Agenda

SPT 2026 Congress
Leonardo Royal Hotel
London Tower Bridge

DAY 1: TUESDAY 15 SEPTEMBER 2026

08:00
Registration and coffee

09:00
Welcome to SPT 2026
Steve Woolley, Director, SW Conferences Ltd

09:05
Welcome from the session chair

SESSION 1: GLOBAL ENERGY OUTLOOK AND OFFSHORE PIPELINE MARKET UPDATE

09:10
Offshore energy market outlook and implications for the offshore pipeline sector

  • Status of offshore E&P: current activity, investment trends, and project sanctioning across key basins

  • Offshore EPC market outlook: forecast demand for engineering, procurement, and construction services as operators advance new field developments

  • Pipeline opportunities: emerging prospects for flexible and rigid pipeline supply, installation, and lifeextension work

  • Geographic hotspots where offshore pipeline activity is accelerating

  • Medium to longterm outlook for offshore pipeline demand

09:35
Keynote address: a contractor’s perspective on the global offshore pipeline market

  • How today’s market dynamics are reshaping the contractor landscape

  • Operating in a transitioning environment and meeting rising technical and commercial demands

  • New methods and technologies driving cost efficiency and lowercarbon operations

  • What the next decade looks like for offshore pipeline contractorse

10:00
Keynote Address: Ormen Lange Pipelines - enabling subsea compression

  • Ormen Lange field overview

  • SURF scope delivered: new field layout consisting of one new production pipeline, 17 new SDSS production spools and two 120 km umbilical/power cables

  • Main challenges and learnings: engineering, fabrication, construction, and installation

  • Handover to operations

Vinicius Serta Fraga, Pipeline Engineer, Norske Shell

10:25
Networking break

SESSION 2: HYDROGEN AND CO₂

11:00
Revised and new pipeline codes
Sigbjørn Røneid, Senior Principal Specialist, DNV AS

11:30
A case study - cost optimised CO₂ pipeline repurposing: engineering strategies towards significant CAPEX reduction
Ir. Tengku Shahru, Pipeline Specialist, Pipewave

12:00
Designing pipelines for hydrogen transport
Kaspian Puukka Jensen, Pipeline Engineer, Ramboll Danmark

  • Repurposing an existing pipeline seems a straightforward exercise, but it is not. The main reason Operators tend to re-purpose is to reduce the project CAPEX as much as possible, especially for the Carbon Capture, Storage (CCS) project, which commercially did not bring dollars and cents to the company unlike crude or gas. 

    Despite the fact, the operator company oblige and committed to fulfil their responsibility and accountability to helps fight climate change by installing a new CO₂ pipeline for transporting carbon dioxide but the challenges are it shall be done with very minimal CAPEX. 

    This is where comes to the idea of re-purposing old existing pipeline, instead of installing new pipeline. A full flash technical assessment shall be conducted to access the current integrity and condition of the pipeline in relation to remaining thickness due to corrosion, pipeline dents and so on.  It is also important to assess the old existing linepipe material specification to know the carbon equivalent, pipe toughness, etc. In order to re-purpose, CO₂ product composition shall be fully known as well as its phase envelope. It is important to know and understand the behaviour of CO₂ when subjected to different pressures and temperatures throughout total pipeline length and its design life for the next 10 – 20 years. 

    Battelle Two-Curve Method (BTCM) is the primary, industry-standard and semi-empirical method used to assess and prevent failure mode of Running Ductile Failure (RDF) which likely to happen for the re-purposed pipeline due to its aging condition. But the bottom line is, the comprehensive study is essential to determine the most optimum pipeline design and operating data of CO₂ pipeline for the repurposing. 

    At the end of the day, operators only spent CAPEX costs to the bare minimum but were still fulfilling their obligation in carbon capture to help climate change. It is worth to highlight that minimum cost saving at least 30% is likely to be achieved by performing this pipeline re-purposing compared to installing a new one.

