New innovative services and goods based on artificial intelligence, next-generation robotics, autonomy, digitization, and electrification are taking root in the ocean economy. More typical competitive forces, such as value enhancement and safety improvement, are also present, as suppliers constantly strive to improve their competitive positioning. Concurrently, the Oil and Gas sector is experiencing mounting pressure to decrease its operational carbon emissions, forcing efforts to reduce or eliminate liquid fuel consumption offshore. Companies in the ocean economy are having to react to this combination of macro- and micro-level drivers and innovate at an ever more rapid pace. However, before many of these new capabilities can be implemented, new, clean, reliable power sources are needed, especially as liquid fuel grows increasingly out of favor. For many of these loads—both old and new and ranging from watts to megawatts—wave energy systems provide the best solution for remote power generation. As such, research, development and demonstration activities are underway to prove wave energy's ability to provide reliable, consistent energy supplies for certain offshore Oil and Gas activities, paving the way for near term commercialization. This paper outlines these drivers, competitive reaction to them, and why and how wave energy can be a preferable choice for power at sea.

This paper focuses on the benefits of removing existing control boundaries between subsea system components/parts and the automation setup located topsides on the platform (or onshore). The paper describes the communication architecture of existing subsea control systems used today and proposes a new architecture with boundaries removed. This new setup would utilize the same physical (i.e. fiber-optic) communication channels as present systems. For illustrative purposes, a use case for the proposed system will be presented on an anti-surge setup for a subsea pump/compressor. Existing subsea control systems today are intended for and used to control hydraulic valves in subsea production setups. The design and behavior of these systems make them not optimal for anti-surge control (among other applications). Interfaces and communication protocols used in the proposed use case are based on open industry standards, resulting in a vendor-agnostic system with no proprietary or company-specific solutions, and no boundary between the subsea and topside/onshore located parts. Potential benefits of the proposed system would include reduced latency, along with the combining of several measured values for increased accuracy over a larger scale, illustrated with an anti-surge example. This could enable operators to realize cost savings through optimization and increased production over the life of the installation. As the paper will describe, the system also has the potential to reduce both CAPEX and OPEX.

The Operator and the license partnership have set an extremely high ambition for recovery from the Johan Sverdrup field, even before a barrel of oil has been produced. How is this possible? This paper describes the characteristics of the reservoir, as well as early assessments and investments for improved oil recovery (IOR) to ensure flexibility. In addition, data acquisition, reservoir monitoring, new technologies and digitalisation, as well as new ways of working are addressed. This will be the key enablers for a recovery of more than 70% of the field’s oil resources. Johan Sverdrup is the third largest oil field on the Norwegian Continental Shelf (NCS) with a recoverable volume range of 2,2 to 3,2 billion b.o.e. The reservoir is characterized by excellent reservoir properties with a strongly undersaturated oil. The primary drainage strategy is water flooding, including re-injection of all produced water, supplemented by water-alternating-gas (WAG) injection at the end of the oil production plateau. The field came on stream in October 2019. Going back to the early stages of the Johan Sverdrup field development, it was obvious from the start that this would be an independent development solution with a long lifetime. Given the excellent reservoir, this was considered as a unique opportunity to plan for a high resource exploitation, and make sure that future business opportunities in this context could be utilized in a technical and economically attractive way. A very early screening was conducted to investigate which IOR measures should be further matured. With subsurface evaluations as the base, this maturation also included assessments on technical feasibility and potential implications for development solutions. The objective was to ensure sufficient flexibility in early field design. It also implied that the Johan Sverdrup license had to consider pre-investments prior to any implementation decision. Data acquisition and reservoir monitoring strategies were also started early on, which e.g. led to a full field Permanent Reservoir Monitoring (PRM) decision, with installation starting summer 2019. This gives a baseline for parts of the field before production start, and when completed in 2020 it will be the world’s largest fiber based PRM system. Fiber optics are also installed in the wells. In addition, a dedicated observation well is part of the development plan. The idea is that PRM and fiber data results, in addition to repeated logging in the observation well, will be key information to evaluate business cases for future IOR or new technology measures. Digitalisation has also been a key aspect of this, and several subsurface-focused digitalisation initiatives have been implemented during the field development, giving the operator the opportunity to implement new ways of working and enabling new ways of cooperation in the partnership as data and applications are shared within the owner group in a digital setting. The overall objective of digitalisation in this context is to further optimize the analysis and management of the Johan Sverdrup reservoir – and hence value of the Johan Sverdrup field – for the license owners.

