Bergen, Norway 11 – 13 June, 2019

Program

Change day
  • 08:30 - 09:30

    Badge pick-up and coffee

  • 09:30 - 09:40

    Welcome

    Roald Sirevaag, Chairman UTC Program Committee and Conference Moderator Simon Davies, Statoil

  • 09:40 - 10:00

    Opening speech

    Dr. Helge H Haldorsen, 2015 President, SPE International

  • 10:00 - 10:20

    Driving for value creation and industrialization

    Margareth Øvrum, Executive vice president Technology, Projects and Drilling, Statoil

  • 10:20 - 10:40

    Handling pressure through technology

    Mike Garding, CEO, OneSubsea

  • 10:40 - 11:00

    Challenging project execution

    Geneviève Mouillerat, Vice-President Projects  & Construction, Total E&P

  • 11:00 - 11:30

    Coffee break and exhibition

  • 11:30 - 12:30

    Panel discussion: Subsea under pressure – are we innovating in the right way?

    Hervé Valla, CTO, Aker Solutions
    Pål Helsing, President and EVP, Kongsberg Oil & Gas Technologies
    Sigurd Skogestad, Professor, Norwegian University of Science and Technology
    Julie Ferland, Head of Program Management, Shell TechWorks
    Per Sandberg, Vice President, Chief of Innovation, Statoil
    Moderator: Simon Davies

  • 12:30 - 14:00

    Lunch and exhibition

  • Track 1 @ Peer gynt

    Track 1 @ Peer gynt

    Field Development Concepts and Experiences

    Track 1 @ Peer gynt

    Session leaders: Tom Eddy Johansen, FMC Technologies and Torkild Reinertsen, Reinertsen

    Track 2 @ Klokkeklang

    Track 2 @ Klokkeklang

    Improved asset value and significant cost reduction

    Track 2 @ Klokkeklang

    Session leaders: Nils Arne Sølvik, OneSubsea and Michael Starkey, Exxon Mobil

    Track 3 @ Troldtog

    Track 3 @ Gjendine

    Technological innovations – Materials, Mechanical and Marine disciplines

    Track 3 @ Gjendine

    Session leaders: Terje Clausen, Subsea7 and Per Arild Nesje, Kongesberg Oil&Gas Technologies

    Track 4 @ Troldtog

    Technological Innovations - Control, Power and Instrumentation

    Track 4 @ Troldtog

    Session leaders: Tonje Dahl, ClampOn and Henrik Meland Madsen, Siemens

  • 14:00 - 14:30

    14:00 - 14:30, Track 1 @ Peer gynt

    Subsea Processing from Brazil to the Barents Sea

    Jan-Olav Hallset, Team Lead - SURF Controls & Distribution, Norske Shell

    Subsea Processing from Brazil to the Barents Sea

    Norske Shell ‘s SURF department is involved in a number of subsea processing projects around the globe, projects which will enable effective exploitation of deep water fields worldwide. These projects all rely on development and delivery of novel technology and solutions. In this presentation we would like to share and discuss our experience so far, from Norway, via Gulf of Mexico to Brazil. It should be noted that all these projects are still in the execution phase and hence operational experience is limited. Regardless, we believe that it would be valuable to share our know-how with system design, technology qualification, execution, and installation. The presentation will show that subsea pumping is the key processing technology that enables unlocking of extra resources and that this happens over a wide range of water depths and reservoir pressures. It is tempting to discuss if processing technology is becoming a standard tool for subsea developments, although the technology is still novel and introduces a new level of complexity when compared to conventional subsea production systems. Lastly the presentation will point towards the future and discuss how Shell’s know-how and subsea processing technology are relevant for the development of resources in the Barents Sea. Subsea systems will have to handle the challenges in the Arctic, firstly the sensitive environment and secondly the sheer distances to any onshore supply facility.

    14:00 - 14:30, Track 2 @ Klokkeklang

    Good oil & gas projects lost due to traditional design methodology?

    Tine Bauck Irmann-Jacobsen, Global SME WATCH Design, FMC Technologies

    Good oil & gas projects lost due to traditional design methodology?

