norwep subsea tieback technology conference

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Australia Subsea Tieback Technology Conference

15 November 2017 | Perth, Australia

Agenda Abstracts

Incooperationwith:

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Agenda

Chair Tore Moe, Energy Advisor - Australia, NORWEP

10:00 Registration & Coffee/Tea

OPENING

10:45 Welcome & introduction Tore Moe, Oil & Gas Advisor – Australia, NORWEP

10:55 Opening H. E. Unni Kløvstad, Ambassador, Norwegian Embassy

11:10 Key Note – “Long Subsea Tie-Back – Opportunities and Challenges” an Operators prospective. Hosi Sabavala, Technology Development Manager - Upstream, Woodside Energy Mark Wagstaff, ETC Subsea Team Lead, Chevron Australia

11:30 Cost-effective approaches to managing hydrate blockage risk rather than hydrate avoidance Eric May, Chevron Chair in Gas Process Engineering, University of Western Australia

SUBSEA POWER

11:50 Subsea Power – An Enabler for Subsea processing, compression and boosting Asmund Maland, VP Business and Project Development, ABB

12:10 Unmanned Power Buoy solution for electrification of subsea processing facilities Jan Wigaard, Principal Engineer, Structural and Naval Architecture, Aibel

12:30 High voltage power cables as an enabler for long subsea tie-backs Martin Amundsen, Tender Engineer, Nexans

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12:50 Lunch and Exhibition

SUBSEA FIELD DEVELOPMENT SOLUTIONS

14:00 Water dew-pointing with subsea gas dehydration to improve pipeline and flow assurance economics Si Huai Yeaw, Senior Process Engineer / Project Engineer, Aker Solutions

14:20 Implementation of new instrumentation and monitoring in existing subsea field infrastructure Olav Brakstad, Sales Manager, ClampOn

14:40 Long Tie Back for Stranded Asset Development James Martin, Chief Engineer – Front End Technical Sales, TechnipFMC

15:00 Novel Method for Replacement of Pliant Wave Production Risers from Floating Unit Whilst Continuing Production – Simopro Joel Ireland, Regional Engineering Manager, Ocean Installer

15:20 Afternoon Refreshments and Exhibition

16:00 Towed Construction: a Cost Effective Solution for Australian Subsea Tie-Backs Stephan Eyssautier, Field Development and Technology Manager for AsiaPacific, Subsea7

16:20 Subsea Repair – “Emergency equipment versus Emergency brains Adrian Gamman, Business Acquisition Manager – Subsea, IK Subsea

16:40 Subsea Tie backs – Maximize return on investment, minimizing CAPEX Per Billington, CEO, BPT

17:00 Design and material selection, qualification, and installation of subsea tie-ins and HPHT pipelines Jens Petter Tronskar, SVP & CTO, DNV GL Oil & Gas Technology Centre Singapore

17:20 Closing remarks

17:30 Reception hosted by The Royal Norwegian Ambassador

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NorwegianEnergyPartners

Attendees

Tore Moe, Energy Advisor – Australia

[email protected] / +61 422 132 304

http://norwep.com

Norwegian Energy Partners is a non-commercial foundation with a Board of Directors as its highest body. It is jointly financed by the Norwegian industry and the Norwegian government. The vision of Norwegian Energy Partners': Strengthening the long-term foundation for wealth-creation and employment in Norwegian energy industries through focused international efforts, building on the collective competitiveness of the partner companies. See: http://www.norwep.com

ABSTRACTS

ABB 4

Aibel 5

AkerSolutions 6

BPT 7

ClampOn 8

DNVGL 9

IKSubsea 10

Nexans 11

OceanInstaller 12

Subsea7 13

TechnipFMC 14

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ABBSpeaker

Asmund Maeland, Vice President, Business and Project Development

[email protected] / + 47 90 03 63 00

Asmund have previously worked for Sintef Energy Research and Statnett, and has held different positions within ABB as Senior Research Manager, Project Manager and in Sales Management. For 10 years, he worked in global ABB roles as Center of Excellence Manager Electrification, BU Product Group Manager and BU Global Electrification Manager within the global Business Unit Oil, Gas and Chemical.

In addition to his current role, he is also heading the ABB - Aker Solution alliance as ABB representative.