Service providers for subsea inspection, maintenance, and repair (IMR) generally utilize remotely operated vehicles (ROVs), tethered to a surface vessel and piloted in real-time, to evaluate and manipulate underwater infrastructure. The cost of these operations can be considerable, mostly due to the need to deploy a large surface vessel and crew to support the IMR campaign. Recent progress in marine autonomy, acoustic communication, and artificial intelligence, however, enables new approaches to subsea IMR that could substantially reduce the need for an on-site support vessel and, consequently, the overall cost of these activities. This work describes a novel multi-agent autonomous system comprising an autonomous underwater vehicle (AUV) and unmanned surface vessel (USV). We describe a unique AUV configuration that incorporates a custom high-bandwidth acoustic communication system capable of video transmission to the surface. A state-of-the-art proprietary USV was configured to act as a communication gateway for the AUV, enabling remote mission management from a nearby support vessel. We describe the results of a field test campaign in which real-time video transmission from the AUV was demonstrated at a depth of approximately 900 m. We also describe results from a shallow water test in which the AUV's profiling sonar and integrated lidar system were used to generate 3D maps of a wreck of a World War 2 fighter plane.

To support the digitalization trend in the industry, a higher degree of automation is required. Equinor has launched an Underwater Intervention Drone (UID) initiative backing this trend and paving the way for new, flexible and cost-efficient operation and maintenance philosophies. To cater for this technology the subsea control system infrastructure must be prepared for. The target of the UID initiative is to develop concepts and solutions to establish cost effective technologies equally striving for standardisation of products and interfaces. The UID initiative aims to have a system approach and examine the impact on all elements of a subsea development, i.e. covering topside, umbilical, SPS, docking station and drone. This will safeguard the benefits during technology implementation and operation. As part of that, the UID control system needs to be designed under consideration of aspects such as safety, application, robustness, simplicity, standardization, cost of ownership and project execution philosophy. While most of the main technology elements are available and proven in use there is a great potential for interface standardization by introduction of new equipment such as the Subsea Docking Station (SDS). New interfaces between well-established subsea disciplines such as subsea control and distribution, subsea production, and intervention systems will have to be handled to ensure seamless integration. This provides the possibility of open-standard solutions ensuring interoperability and interchangeability from day one. With focus on UID control system infrastructure, this paper will present the current status of the UID initiative with focus on the UID subsea control system covering: the fundamental features of the UID control system technology and concept the consequences of UID technology for the design of production control systems status of the UID subsea control system initiative with respect to technology maturity the activities required to close the identified technical gaps the implementation strategy

Oil and Gas Operators are moving active production and injection equipment onto the seabed with the aim of reducing CAPEX and/or topside space requirements. Moreover, they want to minimize new production floating facilities (e.g. through tie-back to existing FPSO/Floaters). Given this scenario, the overall electric power needs may become an issue because of the extra power demand due to the increasing number of electric consumers placed subsea. These electric loads may include the subsea boosting (pumps or compressors) operations, pipeline heating or the typical subsea water, chemical injection and valves actuation (in the case of all electric control systems), just to mention some of potential subsea power consumers, and may exceed the existing FPSO/Floater power production capacity. A potential solution to overcome this issue consists of the deployment of wind generators combined with topside Island power generation. Offshore wind power is indeed more and more considered for shore power supply, but also by the Oil and Gas industry with the objective of reducing the carbon footprint of their facilities. High power marine wind generators are already consolidated technologies for near coast, and today they are evolving in the short-term to floating solutions for the open sea. Saipem has developed its own floating wind turbine solution, called Hexafloat, consisting in a pendular floating foundation made of tubular elements and connected through tendons to a counterweight. This solution is particularly cost-competitive for deepwater locations (thanks to the low mooring costs) even for harsh environmental conditions (thanks to an excellent stability), and will unlock the possibility to deploy large wind power generators far from the coastline in deep water. The system composed by the Hexafloat base and the wind generator may be equipped with onboard back-up generation utilities to provide continuous power supply for subsea, despite wind intermittency, and to provide support to certain subsea field development services, making the assembly a kind of supporting device for the subsea field or for the FPSO. This is the Windstream concept that is under internal development and that will be better described in the present paper through the explanation of the results achieved within a couple of case-studies analyzed.