    During the last 40 years the subsea production systems have changed from platform developments on shallow water to deeper water, long tie-ins and need for subsea process systems. The conceptual design methodology has not developed in pace with the need for advanced subsea technology.  When the disciplines traditionally involved in studying the potential of a new field do their estimates separately, they result is a set of conservative estimates. This translates to overly complex and costly solutions that are difficult to operate. This means that many interesting but challenging projects are put on hold because of uncertainty in feasibility and cost. To address this issue, a new type of conceptual design methodology has been developed.  The methodology is based on long experience of online monitoring of subsea fields (from 1995), long experience of subsea delivery projects and equipment (from 1980), multiphase technology expertise, network modelling expertise and powerful optimization algorithms.  The methodology looks at the entire life cycle of the field, from early design to the field’s operability, and provide decision makers with a more accurate and realistic picture of the fields’ potential. The methodology link the main disciplines early, make early design decisions knowledge based, hence reduce the risk of late changes and provide a smarter and leaner system solution which improve asset value and reduce cost. Case examples will be given to illustrate the new design methodology, compared with a traditional design approach. The impact on feasibility, reduction in uncertainty and operability, optimization of the subsea process system and hence reduced CAPEX and OPEX will be illustrated.

    14:00 - 14:30, Track 3 @ Troldtog

    Remote Welding System - a new way of repairing critical deep water pipelines

    Jan Olav Berge, Senior Advisor Pipeline Technology, Statoil

    Remote Welding System - a new way of repairing critical deep water pipelines

    Offshore oil and gas pipelines are important assets for maintaining stable energy supply as well as being critical for maintaining cash flow to the owners and shippers. Emergency repair response time is in focus by all major pipeline operators, and the need for remote repair technology have been addressed since the mid 1990’ies. Statoil have, on behalf of the Pipeline Repair and Subsea Intervention (PRSI) Pool in Norway, developed new technology allowing remote controlled repair by hyperbaric welding of large diameter subsea pipelines in water depths down to 1300 meters. The new Remote Welding System consist of three main modules; a habitat providing a dry gas filled work location at the tie-in location, a power and control unit launched separately providing all essential services needed for the job and the remote welding tool performing the welding operation itself. The system is built and qualified for pipelines from 30” to 42” diameter, but may be expanded to smaller diameters and deeper waters.

    14:00 - 14:30,

    Capping Stack Connectors

    John Charalambides, Director of Business Development, Oceaneering's Specialty Connector Solutions Division, Oceaneering International, Inc.

    Capping Stack Connectors

    During a loss of well control offshore, emergency intervention requires vertical access to the wellhead. Vertical access is currently available via a MODU positioned directly over the wellhead and BOP, but this access may not always be an option if other floating production facilities such as a Spar or TLP are used. To ensure emergency intervention is possible when the wellhead is damaged, debris is in the way, or vertical access is not available, a contingency means to attach the capping stack directly to the well is required. The well capping method involves using a specialized connector to attach a BOP directly on a flowing production riser approximately 100 ft. above the mudline. The connector will have a top connection consisting of an API 18 ¾” – 15 KSI flange. A BOP wellhead mandrel will be bolted to the top flange of the connector. This allows the connector, when latched to the riser, to be a contingency wellhead for the BOP. The connector is controlled and operated via an externally mounted ROV panel. Proven hydraulic pipeline repair concepts have now been applied to capping stack applications and re-engineered to accept high internal pressures, large pressure end loads, and bending and torsion loads. Once the connector has been set on the flowing riser, the only controls needed are via the ROV, which supplies the control pressure and operates the valve functions.

  • 14:30 - 15:00

    14:30 - 15:00, Track 1 @ Peer gynt

    Johan Sverdrup Subsea Concept Development

    Kristoffer Dahl, Subsea Engineer, Statoil ASA

    Johan Sverdrup Subsea Concept Development

    The Johan Sverdrup Field was discovered in 2010 and 2011 just 140 km from Stavanger in relatively shallow water depths of 110 meter. The reservoir located at 1900 meter below surface, and has very good expected production rates and a high recovery rate. The first phase involves the establishment of a field centre consisting of four platforms. Three subsea templates for water injection will be connected to the field centre. No field is identical, and even in a well-known area of the NCS there are several surprises. The current frame conditions have also changed the way Statoil develops fields, with power from shore being the prime example. For the underwater scope there are also other less published key learnings. Some challenges are well known such as the increased dynamic loads on subsea wellheads in shallow water. Other challenges were less well known, such as the soft silty soil was discovered during geotechnical surveys that has posed a challenge for foundation design. The high focus on reducing produced water disposal to sea has led to produced water re-injection. This combined with risk of well clogging and fracking of the reservoir has again led to increased complexity in water management with corresponding impact on field lay-out and control system. Future flexibility and increased oil recovery initiatives are important even with high initial recovery. The subsea water injection system therefore has possibility both for traditional IOR such as infill wells, and non-traditional IOR such as Water Alternating Gas injection.

