safety Cases up to date as "living and useful document". The conveyance of useful information to personnel in first line of command onboard is another challenge. The well prepared Safety Case may be an important instrument in conveying the understanding of major hazard risk potential to employees and the training for handling emergency situations. When MOUs are sailing from one part of the world to another, the Safety Case sails with. A Safety Case prepared for one country is normally accepted in another; subject to a site specific update Experiences from MOUs use of Safety Cases when moving around is discussed. The directions from the preliminary investigations after the GOM blowout may point towards a shift in the regulatory requirement in US Deepwater operations towards more functional requirements. It is LR view that functional requirements will be a valuable supplement to the more prescriptive approach that has been the standard. Introduction Safety Regimes normally changes in the aftermath of major accidents. The marine industry has been suffering from loss of ships and crews/passengers since man started his voyages on seas, and the step change improvements to the marine industry have often been in the aftermath of major losses. E.g. the LR Ship Classification Rules have been subject to changes continuously since LR was founded in 1760. The offshore oil and gas industry is very closely related to the marine industry. Growing up with the offshore industry in Norway it is very natural to remind myself of the Alexander Kielland Accommodation rig which capsized in 1980, causing 123 fatalities and a lot of survivors with traumas for the rest of their lives. The safety regime in Norway changed, reflecting the focus from public and the politicians as well as the owners and other stakeholders. Similar, the Piper Alpha accident in 1988 on the British Continental shelf shifted the regulatory regime in UK significantly. In both cases the industry as well as the regulators recognized the need for revised technical standards as well as e need for improved work processes to improve the overall safety standard. One of the very important consequences from the accidents mentioned above was the increased focus on R&D; new and improved knowledge was required and this enabled both budgets and management attention wherefrom improved methodologies and tools could be developed. There were some new basic fundamental requirements established, e.g. the need for a well structured and documented safety management system. An industry standard for Safety Management has been established since then e.g. documented in ISO standards and industry standards such as API.

Abstract The paper provides an overview of the many challenges facing prospective underwater mining ventures and an overview of processes which have been proven to be successful in overcoming these challenges. The paper is based on 15 years of practical consulting and project experience working with a diverse set of clients and client needs. The information provided will be beneficial to business and project managers involved with exploration and for new mineral resources and underwater sampling and mining systems development. Underwater mining has been practiced for centuries, but in recent times we have seen both success and failure. As land based resources diminish and technology developments progress, underwater mining has become increasingly accepted as a viable alternative source of minerals to land based resources. Successful operations are built on sound system identification and development processes of the resource, the equipment and the management processes. It is becoming increasingly important to not only focus on the technical solutions but also the system acquisition processes and subsequent operations management of underwater mines to ensure sustainable success. In order to initiate a sound acquisition process it is necessary to develop a comprehensive set of system requirements which will satisfy the business need. Together with these requirements it is also crucial to gather sufficient geotechnical information to enable mining tool design. It is equally important to be aware of and manage the regulatory and environmental aspects during the development process. The process of licensing and approval can take years, and as such, it is necessary to initiate these processes very early in the mine development cycle. Mines within the exclusive economic zones are governed by the coastal nations legislation, and mines beyond that are governed by the International Seabed Authority. System acquisition requires a structured approach to ensure successful identification, selection and development. Due to the relatively recent and progressive move into underwater mining there are few ‘off the shelf’ solutions and as such it must be accepted that there will be some level of development in most if not all underwater mining projects. Challenges include clients unfamiliar with the underwater mining environment, lack of geotechnical information, ore-body variability, reliance on research and development, early investment requirements during the project cycle, and limited benchmarking opportunities. Specific project implementation and operations challenges are in many cases similar to the offshore industry. Challenges include space and weight constraints, implementation in foreign countries, and complex integration of marine, mining and beneficiation plant equipment on highly congested work sites. Mining is by nature a harsh working environment for both people and equipment. A thorough development process of both the resource and the mining systems, and sufficient investment in personnel and equipment can however mitigate the risks and set resource license holders up for many years of profitable operations.