Field A is located offshore of Peninsular Malaysia, consists of multi stacked reservoirs where previously the vertical communication between different units was considered to be well understood. Separate reservoir models were built independently where fair to good history matching were achieved during the dynamic modelling study. Subsequently two drilling campaigns were executed based on the simulation results. On top of that, regular reservoir surveillance and frequent simulation model updates have assisted in assessing vertical connectivity. North of Field A, a recent drilling campaign in early 2019 indicated possible communication between infill wells in Unit 35U and water injectors in Unit 35L. One of the well is experiencing severe watercut production than initially forecasted. It is well understood that the seismic amplitude for Unit 35L is being overlapped by the stronger response of Unit 35U in the northern area. Due to that, the reservoir modelling and understanding for Unit 35L in this region is mainly driven by actual well controls and the geological model, rather than from seismic. Meanwhile in the Southern area, a stable reservoir pressure trend is observed in Unit 27 despite reduction of cumulative voidage replacement ratio (VRR) from 0.6 to 0.4. Additionally well C02ST1 was producing oil at an increasing rate, a trend which the current reservoir model failed to match. The model also failed to explain the unreasonably high recovery factor (RF) of 50% for Unit 27 given the delayed water injection and small gas cap support. Back to the North, well interference testing was conducted by shutting in water injectors in Unit 35L and observing the pressure response of a new well in Unit 35U using a permanent downhole gauge (PDG). Observations indicated a decrease in pressure response once injection was turned off, confirming the communication between the two units. Moving forward, two injectors for Unit 35L will be temporarily suspended to relax the watercut trend in the new wells, thus improving the oil rate. In the South, a material balance study and reservoir 3D model suggest additional volume needs to be introduced for Unit 27, which indicates that it is probably draining Unit 35U oil due to a higher level of vertical communication and overlapping sand bodies between both units. This is also supported by produced water salinity readings of well C02ST1 (Unit 27) having similar values as Unit 35U wells rather than other Unit 27 wells. Communication between different layers often requires longer time and a significant amount of production to be well established and observed. This case study proves that reservoir understanding can still be a mystery even when the field is reaching 20 years of production.

The cultural step-change for a successful digital transformation in the Oil & Gas industry is a significant struggle. Under the pressure of executing projects with a lower budget and in time during this low oil price era, project management becomes a complex challenge. In addition, the endeavor in digital technology imposes a transition from traditional project execution to agile project execution which makes the transformation even more challenging. Thus, the objective of this paper is to present a novel way of project management called "Open Project Management" (OPM) using a digital platform that helps team members and employees to engage in the digital transformation process using social networking technology. The Open Project Management (OPM) approach is planned and organized to bridge the traditional project management (TPM) processes (plan-execution-control/monitoring-closing cycle), and the agile project management (APM) processes (short sprint iterations of planning-analysis-design-test-acceptance cycle), by focusing on the basic project building blocks: project deliverables. In the OPM platform, all project members and management processes are directly connected thru the project deliverables (either working packages or sprints). The OPM is flexible enough to switch between the traditional, the agile, or a blended approach. The open approach is aimed to empower employees by offering leadership through a self-management and ease execution work by sharing and collaborating with other project team members and project managers. To implement the OPM approach, a digital collaborative workspace platform is built to mimic familiar social media networks so that employees can perform their work within the system with minimal training. The OPM platform is comprised of 3 frameworks: i) project management, ii) project visualization and iii) project communications. These three digital frameworks combinedly allow every member to work in a collaborative way within the platform by integrating their work process and get quick feedback. The novelty of the OPM approach lies in creating autonomy, increasing transparency and more importantly engagement without face-to-face interaction for all stakeholders of the project execution. The OPM platform is an intelligent digital eco-system (iDES) that works like the traditional social media platforms, which allows employees bringing what they use in their personal lifestyle into work without adopting a new system. The workspace offers to create their work-image into the workplace, enhancing their motivation towards work and empower them. Such a project management strategy and the tool for successful implementation are essential to provide a transitional phase for employees to trigger the cultural step change required to implement digital transformation objectives.