    14:30 - 15:00, Track 2 @ Klokkeklang

    CompactSep - compact subsea gas-liquid separator for high-pressure wellstream boosting

    Olav Kristiansen, Principal Researcher Process Upstream Oil Production Systems, Statoil

    CompactSep - compact subsea gas-liquid separator for high-pressure wellstream boosting

    Subsea separation has successfully been implemented on the Troll, Tordis and Pazflor fields. One feature of subsea separation is to separate gas and liquid to optimize working conditions for subsea pumps enabling high recovery factors. The later years focus has been on qualifying more compact separation units than conventional gravity based separators. If the requirement is high pressure and high-capacity boosting, the only option is single-phase or gas-tolerant/hybrid pumps. A gas tolerant pump can typically handle 10% actual volume gas contents. A higher gas volume fraction will require degassing upstream the pump. This can be done using a conventional two-phase separator. In ultra-deep waters or at high shut-in pressures, separators with large diameters will require thick walls which can be challenging or even impossible to produce. Lifting operations of such subsea modules will be challenging and costly. Reducing the weight and size of the separator module is important both from a construction, installation and intervention perspective. CompactSep, a compact, inline gas-liquid bulk separator consists of already proven hardware components assembled in a two-stage separator system. The CompactSep system has been developed and qualified in a Joint Industry Project with Statoil as operator and Chevron, Petrobras, TOTAL and FMC as participants. Comprehensive, large-scale tests were performed with realistic fluids and at realistic conditions. The main results of the test campaign are presented. The key learnings were that CompactSep has a wide operating range and that it is possible to stabilize the process with relatively slow subsea control valves. A comparison between conventional subsea modules and CompactSep shows significant cost and weight reductions.

    Authors: Olav Kristiansen (Statoil), Gene Kouba (Chevron), Fabricio Soares da Silva (Petrobras), Jérôme Anfray (TOTAL), Mattias Gillis Winge Rudh (FMC Technologies)

    14:30 - 15:00, Track 3 @ Troldtog

    Development of a novel multiphase pump technology

    Fredrik Moen, Business Development Manager, Aker Solutions

    Development of a novel multiphase pump technology

    As the oil industry continuously moves to deeper waters and harsher environments, the need for enabling technologies is increasing. Subsea pumping in general, and multiphase pumping specifically, has for several years been a leading technology in obtaining increased recovery both from greenfield and brownfield developments. In order to take part in this expanding market, Aker Solutions has developed a range of subsea pumps for all applications. The most recent addition to the family is the multiphase pump which has been developed as part of a joint industry project (JIP) with several oil companies participating.   Key focus will be given to the new technology developed for the multiphase pump, differentiating it from products already existing in the marketplace. The pump integrates a newly developed semi-axial impeller design tailored to raw well stream pumping. The hydraulics is designed for maximum pressure generation while avoiding separation and gas locking in the pump. Organized in a back-to-back arrangement, the hydraulic configuration is self-balancing and optimized for long intervention intervals. Coupling the pump with an Aker Solutions 6MW – 6.000 RPM motor has shown promising results in testing to date. Furthermore, the pump will be equipped with a newly developed health monitoring system enabling a more proactive operational strategy. With this new insight into performance parameters, the operator is able to run the pump in optimal conditions.  Moreover, the presentation will include disclosure of the multiphase pump’s performance achievements obtained during the joint industry program currently in its final stages.

    14:30 - 15:00,

    Tracerco Discovery Subsea Pipeline CT Scanner – Integrity and Flow Assurance Case Studies of Subsea Coated Pipeline Inspections

    Lee Robins, Head of Subsea Services, Tracerco

    Tracerco Discovery Subsea Pipeline CT Scanner – Integrity and Flow Assurance Case Studies of Subsea Coated Pipeline Inspections

    Tracerco Discovery provides high-resolution wall integrity data plus detection and characterization of deposits.

    Case Study 1 – Pipeline integrity Discovery was deployed to determine the remaining wall thickness of several coated single wall jumpers and pipe-in-pipe flowlines of an unpiggable pipeline system. Wall thicknesses and other features were measured to within 1mm accuracy, confirming the integrity of the pipelines.

    Case Study 2 – Flow Assurance Discovery was deployed to determine the location and type of unknown deposits in a blocked pipe-in-pipe system. As well as sizing and locating the extent of the deposits, they were also characterised so that different deposit types were differentiated (wax, hydrate, asphaltine, scale). This enabled an efficient remediation and cleaning campaign to be planned to bring the pipeline back into production. Discovery Technology is ROV deployed and the inspection is carried out from the outside of the pipeline. It is the only non-invasive technology capable of inspecting unpiggable coated pipelines.