    This paper will further elaborate on the methodology and best practices in getting existing pipeline being re-purposed with the bare minimum CAPEX spending.

  • This paper outlines changes foreseen in the next revision of DNV-ST-F101 Submarine pipeline systems and DNV-RP-F104 Carbon dioxide pipeline systems, both codes which are subject to review and external hearing in 2026. In addition, the paper highlights key contents in the first revision of DNV-RP-F123 Hydrogen pipeline systems, published in March 2026. The history of DNV-ST-F101 goes back to 1976 when the Rules for Submarine Pipeline Systems was issued by DNV. 2026 marks the 50th anniversary of DNV codes for submarine pipeline systems. Over the years DNV-ST-F101 has achieved global recognition and currently more than 75% of all new pipelines globally are designed to it. The developments throughout the years have been performed in close cooperation with the industry. Over the years, DNV-ST-F101 has been supplemented by a large number of recommended practices, addressing specific pipeline design scenarios. The first revision of the current DNV-RP-F104 for carbon dioxide pipelines was issued in 2010 as DNV-RP-J202, addressing carbon dioxide specifics for pipeline systems. Since 2010 the code has been revised several times, incorporating the knowledge gained from e.g. joint industry projects. Over the last 3 years CO2Safepipe joint industry project has been running, and the next revision will include the findings and recommendations developed by this project. H2pipe joint industry project started in 2020, and the second phase of the joint industry project resulted in the first revision of DNV-RP-F123 Hydrogen pipeline systems.  

    This paper will give insight in the recent developments of DNV-ST-F101 and DNV-RP-F104, and the contents of DNV-RP-F123. The paper will also outline the split between scopes across the codes. 

Afternoon Session Chair

12:30
Networking lunch

SESSION 3: LATERAL BUCKLING

13:30
Critical buckling force at sleepers
Author: Carlos Sicilia, TotalEnergies and Ismael Ripoll, Independent (London)

14:00
Subsea intervention for residual curvature sections to promote lateral buckling in ultra deepwater offshore Brazil
Nikolaos Chatzimanolis, Senior Functional Manager (Global Projects Centre Engineering Design & Analysis), Subsea7
Authors: Anders Madsen, Haicheng Rong, Min Xie, Arek Bedrosian, Nikolaos Chatzimanolis, Subsea7, Sutton, United Kingdom Rafael F. Solano & Thiago L. A. Santos, Petrobras, Rio de Janeiro, Brazil 

  • Sleepers are probably the most commonly used buckle initiator system for pipelines requiring a controlled lateral buckling design. When assessing the reliability of these buckle triggers, it is common to use the formulation currently presented in DNV-RP-F110 and originally developed as part of the Safebuck JIP. This consists of an equation based on the prop shape and a probabilistic correction factor with a certain distribution, calibrated from the survey data from 40 sleepers on one project.

    When using this formulation and input distribution, it is often difficult to demonstrate the reliability of sleepers as buckle initiator. This then forces the designer to use buckle initiators with lower critical buckling forces, such as sleepers with pushing or pulling mechanisms or ZRBs to impose a lateral OOS imperfection in addition to the vertical one imposed by the sleeper; both of which are significantly more expensive than simple sleepers.

    Yet in projects where simple sleepers have been used, these are generally reliable and trigger the planned buckles as intended. Indeed, in some back analyses performed for pipelines currently in operation where sleepers had been used as buckle triggers, the predictions suggest a low probability of buckling at the sleepers, whereas buckles had in fact formed at all sleepers. These results suggest that the formulations currently used to assess the formation of buckles over sleepers could overestimate the actual critical buckling force and therefore be unsuitable.

    This paper will present the comparison of the reliability predicted for some sleepers against the actual response in operation to illustrate the disagreements described above.

    The paper will then present the development of a new formulation based on first principles for the critical buckling force at sleepers. It will then show the effect of the new formulation on the predicted reliability in pipelines already in operation and compare it to the observed responses.

    This could allow to simplify the buckle triggers used and therefore reduce project costs.