The objective of this paper is to provide guidance to the practitioner initiating a model-based systems engineering (MBSE) approach to a system design process. The principles discussed here are applicable irrespective of the domain subject matter of the design and reflect experience drawn from across a range of domains from military-aerospace to property and casualty insurance process to healthcare delivery and subsea oil and gas operations. It is well recognized that the oil and gas industry has a substantial problem with cost overruns and schedule delays. Citing a 2014 Ernst and Young study of 365 projects with a proposed capital investment of above US$1b that reviewed project performance in the oil and gas industry They found that 64% are facing cost overruns and 73% are reporting schedule delays. [EYGM, 2014] Matthew Hause and Steve Ashfield tied the solution to much of the overrun and delay problems to a disciplined and integrated approach to systems engineering using MBSE. Hause (2018) All too often the move to MBSE begins with an embrace of the idea of MBSE as implemented in a particular configuration. Having heard of MBSE, "seen" MBSE in a particular tool, or heard a pitch for some "industry standard" approach, the practitioner is tempted to adopt outright the implementation of the MBSE solution that was presented. The reasoning is that, "the source of the presentation solved their problems by using Tool X so if we buy tool X and start building models, it will do systems engineering for us and solve our problems/make our lives easier." This reasoning contains a number of misconceptions that can get the adopter off to a bad start on an important journey. It is the aim of this paper to see that this temptation is avoided and the quality of the choices made is improved. NOTE: At many points in the initial journey to MBSE it will seem that the process suggested here slows the progress and makes the choice of MBSE less productive, perhaps even less productive than remaining with the status quo. But this is a confusion of operational speed with strategic speed. The good news is that the slowdown to carefully navigate the considerations and choices on the front end of the journey pays off in a higher quality solution at implementation. The "opposition" to instituting an organizational MBSE practice most often appears well-taken on the front end. By rejecting MBSE it appears that the design teams avoid creating "needless" diagrams, interviewing numerous stakeholders and refining large numbers of requirements. The time not "wasted" on paperwork and documentation can be spent on "real" design work. But this is an illusion. The MBSE process that is avoided turns out to be the very thing that would have mitigated or eliminated the inevitable problems that result from the shortcuts and skipped process steps. Design choices that are illuminated by the MBSE practice often fail to appear and are lost to the team. Preventable problems are missed and come back to haunt the design. In fact, project performance has been directly tied to the maturity of systems engineering practices. In a 2007-2008 study by the National Defense Industry Association (NDIA) and Carnegie Mellon University's Software Engineering Institute (SEI), only 15 percent of projects with a "low" systems engineering capability achieved a high level of performance while 56 percent of those with a "high" level of systems engineering capability exhibited a high level of performance. Elm (2011) This study provided confirmation of earlier studies of the benefits of systems engineering practices. It is critical to realize from the outset that the process of adopting model-based systems engineering is a journey and not simply a matter of making a choice. It is a journey in which we seek to move from where we are in our systems engineering practice to a desired state of that practice. Starting the journey without a clear picture of what we are seeking is as foolish as starting a long trip with no idea of where we are going. As Yogi Berra astutely pointed out, "If you don't know where you are going, you'll end up someplace else every time." The first step, therefore, is the definition of the destination for the journey.

The paper uses a case study approach to present the challenges to develop a large and thick oil carbonate reservoir, full of opportunities but also of uncertainties. Additionally, Libra block development is under a Production Share Contract that was award to a Consortium where Petrobras is the operator in partnership with Shell, Total, CNOOC and CNPC. The paper will briefly present the de-risking plan and detail the EWT Program implementation and the way it is helping the full field development, which consists of four mega ultra deepwaters projects.