    Discovery benefits are:
    • Production can continue and normal operations are not affected
    • A high resolution tomographic image of wall thickness and pipe contents is provided to 1mm resolution
    • Coating does not need to be removed
    • Suitable for gas, liquid or multiphase flow
    • Suitable for inspection of rigid and flexible lines, including pipe-in-pipe pipe bundles
    • Real time communications allow instant assessment of pipeline conditions

    Flow Assurance specialists can now obtain an accurate characterisation of pipeline deposits and confirm what they are (i.e. hydrate, wax, asphaltine or scale) Integrity Engineers now have an externally deployed reliable method of accurately measuring any defects and the remaining wall thickness of any type of pipeline (coated or uncoated).

     

  • 15:00 - 15:30

    15:00 - 15:30, Track 1 @ Peer gynt

    Production Increase from Installation of Multiphase Boosting Solution

    Gavin Mann, Underwater Superintendent, Canadian Natural Resources International (UK) Ltd

    Production Increase from Installation of Multiphase Boosting Solution

    In the summer of 2014, Canadian Natural Resources International (UK) Limited (CNRI) successfully installed and commissioned a OneSubsea manufactured and supplied, Multi Phase Booster Pump (MPBP) at its Lyell subsea production facility. At a water depth of 140m, the Lyell field is located around 386km North-northeast of Aberdeen in the UK Sector of the North Sea. Hydrocarbons from Lyell are transported via subsea pipeline to CNRIs Ninian South Platform, from which water injection and facility control is provided. Control to the MPBP itself is provided by an 8km electrohydraulic umbilical running from the Ninian North Platform. The new MPBP replaced an older pump originally installed in 2005 which became unserviceable a number of years ago. Installation of the new MPBP delivers value in two forms. The first is by enabling simultaneous production from wet and dry wells; without the MPBP the wet wells can only be produced when dry wells are closed. The second is the incremental production uplift provided by the pump when all wells are on-stream. Combined together, installation of the MPBP at Lyell has meant increased production and availability, and this is a significant benefit for CNRI. In addition to the above, the presentation will cover: – The drivers behind CNRIs choice of multiphase boosting versus other options, and why subsea boosting can be such a good fit for brownfield developments such as Lyell. – The challenges faced with the integration of new pumping equipment, into a mature subsea facility. – How ongoing pump performance is monitored and optimised. The presentation shall conclude by summarising the performance of the pump since installation, and based on this real experience, the projected value add for CNRI for the years ahead.

    15:00 - 15:30, Track 2 @ Klokkeklang

    Cost Reduction Opportunities in Deepwater Riser Systems

    Hugh Howells, Principal Director, 2H Offshore Engineering Limited

    Cost Reduction Opportunities in Deepwater Riser Systems

    Riser systems can form a major component of the total cost of deepwater production systems. Whether the selected riser arrangement is a steel catenary, lazy wave or freestanding hybrid, the high costs result from a combination of stringent or complex fabrication and inspection requirements and the installation methods and vessels involved. Through some relatively minor design changes or re-configuration, manufacturing and fabrication requirements can be simplified and installation complexity and installation vessel requirements reduced, resulting in smaller overall costs. This paper describes target areas for cost reduction in deepwater riser systems and some methods by which this objective can be achieved.

    15:00 - 15:30, Track 3 @ Troldtog

    Electrically Trace Heated Enhanced Pipe-in-Pipe: Unlocking Reserves through Low Power and Thermal Efficiency

    Neil Brown, Discipline Engineering Manager, Subsea 7

    Electrically Trace Heated Enhanced Pipe-in-Pipe: Unlocking Reserves through Low Power and Thermal Efficiency

    It is estimated that eleven prospects on the NCS will require pipeline systems with enhanced thermal performance, including high performance insulation and / or active heating. This requirement is driven by ever more challenging produced fluid composition, production profiles and the need to optimise process design. The subsea industry is facing the same trend in most active hydrocarbon producing regions. Enhanced Pipe-in-Pipe (PiP) technology utilises high performance insulation material in a reduced pressure environment to provide an order of magnitude improvement in total heat transfer compared to traditional PiP systems. Electrical Trace Heating (ETH) technology is a solution to direct heating of pipelines that provides enhanced redundancy, significantly reduced power requirements, an “always-on” capability and ease of installation compared to existing Direct Electrical Heating (DEH) technology. This paper describes the application of enhanced PiP technology with an ETH system. The technology provides a step-change in the performance of highly insulated and heated pipeline systems. Such a step-change enables extended reach in cold climates as well as the potential to unlock reserves in brown field areas. ETH PiP technology is being actively developed for deployment by major operators such as Total, ConocoPhillips and Statoil. A summary of the design implications and an overview of ongoing technology qualification work will also be presented in this paper.