Presentation Title

Achieving safer and more cost effective wells by integrating workflows

Abstract

For reservoirs with long step-out distance, ABB’s new subsea AC solution is an enabler for powering equipment with high power need as pumps, compressors and DEH systems. The power can be supplied up to 200 kilometers from shore with just one cable using standard 50/60 Hz solutions with onshore compensation equipment. Using low frequency AC solutions can increase the step out distance to around 600 kilometers, with power up to 100 MW, powering pumps, compressors, pipe-heating, and powering a complete subsea factory on the seabed. With the reliable power supply, the factories on the seabed will achieve stable production, extending the lifetime of the field.

Key Learning Outcome

An understanding of the state of the art within subsea power distributions, which type of projects can be realized going forward.

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AibelSpeaker

Jan Wigaard, Principal Engineer, Structural and Naval Architecture

[email protected] - +47 92 08 57 15

Jan has 25 years experience in Structural and Marine design and analyses of fixed and floating offshore structures. His experience includes both concept and detail design including 6 years within floating wind, substations and WTG foundations.

Jan was the concept designer and concept responsible for DolWin Beta HV DC station.

Presentation Title

Unmanned Power Spar solution for electrification of subsea processing facilities

Abstract

A topside and a Spar substructure for an unmanned platform to power and control a subsea compression system, have been developed. The design is based on a similar Aibel design and design experience from the wind power industry and similar platform experience in the oil and gas industry. The platform is designed for unmanned operation from shore. The way of access is by a walk to work supply vessel.

• The main components of the topside are the electrical system and the H/V-AC system, split in an A and a B routing for redundancy.

• The topside layout is designed for safe operation and efficient material handling, to be cost and weight efficient.

• The HVAC cooling system is based on closed loop cooling and fin-fan coolers to avoid sea water cooling.

• The control system is based on remote control from shore with a high degree of condition monitoring.

The Spar substructure outer shape is designed for optimum hydrodynamic performance and limited motions and inclination for the topside equipment. The design has accounted for Spar specific issues, e.g. to avoid mathieu instability. The motions are within allowable limits for the electrical equipment.

The Spar structural and marine design, including the ballast system, is highly efficient for the fabrication process, hence cost efficient, and is based on experience from the offshore wind industry.

A cost efficient mooring system is also designed.


It is indeed feasible to design a small unmanned cost efficient floater with minimum motions to support smaller topsides with electrical equipment.

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AkerSolutionsSpeaker

Si Huai Yeaw, Senior Process Engineer / Project Engineer


Si Huai Yeaw is a Senior Process Engineer working for Aker Solutions since 2011. He has more than 8 years professional experience in the oil and gas industry. Currently based in Perth, Si focuses on the subsea processing and boosting technology applications (which include separation, dehydration, cooler, compressor and pump) in the Asia Pacific Region. Prior to this, he has worked 2 years in Norway with the company, on various topsides and subsea field developments in the North Sea and Australasia region. Si currently sits on the committee board for SUT Perth, and is also a member of SPE.

Presentation Title

Water dew-pointing with subsea gas dehydration to improve pipeline and flow assurance economics

Abstract

For subsea tieback development specifically long distance applications, the pipeline and flow assurance related expenses constitute as a major component of both CAPEX and OPEX figures for the development. This presentation aims to share the subsea dehydration technology development status, as well as how it could be applied to improve the overall field economics by mitigating certain pipeline and flow assurance challenges such as top of line corrosion and MEG requirement, by doing water dew-pointing subsea. Highlights on the key features of these novel technologies will be provided, with specific focus on the benefits the technology brings to the market


• Subsea Dehydration – drivers and benefit • Update on the technology development direction of the subsea dehydration technology

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BPTSpeaker

Per Billington, President and CEO

[email protected] / 47 90 12 42 84

Per has led the company since it was founded in 1998. Under his leadership, he has decisively positioned BPT as a leading company in the field of specialist process consultancy and digital integration of working tools, used in the Oil & Gas industry. By focusing on flow assurance and process integrated projects with his team, BPT has a solid track record of delivering success by fostering greater partnership collaboration and innovation attuned to client needs. Prior to founding BPT Per held various process and management roles in major companies. Per holds an MSc from the University of Trondheim, Norway.

Presentation Title

Reduce subsea tie back uncertainties and costs while maximizing the throughput within receiving facilities safety integrity limits

Abstract

A tie-back solution needs to address the capacities of the receiving facility, configuration of the inlet arrangement and limitations of existing safety systems. A flare system for a new field is often over-designed. The API521 standard 6th edition January 2014, section 4.3.3 is addressing this issue.