Coupling Long-Range Autonomous Underwater Vehicles (LRAUVs) with Unmanned Surface Vehicles (USVs) solves two of the key challenges associated with LRAUV missions: lack of real-time communication with the underwater asset and unbounded navigational error growth from dead reckoning. The coupling of LRAUVs and USVs effectively transforms the capabilities and accuracy of the LRAUV survey. A premier supplier of Unmanned and Autonomous Marine Systems led this development project working alongside a world-leading research center and developer of LRAUV systems. These two organizations were assisted by a leading developer of subsea acoustic positioning, communications and sonar systems, and a developer of software solutions for autonomous systems. The system architecture enables the USV to provide regular position updates to the LRAUV, removing the need for the LRAUV to surface from depth to update its internally calculated position. This cooperative localization scheme increases the efficiency and accuracy of LRAUV survey while reducing cost. The combination of the high-accuracy sonar systems on the LRAUV transiting close to the seabed and accurate position updates from the USV provides game-changing solutions for deep water surveys and Exclusive Economic Zone (EEZ) mapping globally. Due to the endurance and autonomy, this combination also allows for the possibility of executing remote subsea operations from a shore-based location. Eliminating the need for large ships to accompany the LRAUV significantly reduces data acquisition costs. The USV communicates with the LRAUV through two key methods: acoustics to provide short mission updates and positioning information, and optical communication technology to enable the system to upload the data from the survey sensors. With the data uploaded to the USV, it is then possible for the USV to process the data to enable summary data to be passed back through satellite or radio communications to a control center. In situations where data may indicate where gaps occur, or further investigation is required, an updated mission plan can be transmitted from the control center to the USV and then to the LRAUV. As onboard data processing techniques improve, the USV can be used to adaptively update the LRAUV's mission without human intervention. This transition to autonomy will save costs, reduce risk, and increase flexibility across a range of applications, including mine countermeasures, weapons testing, hydrography, environmental science, security, and surveillance.

LH4-1 oil field is a subsea tie-back which was developed by CNOOC in 2012. After a short period of production, the subsea control umbilical started with low Insulation Resistance (IR) of its electric control quads. Extensive trouble shooting work immediately started. The trouble was identified to be on the main umbilical. The subsea electric control was swapped to the spare quad. After about a year, the spare quad also had zero IR. In order to resume the subsea control, feasibility of using the spare Medium Voltage (MV) power cable triads as control channel was studied immediately. The idea of using three core triad to establish dual communication channels with two frequency bands was thoroughly studied and it was found theoretically feasible. Originally the communication was one loop controls 4 wells, now with the new arrangement one loop controls 8 wells, 3-core with one as common return makes two loops. So the new MV cable communication configuration can still achieve subsea control with 100% redundancy. Subsea special bridge flyleads were designed and manufactured to convert the 70mm 2 3-core MV flylead to 10mm 2 4-core communication flylead. Offshore intervention work was done in 2014. After installation, subsea communication to all 8 wells was re-established as expected. The signal qualitywas much better that the original umbilical possibility due to the large MV copper cores.

Autonomous Underwater Vehicles (AUVs) have shown promise to disrupt Inspection, Maintenance, and Repair (IMR) activities typically performed by Remotely Operated Vehicles (ROVs) tethered to large, expensive vessels on the surface. There are many concepts and projects within oil and gas that are focused in utilizing the efficiencies of these AUVs in novel deployment framework. A novel autonomous vehicle platform in this domain is being developed called uROV (untethered ROV). The uROV vision has three main elements to bring to the IMR market. The first is to develop efficient deployment solutions such that IMR vessel expenditure is reduced or removed. The second is to bring next generation sensing technology to the market and integrate into the uROV platform. This is aimed at collecting better and more insightful data to use for integrity evaluation. The third main element is to bring digital enablement to the market through connectivity, data process automation, and visualization.