14:30
Rigid flowline walking in ultra-deepwater systems with complex architecture and seabed topography
Adel Jebali, Operational Manager, TechnipFMC
Authors: Adel Jebali, Cedric Madaschi, Mennad Ait Salaht, (TechnipFMC), Lars Hermanrud and Hroar Andreas Nes, Equinor

  • Controlled lateral buckling using the residual curvature (RC) method has been implemented on rigid flowlines in ultra-deep waters offshore Brazil. During installation some RCs may land outside the acceptable design limits, e.g. excessive embedment or undesirable as-landed orientation (ALO) angles of the RCs, which could restrict the lateral buckling efficacy of the RCs. After analysis of all pertinent as-laid parameters, these RCs may have to be rectified prior to commencement of operation of the flowlines. 

    This paper presents two subsea intervention methods (buoy and pull; and lift and shift) which have both been recently used successfully offshore Brazil. Vertical buoyancy modules were used in the first method to lift the RC above the seabed and then pulling the RC crown laterally to a certain displacement, determined by predictive non-linear finite element (FE)analyses during the design phase and also considering the as-laid configuration of the RC. In the second method a single cable from a vessel was used to perform the lift and shift operation. Both methods aim at moving the RCs away from the high embedment zone and increase the horizontal out-of-straightness (HOOS), but without creating any soil berms ahead of the pulled pipe. Following the modelling of the rectification, the predicted flowline vertical and lateral profiles were compared with the actual post-intervention residual shape of the RC obtained by in-situ surveys. Then, by importing the surveyed rectified configuration of the entire flowline length into the FE models, it was shown that the adopted contingency measure is effective, and that a lateral buckle would be developed satisfactorily at the rectified RC under operational conditions meeting all integrity acceptable criteria.

  • Axial walking of rigid flowlines in ultra-deepwater environments presents a significant engineering challenge, especially for flowlines deployed over highly uneven seabed and within operationally complex systems. The rigid system under study, deployed at water depths exceeding 2800 m, includes multiple loops, bidirectional flow capabilities, and alternating dead oil circulation (DOC) and hot oil circulation (HOC) phases, which occur respectively as part of frequent shutdown and restart operational cycles. These cycles generate a non-linear, time-dependent axial load profile that drives challenging walking behaviour. This response is further influenced by a seabed marked by steep slopes and several natural spans, where the rigid flowline exhibits a highly coupled thermo-mechanical interaction between global buckling and walking. A particularly influential factor is the presence of a high seabed slope, which causes a consistent tendency to walk in a downslope direction. Despite the alternating thermal and pressure loads associated with HOC and DOC phases, transient gradients tend to reinforce axial movement downslope, particularly in configurations where the hot end of the flowline is consistently located at the crest of the seabed slope. This gravitational influence can override local buckling, leading to cumulative displacement that grows with each operational cycle. The high number of shutdown and restart events further accelerates axial walking progression, posing long-term integrity risks. Global buckling phenomenon interacts with axial walking, altering restraint conditions and stiffness distributions in ways that traditional design models often fail to capture. The coupling between buckling and walking becomes especially critical in systems where thermal cycling and operational reversals are frequent. Recent developments in numerical modelling have enabled more accurate representation of flowline–soil interaction under complex loading and support conditions. In this study, advanced three-dimensional finite element techniques are employed to capture the evolving contact mechanics between the flowline and seabed, including sliding, uplift, localized loss of support, and multi-directional constraint effects. 

    By examining the interaction between flowline architecture, operational regimes, and seabed conditions, this study contributes to a deeper understanding of flowline walking in ultra-deepwater scenarios and proposes design strategies to enhance long-term system stability and integrity. 