The API standard allows the use of transient process simulation to define relief loads, providing the basis for secondary safety barriers and finally the flare capacity evaluations. BPT has developed software to integrating and improve tools globally in use for pipeline and receiving facilities.

Since 2007, BPT in cooperation with Statoil (Norway) has developed methods to ensure all elements of an asset are accurately represented all the way from the inflow from the wells production tubing to the exit of the flare tip. To achieve a “one-to-one” representation of an asset using the existing first principle tools, BPT has developed software running on the backbone of globally leading software solutions, linking multiphase simulators to transient process simulators and added functionality not present in the main stream prediction tools. The API520 requirement to use rated PRD curves (vendor curves) is now available, ensuring a method that complies fully with the API standard.

With the BPT FSG “Flare Scenario Generator” – automatically capturing of data from the individual relieving sources throughout the scenarios and subsequently used in accepted flare design tools, such as the Aspen System Flare Analyzer, maximizes the use of existing flare systems within the plant integrity limits.

The methods and tools assist increasing the collaboration between flow assurance, process and process safety disciplines and reduces the time to execute and document all safety aspects of a tie-back.


Learn how improved digitalization allows for better verification and utilization of the receiving facility for subsea tie-back projects. A radical change to the engineer’s ability to visualize the design parameters reduces the process work by more than 60%.

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ClampOnSpeaker

Olav Brakstad, Sales Manager

[email protected] / +47 95 02 09 33

Olav has a background in electronics and instrumentation with education and work experience from long and short wave radio systems, ships’ radars, navigation and sonar systems, before joining ClampOn in 1999.

During his 18 years with ClampOn, he has gained firsthand experience and extensive knowledge in ultrasonic measuring systems. Olav has covered the Australian market since 2004 and been ClampOn’s Sales Manager for the Eastern Hemisphere since 2008.

Presentation Title

Implementation of new instrumentation and monitoring in existing subsea field infrastructure.

Abstract

When a field is developed via a subsea tieback, it is often hooked up to an aging subsea infrastructure with limited or technologically out-dated instrumentation and monitoring sensors. The specifications of the original field development often hinder implementation of new technology and functionalities, either by blueprinting the original specs, or due to the original field having limited possibilities for hooking up new technology to the existing infrastructure.

This paper will present examples of challenges, and how they can be resolved. Practical examples will be included.


• Early involvement and «ownership» of data opens up possibility for improvement on monitoring and instrumentation.

• Technical challenges/changes are almost always solvable when addressed sufficiently early in a tieback project.

• Not addressing challenges at early stage may lead to less optimal (and costly) retrofit solutions.

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DNVGLSpeaker

Dr Jens P. Tronskar, Senior Vice President & Chief Technology Officer DNV GL Pte. Ltd. Oil & Gas Technology Centre Singapore


Jens P. Tronskar M.Sc., Ph.D., C.Eng., IWE, SenMWeldI, FSWS received his M.Sc. degree in Materials’ Physics / Physical Metallurgy from the Technical University of Norway (NTH) in 1980 and was conferred the degree of Doctor of Philosophy (Ph.D.) by the National University (NUS) of Singapore, in 2002. Dr. Tronskar has 35 years of experience of materials technology, materials selection and welding, failure investigations, pipeline installation ECAs/ fracture mechanics analyses of structural and piping/process components and pipelines for the offshore and onshore oil & gas and LNG industry. He has experience from projects in the North Sea, Australia, SEA, China, ME and Brazil.

Presentation Title

Design and material selection, qualification, and installation of subsea tie-ins and HPHT pipelines

Abstract

Subsea technology has moved from subsea wells, manifolds, flowlines, and templates, to include subsea boosting, separation, and now recently compression. The industry is seeking standardization of subsea installations, but specific standards for subsea processing lack today. DNV GL and the Joint Industry group of sponsors in the Subsea Processing JIP are developing a guideline and recommended practice for subsea pumping.

Harmonized technical requirements may give efficiency benefits such as those evidenced by implementing DNVGL-RP-0034 for subsea forgings or by DNVGL-RP-O101 ‘Required Technical Documentation for Subsea Projects’. CRAs subsea may soon be replaced to some extent by Thermoplastic Composite Pipes (TCP) manufactured to DNVGL-RP-F119 requirements, due to numerous advantages it hosts over traditional carbon steel or clad steel pipelines; such as chemical resistance to degradation by corrosion and bacteria, HTHP capabilities, 5-10% the weight of rigid carbon steel pipe of equivalent pressure rating reducing top tensions and transportation / installation costs.