Potential applications for wave energy cover the spectrum from powering watt-scale maritime sensors to generating electricity at megawatt-scale. These applications include energy generation for: ocean observation, communications, autonomous underwater vehicles recharging, isolated community grids, aquaculture, underwater data centers, seawater desalination, ocean mining, disaster relief and recovery, and utility grids. Much of the focus to date has been on utility-scale systems for grid-connected applications. However, despite the effort to develop viable technologies and the attractiveness of the resource, wave energy has yet to achieve status as a mainstream renewable resource. According to REN21, 150 GW of wind and solar was installed last year, but in spite of this growth, wind and solar do not present a universal solution to our renewable energy needs. Without significant amounts of cost-effective storage to smooth and shift energy supplies, the intermittency of wind and solar leave gaps that must be filled with other, new renewable resources that are widespread, energy dense and close to the load. These issues are exacerbated in a maritime environment where wind and solar are not technically viable in many cases. Energy from marine hydrokinetic sources—mainly ocean waves, currents, and tides—will help fill the gap that wind and solar can’’t. Our oceans are the largest battery of stored energy on the planet; capable of providing 200% of our current global electricity supply & 30% of US demand (load). Wave energy, in particular, possesses the desirable characteristics of a new mainstream renewable, with nearly 7x the amount of tidal resource available globally. However, all marine energy resources present inhospitable operating environments, with a need to balance the competing interests of affordability on a local basis, acceptability of the system by the various stakeholders, and availability of the generation system on a consistent and reliable basis. While federally-funded wave energy research and development has been underway for over a decade, recent advances in wave energy technology present the opportunity to breakthrough these constraints and provide dependable, cost-effective energy. These advances also bring forward several potential market applications of interest to the maritime community, specifically low-power autonomous systems for maritime sensing, monitoring and communications payloads and utility-scale systems for provision of megawatt-scale energy. Potential customers of these systems—such as defense and security agencies, and oil&gas, industrial, aquaculture and telecommunications companies—need consistent and reliable energy storage and generation that reduces their cost of ownership for their current battery, solar or liquid fuel energy sources and/or enables operating capabilities and location persistence that is not currently available.

Subsea production systems and processes are generally conducted using hydraulic and more recently electro-hydraulic controls. These systems have become complex and expensive to deploy, especially with increasing length of tie-backs, more deepwater installations and challenging environments. Electrically powered and controlled equipment has become the standard for onshore and topsides equipment. Developing a subsea electric control unit that is modular and easily packaged is integral to leveraging the benefits of electric monitoring and control into subsea production systems and processes, as well as many other intervention applications such as subsea chemical storage and injection. In addition to simplifying and reducing costs of these systems, the unit will be able to discern an end component's health and status providing an opportunity to adjust or modify the operation in-situ, and in some instances real-time as well as provide other benefits. New analytical techniques powered by advanced analytics and artificial intelligence (AI) are being developed to examine in greater detail the controlled equipment's operational status, infer its current state of health and even predict future performance and maintenance/repair needs. As more and more data are collected and analyzed, the predictability and accuracy of the analysis and prediction improves. Coupling the newly developed all electric subsea controller unit described in this paper with advanced data analytics will lower operator costs and risks in subsea systems. the system presented herein has been designed as a simple, rugged and reliable piece of equipment based on years of experience with API RP 17H Class 2 torque equipment and variable speed subsea pumps. It utilizes serial communications with position limiting and has a closed loop speed/position control, torque control, and real-time torque limiting. The profiling feature helps establish valve and pump status, functionality and health monitoring. The tool is ideally suited for subsea application to 10,000 fsw for any application requiring up to 250 ft.-lbs. with position and variable speed control. Leveraging learnings from the nuclear industry and their regulators, this ‘spring-less’ unit includes an option for a ‘smart battery’ (Lithium ion) back-up for specified fail-safe positioning and monitoring. Technical specifications were driven by operator customers. A full set of Functional Design Specs (FDS) were developed as well as an Inspection and Test Quality Plan (ITP). Where practical, acceptance criteria were leveraged from API, ASME and other industry guidance. A full-scale prototype unit has been built, tested and qualified with over 1 million cycles. The unit enables collecting sensed operating data from one or more end devices and one or more control end points, calculating and performing analytics, and reporting health and status of the one or more end devices and one or more control end points. It is currently being utilized on a common industry subsea ball valve, integrated into a subsea chemical storage and injection system as well as a drive for a variable speed subsea chemical injection pump. Regulator authorities in the U.S. have been included in the qualification witnessing.