15:00
Networking break

SESSION 4: PIPELINE DESIGN

15:30
Challenges in understanding and remediating a 4” piggyback pipeline buckle
Kiran Kayyar, Senior Pipeline Engineer, Peritus International 
Author: Christopher Burnett, Director of Engineering, Peritus International

  • Peritus was recently involved in a project where a 4” piggyback pipeline buckled over an existing 26” pipeline following a trawl gear interaction. This paper presents a detailed investigation of the incident, using state-of-the-art survey technology, and replication of the buckle formation process and 3D characterization of the deformation using Finite Element analysis techniques. The study demonstrates the methodology used to quantify the damage, evaluate the system’s operational integrity, and implement effective remedial measures. The findings provide insight into piggyback pipeline behaviour under mechanical stress and offer practical guidance for future risk mitigation and remediation strategies for similar issues.

16:00
Advancing the fatigue assessment of subsea pipelines
Sean Murray, Subsea and Wellheads Team Leader, Lloyd’s Register
Authors: Sean Murray (Lloyd’s Register), Ralf Peek (Peek Solutions), Ian Macrae (Crondall Energy), Luke Munro (Lloyd’s Register)

  • As subsea developments extend into deeper waters, more complex seabed terrains, and harsher operating environments, fatigue performance has become an increasingly critical aspect of pipeline design. Accurate fatigue prediction depends on the reliable prediction of cyclic stress ranges at girth welds, where fabrication tolerances, weld geometry, and local stiffness discontinuities due to thick coating cutbacks generate additional bending and elevate hotspot stresses. Industry practice typically relies on stress concentration factors (SCFs) to relate nominal stresses from global analysis to local hotspot stresses. While existing standards provide widely adopted formulations, several underlying assumptions and simplifications mean that traditional approaches may be either overly conservative or insufficiently conservative depending on the specific application and loading conditions.

    This paper explores and highlights potential improvements in three key areas that significantly influence fatigue life predictions for subsea pipelines:

    1. Updated SCF formulation for weld root misalignment, providing a more accurate and physically representative prediction of root SCF behaviour.

    2. Strain/stress concentration at concrete weight coating field joints, including assessment at elevated strain levels and the system level effect of multiple joints along a pipeline.

    3. Treatment of corrosion allowance in fatigue analysis, comparing traditional approaches and evaluating alternative methods to account for wall thickness reduction over the operating life.

    Application to real pipeline configurations demonstrates the impact of enhanced treatment of stiffness discontinuities, corrosion allowance, and weld root SCFs. The paper concludes with practical recommendations for integrating these improved methods into design workflows to achieve realistic, yet still suitably conservative, fatigue predictions.

16:30
Streamlining subsea pipeline fatigue analysis without compromising damage accuracy
Dragos Cisu, Installation Analysis Engineer, McDermott
Authors: Dragos Cisu, Installation Analysis Engineer (McDermott, Vladimir Sentosa, Senior Principal Installation Analysis Engineer (McDermott) and Ling W Chin, Principal Installation Analysis Engineer (McDermott)

  • Time-domain fatigue analysis of subsea pipelines under wave loading is commonly performed using multiple random wave seeds and long simulation durations to ensure statistical reliability. While conservative, this approach can result in substantial computational effort, particularly during design iterations and parametric studies. This paper investigates practical opportunities to streamline fatigue simulations without compromising the accuracy of predicted fatigue damage, with direct application to time-critical offshore installation operations.

    The work is demonstrated through a representative J-Lay installation case study using the Amazon lay vessel, where large numbers of fatigue simulations are typically required during installation engineering assessments. A series of sensitivity studies were carried out to evaluate the influence of peak stress, stress range distribution, random wave seed selection, and simulation duration on calculated fatigue damage. Results show that fatigue damage is governed primarily by stress ranges and cycle distributions rather than isolated peak stress events. Load cases producing the highest absolute stress are not necessarily fatigue critical. In addition, variation in predicted damage between different wave seeds was found to be limited when the stress-range spectrum is adequately captured.

    The effect of simulation length was also examined by comparing conventional three-hour simulations with shorter one-hour realizations. For the studied subsea pipeline configurations and environmental conditions, one-hour simulations provided fatigue damage estimates consistent with longer simulations within typical engineering scatter.