    15:00 - 15:30,

    Subsea Controls - Network for the future

    Odd Gilinsky, Product Line Manager, Aker Solutions

    Subsea Controls - Network for the future

    Subsea controls has evolved over the decades, starting with rather basic hydraulic control functions, then adding a growing portion of electronics and eventually data communications. The principal architecture has however not changed dramatically; after all we are an extremely conservative industry, not without reason. The pressure for new solutions is driven by increasing process complexity (the “Subsea Factory”) and a requirement to reduce cost. Two elements may accelerate this change; optical fibre and electrical actuation, already well known technologies, but the real impact on how we build subsea controls is yet to be seen. The traditional hydraulic-electrical SCM is designed for tree/well control, however for the separation, processing, and boosting subsea plant we have the opportunity to solve this with a much more modular, distributed architecture, changing the principles on how we separate traffic and address redundancy; at a lower cost. The subsea control system is there to facilitate the production process; it is a “necessary evil”, but is also the glue in an advanced subsea production system. The current standards are all targeting well/tree control, limiting the necessary evolution. We will show concepts for a controls infrastructure that will have a significant impact on how we could connect the subsea factory, using principles from the telecoms industry. Not a revolution, but give the evolution a necessary push forward.

  • 15:30 - 16:00

    Coffee break and Exhibition

  • Track 1 @ Peer gynt

    Track 1 @ Peer gynt

    Field Development Concepts and Experiences

    Track 1 @ Peer gynt

    Session leaders: Torolf Hæhre, Shell and Henrik Meland Madsen

    Track 2 @ Klokkeklang

    Track 2 @ Klokkeklang

    Improved asset value and significant cost reduction

    Track 2 @ Klokkeklang

    Session leaders: Per Christian Eriksen, Aker Solutions and Johan Kristian Mikkelsen, Perestroika

    Track 3 @ Troldtog

    Track 3 @ Gjendine

    Simplification, Standardisation and Enhanced Industry Collaboration

    Track 3 @ Gjendine

    Session leaders: Hans Kristian Sundt, GE Oil&Gas and Martin Dove, BP

    Track 4 @ Troldtog

    Technological Innovations - Control, Power and Instrumentation

    Track 4 @ Troldtog

    Session leaders: Tom Eriksen, NCE Subsea and Marie Bueie Holstad, CMR

  • 16:00 - 16:30

    16:00 - 16:30, Track 1 @ Peer gynt

    Fast Track project execution: From speed to cost

    Christina Schieldrop, Project Manager Fast Track Field Development, Statoil

    Fast Track project execution: From speed to cost

    The Fast track mandate was given by Statoil’s Corporate Executive Committee (CEC) in November 2009. Average time for realizing subsea tie-back projects on the NCS was more than 5 years and increasing. Fast track was a measure to realize marginal discoveries and provide production growth in the short term. The ambition was clear: Reduce the execution time with 50%. Similar projects were clustered in one portfolio – to create a basis for scale and repetitiveness through standardizing and industrializing. 12 fast track projects have been sanctioned, whereof 10 are already in production. The fast track portfolio have a total capex of about 60 BNOK and recoverable reserves of about 500 mmboe. On such a large basis – systematic improvements makes a difference. The fast track portfolio has reduced the time from discovery to production with up to 40%, to close to 3 years, and has delivered within the approved capital budgets. The capital efficiency and profitability is high compared to industry average, and the fast track portfolio delivers above average industry execution performance. It has moved Statoil’s and industry’s perceptions of the potential within efficient project planning, front end loading and execution to a new level. Going forward we are committed to maintain and expand the fast-track activity. We want to achieve similar results on cost as we have obtained on the time dimension. Although we have many possibilities in the pipeline, the inflow of traditional fast track candidates varies, so we have to investigate and push for expanding the established Fast-track criteria. Our ambition moving forward is to “maintain speed – reduce cost”.

    16:00 - 16:30, Track 2 @ Klokkeklang

    Lean Contracting and Technologies for Cost Optomised Subsea Development

    Hamish Button, CTO, Technip

    Lean Contracting and Technologies for Cost Optomised Subsea Development

    The paper will present strategies for lean field development and project delivery. Highlighting areas where ‘offshore industry culture’, excessive specification and functionality currently can lead to inflated costs in the construction of subsea facilities. It will also review the integration of SPS and pipeline infrastructure technologies with topsides for optimizing performance and installed cost.