Abstract The HYCOM (HYbrid Coordinate Ocean Model) consortium, sponsored by the National Ocean Partnership Program (NOPP), provides near real time global estimates of daily mean current data back to November 2003. In April 2005, the US Minerals Management Service (MMS) issued a Notice to Lessees and Operators (NTL) regarding the reporting of ocean current data in the deep water of Gulf of Mexico. An extensive body of NTL current data has since been collected by the offshore oil and gas industry and made available via the National Data Buoy Center (NDBC) web site. This provides an extremely valuable source of observational data for current model validation at deepwater drilling locations in the Gulf of Mexico. Careful validation of the HYCOM model is required to ensure critical features of the current regime are adequately represented and to assess model skill. The paper describes the methodology and results of a HYCOM current model validation exercise using the MMS NTL observations in the Gulf of Mexico. The suitability of the model for the offshore industry in Gulf of Mexico is discussed. Introduction As the offshore industry is moving to ever-deeper waters, assessment of the ocean current is required. The knowledge of the ocean currents through depth is essential to riser design and control, operation of Dynamically Positioned Vessels, and other elements of engineering design and operation of deepwater oil and gas facilities. The Hybrid Coordinate Ocean Model (HYCOM) consortium is a multi-institutional effort funded by the National Ocean Partnership Program (NOPP), as part of the U. S. Global Ocean Data Assimilation Experiment (GODAE), to develop and evaluate a data-assimilative hybrid isopycnal-sigma-pressure (generalized) coordinate ocean model (called HYbrid Coordinate Ocean Model or HYCOM). The horizontal dimensions of the global grid are 4500 × 3298 grid points resulting in ~7 km spacing on average. There are up to 32 vertical layers, depending on the water depth, with output at standard Levitus depth levels. Daily data are available from 3 November 2003 to three days into the future (Chassignet et al., 2009). On April 21, 2005, the US Minerals Management Service (MMS) issued a Notice to Lessees and Operators (NTL) regarding the reporting of ocean current data in the deep water of Gulf of Mexico. Since then, the offshore oil and gas industry has collected and reported current data, using Acoustic Doppler Current Profilers (ADCPs), at 78 deep water drilling locations in the Gulf of Mexico. The extensive body of NTL ADCP current data has been made available via the National Oceanic and Atmospheric Administration (NOAA) National Data Buoy Center (NDBC) web site1. This provides an extremely valuable source of observational data for model validation at deepwater drilling locations in Gulf of Mexico. Based on the results of the HYCOM validation in the Gulf of Mexico, this study assesses the suitability of the model for application by the offshore industry in the Gulf of Mexico.

Abstract Based on the earlier work of pioneers in risk management in the offshore industry, the panel will discuss various types of risk associated with the new opportunities and challenges that now face the offshore industry. The various risks include geological and engineering evaluations, commercial concerns, weather risks, and setting contract terms between culturally diverse people. The panel will speak to identifying the risks, setting risk base-lines, and addressing uncertainty. Having a reasonable assessment of risk allows decision-makers to assess the true value and potential return of projects in the offshore industry and provides clear windows of opportunity for investors. INTRODUCTION The decision to go forward with new energy opportunities, and pursue an associated offshore project is clearly premised on an expectation of a return on investment. The return, however, is affected by the amount of risk a project bears whether such risk is an operational risk including the use of new technologies or a commercial risk. It is important that each investor have a clear understanding of the known and potential risks. Different parties will be comfortable with different degree of risk. Each party must understand the degree of risk the other party is willing to accept and what type of return is expected. So, it is not only preferable, but imperative, that individuals, teams and entities adopt and use reliable methodologies in order to make informed decisions. This paper is designed to provide a general outline of the different risks to be considered in an offshore industry project and offers examples of each type of risk. The paper has been written to facilitate discussion and questions for attendees to ask the panel at the conference, and may further serve as an outline or checklist when analyzing and determining various risks in any offshore industry project. Discussion I. Operational Risks A. Geological Common geological concerns often center on structure, reservoir, hydrocarbon charge and seal. 1 Other geological factors can be of a geohazard nature including: Slope instability Shallow gas Natural gas hydrates and their climate-controlled dissociation Shallow water flows Mud diapirism and mud volcanism Active fluid seepage and seafloor pockmark formation Seismicity - which may trigger slides - may cause tsunamis and disturb subsurface geological conditions, e.g. pore pressures Excess pore pressure development, in relation to fluid migration and sediment accumulation Assessment of geotechnical properties of seabed sediments. 2 Geohazards may also be manmade. These manmade geohazards include " existing offshore installations, pipelines or cables, shipwrecks, military dumping grounds, and maritime regulations??. 3