    Based on these findings, a simplified fatigue assessment approach is proposed using a single representative wave seed and reduced simulation duration. The methodology significantly reduces computational time while maintaining accuracy suitable for engineering design and screening-level fatigue assessments of subsea pipelines. The proposed approach can support more efficient offshore installation engineering workflows, where rapid analysis and decision-making are often required.

17:00
Chairman’s closing remarks

SESSION 5: ROUNDTABLE SESSION

17:10
This session will provide an informal environment for delegates and speakers to come together to discuss and debate those issues currently influencing their business. Each table will be moderated by a leading expert and delegates choose which table to join:

Table 1: Composite solutions for controlled subsea pipeline lateral displacement in deepwater environments
Moderator: Carl-Petter Halvorsen, SVP Business Development, CSUB

Table 2: AI in the world of offshore pipelines
Moderator: Carlos Charnaux, GPC Engineering Functional Director, Subsea7

Table 3: Pipeline security and sabotage threats: what should we do in the current climate?
Moderator:

Table 4: Hydrogen & CO₂ pipelines
Moderator:

  • This paper addresses the design of hydrogen (H2) transmission pipelines, with emphasis on early-phase assumptions that allow fatigue and fracture safety to be assessed without introducing unnecessary conservatism. H2 pipelines are a key element for future hydrogen value chains, but their design raises challenges that differ from conventional hydrocarbon service, in particular fatigue performance, pressure cycling and material resistance to crack initiation and propagation.

    Detailed assessments using standards such as DNVRPF123, DNVSTF101, ASME B31.12 can address installation mechanics and structural integrity. However, earlystage and preFEED studies must work with limited data and assumptions. Therefore, practical engineering guidance is needed to enable robust concept selection and preliminary sizing of pipeline diameter, wall thickness and material properties, without relying on detailed strainbased or materialdegradation analyses that can only be completed closer to construction or extend the FEED phase.

    The pipeline considered is an early-stage, conceptual design for a >300 km, 42-inch offshore pipeline intended for continuous transport of gaseous hydrogen between production, storage and consumption nodes. At this stage the objective is to define feasible ranges for wall thickness, material grade and operating philosophy that are technically robust while remaining compatible with economic and constructability constraints.

    The work included a bottom-roughness (BR) analysis, and a preliminary fatigue and fracture-mechanics analysis (FFMA) for assessment of longitudinal-seam and girth weld regions. A central challenge is the fatigue design combined with functional stresses related to out of straightness curvature caused by support conditions and geometric imperfections at the pipe–seabed interface. Local irregularities and resulting stress concentrations can govern fatigue life, particularly when combined with frequent operational pressure variations typical of hydrogen systems.

    The BR analysis is executed as a 3D Finite element model with the pipeline analysis tool SIMLA following in-line with recommended practices as per DNV and client requirements. The FFMA is performed with in house tool based on BS 7910 methods and supported by best practices from other pipeline standards. The analyses highlight clear dependencies between required wall thickness (range ~30 mm), assumed fracture toughness and the magnitude of operational pressure changes, and show that pressure cycling combined with residual out of straightness stresses (notably displacement controlled longitudinal strains) can be a dominant design driver.

    On the matter for steel material grade, input from linepipe vendors indicates that established steel grades such as X65 are broadly suitable for gaseous hydrogen service, provided that adequate fracture toughness and material quality requirements are specified.

    Based on these findings, the paper proposes a set of recommendations for early-phase H2 pipeline design, aiming to support timely decision-making while avoiding overly conservative assumptions that may otherwise compromise feasibility. It is further recommended with early routing-optimization and, where appropriate, include seabed intervention, to reduce displacement induced stresses and mitigate fracture risk.