    16:00 - 16:30, Track 3 @ Troldtog

    Standardization – will take the industry to the next level

    Ingvar Grøtberg, Manager Field Development, FMC Technologies

    Standardization – will take the industry to the next level

    In the mature oil  and gas provinces the majority of the opportunities consist of smaller and more marginal discoveries requiring tie-back to existing infrastructure, while the development cost has increased over time due to a number of reasons. On top of this the oil price is under pressure. The challenge is then to develop solutions that can make these discoveries profitable.  Historically solutions were copied from one project to the next. This does no longer give the expected efficiency gains, since the requirements have increased in quantity and complexity which again leads to changes that is detrimental to the effect of copy. Even small changes may lead to large engineering rework.  It seems like there is an agreement in the  industry that there are two key enablers to solve the challenge for our industry to improve the economics in the marginal discoveries. (A)  Standardization through the value chain to be able handle the complexity in requirements and consequences of changes. (B) The industry needs work together to align, simplify and reduce the amount of requirements.  The question is how we do it. Standardization needs to take place on components, products, subsystem and system level in order to take out the full potential. At the same time we need to agree on solutions that are fit for purpose, we need to simplify and challenge the requirements. In this presentation FMC will demonstrate how standardization provides efficiency gains, improvement in schedule, quality performance and ensures that lessons learned is captured.  We will present a configurable standard with flexibility to accommodate functional requirements and project specific needs.

    16:00 - 16:30,

    Unique technology for 3D integrity monitoring of subsea pipes

    Geir Instanes, Vice President, ClampOn

    Unique technology for 3D integrity monitoring of subsea pipes

    Corrosion and erosion on subsea installations is a big challenge for oil and gas operators and can carry significant cost and risk. Better monitoring of seabed installations will lower maintenance costs, provide greater control and reduce risk to installation integrity. For topside installations, there are several methods of inspection and monitoring available, but subsea, the challenge has been to find technology that works and provides real value. The growing number of aging subsea installations increases the need for good retrofit solutions. Research and development of guided-wave methods for asset monitoring and screening has been ongoing for several years and over this time ClampOn has developed a non-invasive instrument which can be used on new subsea installations or retrofitted by ROV to existing installations. While developing this guided wave based system, ClampOn’s research team has worked in parallel to develop and implement more technology in the system which will provide high-resolution 3D data for the area being monitored. Tomography is already used elsewhere, such as in medical applications, but has never before been used as part of a fixed subsea system to monitor wall thickness loss in pipelines. This paper provides background information about ClampOn’s development of its subsea corrosion-erosion monitoring system, an explanation of the measuring principles used, and explains how combining several technologies and principles allows us to accurately monitor changes in wall thickness loss in subsea installations and fulfil operators’ need for continuous condition monitoring of subsea pipes.

  • 16:30 - 17:00

    16:30 - 17:00, Track 1 @ Peer gynt

    All subsea? – The future of subsea production

    Tore Irgens Kuhnle, Principal Researcher, DNV GL

    All subsea? – The future of subsea production

    Where do we think the subsea technology is taking us with respect to pure subsea development concepts? We look into the business case of a pure subsea field development concept relative to existing floating field development concepts; determine to what degree it is an enabling versus enhancing alternative, and under what circumstances it is likely to become a preferred development concept in the future. While subsea technologies are advancing, there are still barriers to overcome related to cost and uncertain technology performance. The future of subsea technology must also be viewed in context of a business environment where the cash flow and profitability situation of the oil companies have made them more stringent on capital and risk averse. The business case of different subsea technologies is investigated both in isolation and how they impact each other as a part of a complete subsea concept to determine when moving production, power and processing subsea has positive versus negative consequences for the field economy. Main drivers and feasibility are discussed based on the positive and negative contribution from the different technologies. The conclusion is that while certain technologies are clearly enhancing or even enabling, other parts of the concept introduces new limitations. How to take advantage of the strengths of subsea technologies and multiphase flow capabilities while mitigating shortfalls related to power, complexity and availability? Field types especially suited for pure subsea developments are exemplified.

    Co-writers: Tore Myhrvold (Senior Principal Researcher), Frank Børre Pedersen (Vice President)

    16:30 - 17:00, Track 2 @ Klokkeklang

    Subsea Hand Tools - ROV Disassembly of THS

    Will Price, Engineering Lead, Oceaneering

    Subsea Hand Tools - ROV Disassembly of THS

    During the decommissioning of a deepwater well in the Gulf of Mexico the removal of the Tubing Head Spool (THS) was unsuccessful after multiple attempts using the existing disconnect options built into the THS. Taking a couple months to regroup and discuss potential solutions the operator and Oceaneering decided to partner together to disassemble the THS subsea using the ROVs and modified tooling. To ensure the success of this operation the two companies worked together to simulate the entire operation with a similar THS prior to mobilizing for the campaign. Leading up to and during the campaign it was determined a vast array of non conventional ROV tooling would be required. Some of these tools included pipe wrenches, ROV installable 1/2″ NPT fittings, hydraulic tubing overshot tools to reconnect control tubing, and large socket high torque wrenches. The intervention was successful offshore but was not as straight forward as planned. During the intervention it was visually determined that hydrates had formed inside the lock piston of the THS and was the reason for the malfunction. After four days of continuous ROV operations to remove bolts, nuts, install hydraulic fittings, and pump MEG into the connector the THS was able to be successfully removed in three pieces. This intervention prevented years of delays in decommissioning and helped eliminate significant costs and risks to develop tooling to cut the THS off.