Sulphate reducing bacteria (SRB) can grow in reservoirs with subsea water injection of sulphate-rich water causing souring of the reservoir, thus requiring material selection for sour service for the wells and HTHP lines.

This paper presents cases and achieved benefits for subsea projects from North Sea and APAC in design, qualification, and installation based on DNV GL’s codes and recommended practises.


Subsea tie-in field developments have proven to be cost-efficient solutions in shallow to mid-water with subsea technology development now enabling similar deepwater projects.

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IKSubseaSpeaker

Adrian Gamman, Business Acquisition Manager – Subsea


Adrian Gamman is Business Acquisition manager and Project Manager for the Subsea Department in IK Norway. IK Subsea is mainly working within the IMR area with a long track record doing subsea maintenance and repairs. Gamman began in IK Norway in 2015, and has over 5 years’ experience from the oil and gas industry working for Nemo Engineering and Kongsberg Oil and Gas Technologies as both project engineer and project manager.

Presentation Title

Subsea Repair – “Emergency equipment versus Emergency brains”

Abstract

IK-Norway AS (IK) has over 3 decades designed and delivered emergency repair solutions for damaged subsea pipelines, flow lines, risers, structures and equipment. The repair solutions have varied based on the actual requirements regarding interfaces, pipeline specification water depth, available space and access, etc. The IK repair philosophy is to employ proven concept and compliance with the relevant standards, rather than keep equipment and tools on the shelves for these projects.

When IK performs emergency repair operations the first priority is establishing the core project team with experienced and competent personnel. The second activity is to mobilize the pre- nominated and best-fit sub-suppliers for the actual repair tasks. The project is then performed with a “seamless” and close relation from client to the sub-suppliers with a transparent and open project execution. This service is named; “Competency Based Emergency Repair” – “CBER”.

IK have delivered complete and relatively complicated repair solution within a few days that normally would require several weeks’ delivery time by applying the above CBER concept. In this paper we will present the major activities / bricks of this project execution concept and compare it with the benefits and limitations of establishing an emergency equipment base. In addition, a couple of repair operations will be presented as case studies. The above topic is very comprehensive and this paper will focus on the repair of leaking flow lines and pipelines.


Manufacturing and storage of emergency equipment versus keeping an emergency organization with skilled engineers and operators ready for potential repair operations.

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NexansSpeaker

Martin Amundsen, Tender Engineer - Subsea Energy Systems


Martin has a M.Sc. degree in electric power engineering from the Norwegian University of Science and Technology. His recent professional experience includes power system engineering and electrical system simulation and design for FEED and studies within the subsea electrical power domain, including subsea boosting. Relevant project experience includes the Åsgard Subsea Compression project where he was working with follow-up of qualification of novel subsea equipment, power system analysis and multidisciplinary testing of assembled boosting systems. Today he is working within technical tendering of subsea power cables for various industries and markets.

Presentation Title

High voltage power cables for remote tie-backs and deepwater applications

Abstract

Nexans Norway is a global supplier of submarine cable systems, including control umbilicals, power umbilicals, power cables, direct electric heating (DEH) and ROV cables for the offshore oil and gas industry. Recent projects for the Australian market include the Greater Enfield power umbilical to OneSubsea and Woodside.

This presentation will focus on technical challenges related to electrical power transfer in long step-out subsea tie-backs at high voltages. Altering the insulation thickness may give preferable cable characteristics (i.e. decreased cable capacitance), which may enable longer step-outs with high voltage AC transmission.

Recent R&D activities performed by Nexans Norway show that dynamic power cables are feasible also for high voltage applications without the fatigue challenges associated with a conventional lead water barrier. A lead sheath is normally used to prohibit water ingress in XLPE cable insulation systems for static high voltage applications. Alternative water barriers suitable for dynamic application at large water depth may enable project developments with reduced topside facilities by supplying high voltage electrical power from shore.

DEH as an alternative flow assurance technology will also be presented in brief, which is gaining an impressive track record and increased focus from all major operators.


Better understanding of power cable considerations for long tie-backs and insights into ongoing developments.