18:15
Close of Day 1 followed by Networking Drinks Reception

19:30
SPT Gala Dinner

DAY 2: WEDNESDAY 16 SEPTEMBER 2026

08:30
Registration and coffee

09:00
Welcome from the morning session chair

SESSION 6: INSPECTION

09:10
Computed tomography applied to subsea pipeline inspection: technical capabilities, field deployment, and integrity & flow assurance applications
Donald Ballantyne, Commercial Manager – Subsea Services, Tracerco

  • This paper presents the technical development, qualification, and field application of a computed tomography (CT)-based external inspection tool — Tracerco Discovery — designed for deployment on subsea pipelines and associated riser systems. As a first-to-market transfer of CT technology to the subsea environment, the instrument addresses a critical gap in non-invasive, external pipeline inspection capability.
    Mounted externally on the pipe, the tool requires no coating removal, no interruption to production, and no pig launch or retrieval operations. It is deployable by remotely operated vehicle (ROV) to water depths of up to 3,000 metres. The instrument has undergone third-party and IOC qualification for accuracy, resolution, and sensitivity, and is capable of scanning through thick coatings to characterise the pipe wall beneath.
    A key technical differentiator is the tool's ability to capture both pipeline integrity measurements and flow assurance data within a single scan pass on complex pipeline arrangements (PiP,Piggyback). On the integrity side, the system provides accurate quantification of corrosion and metal loss, including growth rate monitoring to support fitness-for-service assessments and life extension programmes. Concurrently, the tool detects and quantifies internal deposition — including paraffin wax, scale, and bore restrictions — enabling operators to assess flow assurance risk without the need for additional interventions. Deposition measurements have been correlated against flow assurance models to verify accuracy and support predictive modelling.
    The paper presents three field case studies drawn from deepwater operations in West Africa, the Gulf of Mexico, and Brazil. The first describes the application of the tool in support of a remote intervention repair programme following a confirmed loss of containment attributed to a corrosion anomaly. The second examines its use in a pipeline life extension context, where corrosion growth rate data informed remaining service life estimates. The third case study addresses a flow assurance challenge involving paraffin wax accumulation, where CT-derived deposition measurements were integrated with client flow models to validate the severity and extent of the blockage. The paper also discusses the application of the technology in advance of pigging and in-line inspection (ILI) operations to identify bore restrictions or deposition that could present a risk of a stuck or lost pig.
    The results demonstrate that external CT inspection can provide a technically robust and operationally efficient complement to conventional ILI, particularly for assets in late life, those in deepwater environments where ILI is logistically challenging, or where intermediate inspection intervals are required between scheduled pig runs.

09:40
Full matrix scan phased array UT - advanced robotic inspection for offshore steel catenary risers (SCR)
Markus Ginten, Group Business Line Manager, ROSEN Group
Authors: Markus Ginten, M.Eng., MBA, Benjamin Koster M.Sc., Ruediger Bauernschmitt, PhD Physics and Nico Gruhler, PhD Physics, ROSEN Group

  • As pipeline systems worldwide continue to age, the management of fatigue-related degradation has become an increasingly important integrity challenge for operators. Fatigue cracking is particularly prevalent in high-stress regions such as girth welds, heat-affected zones, bends, free spans, and fixed points. In addition, mechanical damage mechanisms, including dents, gouges, and other surface irregularities, can introduce local stress concentrations that serve as initiation sites for cracking, accelerating integrity risks over the remaining service life of the asset.

    These challenges are especially pronounced in Steel Catenary Risers (SCRs), where continuous exposure to wave, current, and vessel-induced motion results in significant cyclic loading. The highest fatigue stresses typically occur at critical locations such as the touchdown zone and stress joints. Although SCRs are designed using advanced fatigue assessments and safety factors, their dynamic operating environment makes periodic, high-resolution inspection a key element of effective integrity management.

    This paper presents results from an ongoing research and development program focused on an advanced ultrasonic phased array inspection system designed for internal deployment using robotic platforms. The system enables full matrix capture of ultrasonic data from within the pipeline, with particular suitability for complex and traditionally hard-to-inspect assets such as SCRs. A dedicated sensor carrier incorporating an optimized number of strategically positioned phased array probes has been developed to provide efficient coverage of both pipe body and weld regions. Importantly, the sensors operate in a non-contact configuration, with acoustic coupling achieved through a controlled liquid standoff. This approach facilitates inspection across varying surface geometries and reduces sensitivity to external surface condition.