    16:30 - 17:00, Track 3 @ Troldtog

    A new approach to a total field development assessment

    Torkild Reinertsen, Managing Director, Reinertsen Oil & Gas

    A new approach to a total field development assessment

    In order to cope with the market demand for new and cost effective subsea field development solutions, the Oil & Gas subsea industry is now at a very important and exiting crossroad. After decades of technology-driven subsea project developments, the subsea equipment has reached a level of maturity which enables the industry to swop towards cost-driven project developments. It is time to look into the toolbox and make a sanity check – do we have all we need in order to develop the next generation subsea project? With all these tools actually at hand, it is time to take advantage of the technologies and put focus on standardization, common standards & specifications, reuse, open architecture, configurable systems etc. To proceed into the future we must look at alternative and better ways to execute complete subsea projects. This implies a need to reconsider the subsea contract models and accept new and alternative ways of handling concept studies, FEEDs, system engineering, hardware supply and installation, and consequently the industry can take advantage of equipment independent system engineering players entering the subsea arena. In addition we believe that subsea development projects can be executed along the same contractual and competitive principles as in other segments of the Oil & Gas industry, e.g. topside and landbased projects. The subsea main suppliers and customers need to come to a consensus in order to change the route into the future. The presentation will put focus on main drivers and what steps to take in order to achieve field developments that are simple, robust, reliable and cost effective.

    16:30 - 17:00,

    Wireless subsea communication: the potential for utilization of general wireless broadband technologies

    Ingvar Henne, Scientist, CMR Science and Technology

    Wireless subsea communication: the potential for utilization of general wireless broadband technologies

    The development of new technologies for mobile broadband communication has produced efficient solutions for high capacity wireless communication based on the combination of adaptive modulation, OFDM (Orthogonal Frequency Division Multiplexing) and MIMO (Multiple Input Multiple Output). These technologies reduce the impact of varying transmission conditions, and should have a potential for use in wireless subsea communication in order to improve communication capacity and robustness. OFDM has proven to be robust, particularly in transmission conditions with severe inter-symbol interference caused by multipath reflections or refractions. MIMO is used for spatial diversity to improve communication channel robustness during transmission conditions that are predominant in wireless communication close to subsea installation like templates, pipelines and risers. Complex structures create a very challenging environment for acoustic communication, which OFDM and MIMO can handle efficiently with adaptation to the medium. Simulations have been carried out for the transfer function of an acoustic transmit and receive system. This simulation setup emulates a simplified model of the measurement setup, and parametric sweeps simulate time-variations for the transmission medium. A prototype system based on a software-defined radio with acoustic transducers was built, and measurements have been carried out. The transducers were placed in a rectangular tank with plane surfaces that creates distinct reflections, which resembles the propagation conditions close to or within subsea installations. The initial study shows that mobile broadband technologies have potential usage for underwater communication, and that the combination of adaptive modulation, OFDM and MIMO can improve system performance compared to fixed single-carrier solutions.

  • 17:00 - 17:30

    17:00 - 17:30, Track 1 @ Peer gynt

    Managing Sand in Subsea Separation Systems

    Ed Grave, Fractionation & Separation Advisor, ExxonMobil Upstream Research Company

    Managing Sand in Subsea Separation Systems

    ExxonMobil recently completed subsea technology qualification test programs, which included a multiphase subsea separation system for shallow-water applications using conventional, vessel-based separation technologies and another system for deep-water applications using compact separation technologies. As with any subsea processing application, reliability of the systems is extremely important, as intervention costs can be considerably high. One key reliability risk is related to managing the accumulation of sand in the subsea processing equipment. Another is the erosional limit of the process equipment due to sand production. By properly designing and validating the performance of the various sand management technologies in these two subsea separation systems, these reliability risks could be reduced. For the shallow-water system, sand handling trials were conducted to evaluate the performance and to identify potential failure mechanisms of the sand fluidization/removal internals and/or the rest of the integrated sand handling system. In addition, the oil-water separation performance of the three-phase separator was measured during the trials to determine the effect of the various sand removal operations on the oil-water separation. For the deep-water system, an inline sand removal device was tested using model fluids over a wide range of inlet conditions to determine the sand removal performance. In other qualification test programs, the effectiveness of sand fluidization/removal internals in the compact separation technologies, including the subsea slug catcher and pipe separator, was determined. This presentation will detail the design considerations with regards to sand management and disposal that impacted the final layout of these two subsea separation systems, the qualification test programs carried out on the various technologies of the integrated sand handling systems, and the results from these qualification test programs.