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OceanInstallerSpeaker

Joel Ireland, Regional Engineering Manager (Asia Pacific and Oceania)


Joel Ireland established the engineering department at Ocean Installer's and has an extensive background in SURF installation work scopes. He was recently responsible for the replacement of risers in many of Statoil's fields and successfully completed the first "Simultaneous Marine Operations and Production" replacements for Statoil on the Visund field. He is now establishing the engineering department at Ocean Installer's Perth office.

Presentation Title

Novel method for replacement of pliant wave production risers from floating unit whilst continuing production - Simopro

Abstract

A novel method for replacement of pliant wave production risers was implemented for the Visund field in the North Sea to enable production to remain in place during the marine operations of riser replacement. Due to the relatively high probabilistic and high consequential risk of DP incidents occurring during marine construction operations in the vicinity of "hot" risers, a 200m exclusion zone has been implemented at all of Statoil's offshore oil and gas platforms with exposed risers in the North Sea. Additionally, other marine/environmental restrictions have been implemented whilst production was ongoing in order to ensure safety of the offshore facilities. Ocean Installer with the vessel Normand Vision performed riser replacement whilst remaining outside the 200m exclusion zone through use of bespoke equipment, additional safety considerations with respect to potential DP incident risk mitigation, novel initiation methods and highly complex subsea activities. This created an enormous economical upside for Statoil. This presentation will present the challenges, outline the methods and equipment and highlight the many economical, operational and safety benefits with performing this operation.


Improving safety and identification of methods used to overcome vessel positioning constraints on live/producing fields

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Subsea7Speaker

Stephan Eyssautier, Field Development and Technology Manager for AsiaPacific


Stephan has an extensive background in SURF installation and design scopes. After a few years as Project Engineering Manager with Subsea7, Stephan has recently established the Field Development Group of Subsea7 in Perth, whose mission is to provide Early Engineering Studies to help marginal fields to reached FID and maximise added value for clients before execution ITT. Stephan has more than 17years of experience acquired within Saipem, Technip and Acergy. Stephan graduated with a Master of Science from Ecole Centrale de Nantes and holds a Master in Economics and Management from IFP-School.

Presentation Title

Towed Construction: a Cost Effective Solution for Australian Subsea Tie-Backs

Abstract

The initial developments of large gas projects in Australia have required bringing costly rigid pipelay barges from overseas. Will it be sustainable to bring them back for phase 2 in the current market? Can’t we find a step change in how we develop those new tie-back projects? “Towed construction” could be one way to achieve this.

Towed Construction consists of fabricating onshore long stalks of pipes that can be bundled together with umbilical lines within a carrier pipe, terminated at each end by a structure called a “towhead”, which can hosts the same functions as a standard manifold. The cross-section design can provide the best thermal performance. Once successfully assembled and tested, the bundle is launched across the beach and towed away by tugs to its offshore location. The Controlled Depth Tow Method (CDTM) provides a low stress installation. It’s a simple and reliable solution that provides Cost savings and Risk reduction compared to Conventional Pipelay.

This presentation proposes to detail Towed Construction’s main benefits & challenges and to briefly highlight how Towed Bundles can be implemented from concept selection towards operations in Australia, thanks to 40years of experience acquired in the North Sea


1. Better understand what Towed Construction consists of and what are its differences with Conventional Pipelay

2. Recognise which prospects Towed Construction will provide the most added value compared to Conventional Pipelay

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TechnipFMCSpeaker

James Martin, Chief Engineer – Front End Technical Sales


James graduated with honors in Mechanical Engineering at The University of Huddersfield, England, joined Dril-Quip Inc’s graduate program in 1997.He was the engineering manager for the Woodside Greater Western Flank Phase 1 development. He is currently in the Perth Front-End Engineering team for TechnipFMC.

Presentation Title

Long Tie Back for Stranded Asset Development

Abstract

The objective of this presentation is to propose a system that can process gas from a remote field in Western Offshore Australia to enable a dry gas production stream can be transported back to a production facility or tie in point up.

Long tie-backs allow remote fields to be produced to existing infrastructure. Therefore, small remote discoveries can potentially be produced in an economically viable manner, where a dedicated topsides facility would eliminate the financial incentive to develop the field.

A low cost, unmanned, facility can provide essential produced water processing, MEG regeneration, power generation, controls and communications with the subsea equipment. A facility on site will negate the requirement for long umbilics and an all-electric subsea system will further reduce controls distribution costs.


An overview of a possible combination of technologies to enable the development of stranded assets

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