The Subsea Oil and Gas industry is quickly moving toward deeper waters, complex, challenging, and dynamic working environments, while requiring the highest level of safety. Tasks that have been historically undertaken by workers in shallow waters are now performed by Remotely Operated underwater Vehicles (ROV) at water depths that humans cannot survive. ROV's are being used for intervention (Work-class ROV's, WROV) and for surveillance on drilling and production systems and pipeline. ROVs inherently have several limitations including requirement of a large operating crew, a need of a dynamically positioned surface vessel, tether management, and high cost mobilization and demobilization. Autonomous Underwater Vehicles (AUV) are now emerging with new capabilities and technologies that could make them more efficient and more cost effective than ROVs. New paradigms in shape, autonomy, sensing and communication and physical capabilities are needed to make AUVs the tool of choice for deepwater industry. An ideation and roadmapping workshop on the Development of AUVs for Subsea Applications was held at Rice Uni-versity that (i) generated a consensus from Oil & Gas operators, service providers, technology developers and providers, academics and policy makers of the anticipated needs and wishes for AUV technology in10 years, (ii) identified gaps between current status and future needs, and (iii) developed a roadmap of specific technical needs, gaps and solutions, and identified how and when those gaps might be closed.

This paper addresses the innovative appraisal strategy applied to the Libra project; located in ultra-deep waters offshore Brazil. It details the key role of the Extended Well Test (EWT) Program, within the field overall Risk Mitigation Plan, as well as its interfaces with additional appraisal activities. The Value of Information (VoI) for the main acquired data is described, highlighting the associated impacts for the full field development and validation of the enhanced recovery strategy. A case study approach details how the whole EWT project maximized the acquired information, mainly from a reservoir point of view. Although the EWT approach is not new to Petrobras in the offshore environment, this is the first one with simultaneous oil production and gas reinjection. Several reasons justify the use of the industry’s first dedicated offshore EWT system with this capability. Gathering data on the main dynamic parameters of the field was critical to speed-up the development, with an acceptable risk level. The incorporation of these data in the reservoir models and the impacts in the most relevant development decisions are also described. The chosen methodology brought many opportunities, as well as challenges to interpret the data and to incorporate them in the reservoir models. Furthermore, the capability to produce without continuous gas flaring makes it possible to apply such approach anywhere else in the world.

Investments in applied research have made positive improvements in safety and environmental protection in the oil and gas industry. This paper identifies technical needs, research topics and processes for future research investments in the Gulf of Mexico based on a report titled "21 st Century Ocean Energy Safety Research Roadmap" (Roadmap). This report was completed by RPSEA for the Ocean Energy Safety Institute (OESI) in November 2018. Funding for OESI and this report came from the U.S. Department of Interior Bureau of Safety and Environmental Enforcement (BSEE). This paper provides an overview of the report findings as well as a summary of areas where the government, key stakeholders and industry can work together to continue to improve safety and environmental improvement. Investments in safety and environmentally protective research are responsibility of all parties. This report stresses that new technologies are of little value if they cannot be applied, so the process of how the research is conducted, early stage adoption, advancements and technology transfer play a key role. It is important to note that as new technologies are developed, the personnel qualifications may also change, as will associated training. The Roadmap, developed in this effort, offers a unique opportunity to guide the applications of advanced technologies. These new technology applications will continue the significant progress of current safety and environmental management systems and procedures. The recommendations were based on areas where government funding and leadership can play an important role. These recommendations came from workshops, interviews of subject matter experts, surveys, and an extensive literature search. Prior recommendations are also included from reports published by the Society of Petroleum Engineers, the Gulf Research Program, the Center for Offshore Safety, OESI and RPSEA. Investments in safety and environmental research spiked following the Macondo incident, as they have following prior safety and environmental incidences. Most of the research funding has come from fines and penalties, (from the RESTORE Act), but other substantial funding has come from industry. The offshore oil and gas industry have made significant progress in developing safety and environmental management systems and procedures. These systems and processes provide an opportunity to incorporate advances in technology for continued improvements. Working with regulators, service providers and researchers, this document addresses an important need to identify and prioritize limited research investments. The goal is for identified R&D investments to target the development of safe, environmentally sensitive, cost-effective technologies. The application of these advances will allow industry to develop resources in increasingly challenging conditions and ensure that the understanding of the risks associated with operations will keep pace with the technologies that industry has developed. Advances in knowledge will aid in the assessment and mitigation of the risk in offshore production activities related to controls, safeguards, and environmental impact mitigation procedures during drilling, completion, production operations and abandonment. This is of critical importance.