    17:00 - 17:30, Track 2 @ Klokkeklang

    Lifetime extension through condition based lifetime management

    Sigurd Hernaes, Senior Field Development Engineer, FMC Technologies

    Lifetime extension through condition based lifetime management

    Lately it have been performed several Lifetime Extension evaluations for the subsea fields on the NCS. Commonly the output of such evaluations will be some form of mitigating actions. A common mitigation is a reduction in the operational envelope, e.g. reduced maximum allowed pressure, production rate or intervention limitations. This can often be unwanted constraints to the system. The basis for this conclusion will often be theoretical analysis of the system and these can be quite conservative as the information that forms the basis for these is limited. As a result unnecessary constraints can be implemented to the system. This presentation will present an approach where condition and data monitoring is actively used to extend the lifetime for an existing field based on true and more realistic data for the assessment of the condition, and hence the integrity of the system. Further, aspects with regards to maintenance and integrity management will be discussed. Also positive side effects of having a Condition and Performance Monitoring system will be mentioned. The presentation will conclude that Condition and Performance Monitoring is a good tool for extending the lifetime of an existing field as it makes it possible to continuously monitor critical parameters with regards to degradation mechanisms that is potential threats to hydrocarbon containment and the operational integrity of the equipment.

    17:00 - 17:30, Track 3 @ Troldtog

    Subsea Processing JIP - Standardisation of Modules and Interface

    Kristin Nergaard Berg, Principal Engineer, DNV GL

    Subsea Processing JIP - Standardisation of Modules and Interface

    Over the last decade, CAPEX costs per well have increased considerably. Industry players are discussing the root cause and possible solutions. Tailor making and company specific requirements are mentioned as part of the picture. Subsea processing is an enabler for exploiting resources in marginal fields. However, with the current cost level, profitability can be challenging to prove. On this background, DNV is leading an industry cooperation to find standards within subsea processing – based on initiative from Statoil. To achieve cost efficient technology, industry collaboration is being established to define standards that can be used in subsea processing projects. Cooperation between operators is important to secure a coordinated and predictable approach to the supplier industry and to identify in which areas standardisation may be achievable and beneficial. Although subsea processing is seen as relatively new technology, there is experience to draw from between operating companies. Subsea pumps have been taken into use in several fields. Subsea separation is used in Total’s Pazfloor project, Petrobras’ Marlim project and Statoil’s Troll Pilot and Tordis. In 2015, the first systems for subsea compression will start boosting the gas production at the Åsgard and Gullfaks fields. All of these represent significant efforts that can be re-used through operator collaboration, in terms of e.g. working methods, engineering and technology qualification. Being a young technology, there is a window of opportunity to set directions for standardisation before practices have become too integrated to turn around. Standardisation is a buzzword today and it is expected from our industry that we make efforts to achieve this. In this presentation, DNV GL will explain the approach and ambition for the JIP and give a status update of the work.

    17:00 - 17:30,

    Subsea Laser profiling and Sequential imaging

    Michael Flynn, CTO, Cathx Ocean

    Subsea Laser profiling and Sequential imaging

    The integrity and operation of subsea assets requires regular survey and inspection using highly accurate survey tools and processes. Subsea Survey today uses a combination of video imaging and acoustic data which is limited in resolution. This makes some features such as anodes and cracks difficult to identify. Traditional video data and even HD, on a moving subsea vehicle, is captured over long exposure times and so details are heavily blurred even where the video stream is adequate for piloting. A combination of Laser profiling and co-registered still images provides sharp high resolution images and accurate 3D point cloud enabling detailed asset inspection. The industry is now entering a phase where five knot vehicles are being successfully trialled. These bring new challenges to all forms of optical data capture. The limiting factor for increased speed and range is exposure times, which is determined by high camera sensitivity and optical power. Laser images are best shot in darkness and stills cameras require intense burst of light therefore a key requirement is the ability to sequence the various imaging scenarios. Recent laser profiling trials over subsea assets in the North Sea have had very positive results. In varying turbidity conditions the 3D laser data with co-registered still images enabled clear identification of features on a pipeline. The simplicity and accuracy of these data collection methods makes identification of features and faults much simpler. Matched with modern data storage and retrieval tools automation of the inspection process is the natural progression.