This paper discusses the requirements for a "next-generation" subsea control system and provides a description of the proposed setup/architecture. Requirements for "next-generation" subsea control focuses on requirements for "digitalization" and Industry 4.0 capabilities. Existing subsea control systems today are intended for and used to control hydraulic valves in subsea production setups. The proposed "next-generation" subsea control system is specified, designed and built for an all-electric process control setup, with requirements for extensive usage of digitalization toolboxes. Primary requirements for the "next-generation" subsea control system would be deterministic behavior and latency in the millisecond range for the control of operations part/signals/objects, while at the same time generating large amounts of high quality and highly accurate time-stamped condition monitoring data to be used in the digitalization setup. The proposed concept integrates subsea control and historian systems directly into the existing topsides control and historian systems. Implementation of an anti-surge control system will be used as an example to illustrate the concept for control of operations, and the use of artificial intelligence (AI) and historical stored data would be used as examples for topside digitalization techniques used on subsea installed equipment. Removing boundaries between topsides and subsea automation as suggested in this paper provides options to use already available toolboxes for digitalization of topsides assets on similar subsea components. The proposed open architecture control system would also easily interface directly to any cloud-based solution with standard interfaces or well-defined application program interfaces (APIs). Economic benefits of implementing an open-architecture control system would include CAPEX and OPEX reductions, while at the same time creating a "future-proof" system that allows for the addition of digitalization options. Subsea data would be delivered and stored with higher quality, providing operators with the option to look retrospectively and evaluate historian data based on knowledge to be obtained in the future. Moreover, having one integrated control system provides better protection against cyberthreats, as it eliminates the requirement for several systems, which need to be updated and maintained during the lifetime of the installation. Various predictions and thoughts about the future of subsea controls beyond the proposed "next-generation" subsea control system will also be included in this paper.

High speed wireless communication has proven elusive in subsea environments due to the inherent bandwidth limitations of acoustics and range limitations of other transmission modalities. A truly connected subsea system necessitates a high-speed, resilient architecture that can enable the integration of new sensor technologies and edge analytics and allow closed-loop monitoring and control of subsea operations for integrity monitoring and optimization. Like terrestrial Internet of Things applications, the realization of this "digital subsea" vision requires the application of high speed, point-to-point wireless technologies to complement rather than replace "hard-wired" communications such as optical fiber or acoustic systems. This work addresses the development of ULTRA (Underwater LASER Telemetry and Remote Access), an ultra-long range underwater laser communications system for use in critical points of the subsea communications architecture to increase reliability, operational flexibility, and reduce communication system maintenance associated with physical subsea connections. To demonstrate the data capacity and range of ULTRA, a subscale laboratory point-to-point wireless laser communication system was constructed with the flexibility to transmit through either air or water. The test system used power and modulation frequencies for air, fresh water, and different qualities of seawater. Optical and RF encoding methodologies were implemented to facilitate and characterize data transmission through the various media. The laboratory experiment used a subscale, filtered, and attenuated 5 mW blue-green laser in a 22-meter folded path configuration to demonstrate real-time data transmission at 312 Megabit per Second (Mbps) data rate using single channel Quadrature Phase Shift Keying (QPSK) modulation. A field prototype ULTRA system will use an unattenuated 5 mW laser that can reach approximately 280-meter range at 312 Mbps in clear conditions, which are typical of deepwater subsea. The selection of laser power and data rate are considered operational tradeoffs in environments where underwater vehicles operate. The extended range of ULTRA can enable various use cases to greatly augment subsea data communications capacity to enable the "Digital Subsea".