    To fully exploit the captured data, an adaptive Total Focusing Method (TFM) has been implemented. During inspection, the internal pipe surface and back-wall geometries are continuously characterized and incorporated into the image reconstruction process. Multiple sound propagation paths are evaluated, including longitudinal and shear waves, mode conversions, and back-wall reflections. The resulting datasets from different sensor positions and wave modes are combined into a concise set of high-fidelity images representing the pipe wall and weld structure.

    Inspection results obtained from representative, natural-like defects across a range of weld configurations are presented, demonstrating reliable defect detection, classification, and sizing capabilities. The paper concludes by outlining potential operational applications of this measurement technology when integrated with robotic inspection systems, highlighting its value for integrity managers seeking enhanced fatigue crack identification and risk-informed decision-making for critical pipeline assets.

10:00
From passive to active: advancing magnetometry for subsea pipeline integrity assessment 
Ken Yap, Vice President, Technology & Business Development – North America, Electromagnetic Pipeline Testing (EMPIT)
Authors: Keng Yap, Mark Glinka, Jakob Stumme, Electromagnetic Pipeline Testing (EMPIT)

  • Subsea pipelines pose significant inspection challenges due to limited accessibility, harsh environments, and the prevalence of unpiggable and submerged assets. Magnetometry-based inspection has emerged as a transformative, non-intrusive solution, enabling pipeline condition assessment without in-line access. This paper presents advancement in subsea magnetometry technologies, including a passive Large Standoff Magnetometry (LSM) system utilizing an ROV-deployed sensor array, and an active Current Magnetometry Inspection (CMI) system implemented on a hybrid AUV platform.

    Passive magnetometry leverages naturally occurring magnetic flux leakage fields to assess corrosion. Over a decade of research and development has explored its advantages in non-contact surveying, but also demonstrated its inherent limitations in detection sensitivity. Experimental studies evaluating metal loss detection under varying pressure and temperature conditions reinforced these findings. The insights have enabled the deployment of passive magnetometry on ROV to inspect subsea production flowlines for internal corrosion. Active magnetometry addresses many of the limitations of passive approach through controlled electromagnetic excitation but introduces additional constraints. This has driven the integration of CMI with a hybrid AUV platform to enable inspection of subsea pipelines for external corrosion. Fundamentally, the physics-based constraints of each approach directly define their respective subsea applications.

    Active CMI applies multi-frequency alternating current to a subsea pipeline via cathodic protection connections and measures the resulting magnetic field above the pipeline using an array of tri-axial fluxgate magnetometers. The technique enables detection of coating damage and external corrosion defects, while frequency-dependent flux leakage analysis allows differentiation between active and passivated corrosion. CMI has been validated through onshore field trials and blind tests, demonstrating its effectiveness in supporting external corrosion direct assessment (ECDA), and stress-corrosion cracking direct assessment (SCCDA) programs. Ongoing developments in subsea deployment and AI-driven analytics continue to expand the role of magnetometry in subsea pipeline integrity assessment.

10:40
Networking break

SESSION 7: PROJECT DELIVERY

11:10
Berling: A high temperature exposed PIP on a very uneven seabed subject to trawl loads
Anoop Nair, Principal Discipline Engineer, TechnipFMC
Authors: Anoop Gopinathan (TechnipFMC), Liyaqat Ali (TechnipFMC), John Canney (TechnipFMC), Chris Cooper (TechnipFMC) and Atle Rangnes (OMV)

  • The Berling pipeline is a 24 km high-temperature 10"/16" pipe-in-pipe system, installed in approximately 300 to 370 m water depth in the Norwegian sector of the North Sea. The pipeline is designed to remain exposed on the seabed, making it highly susceptible to global buckling and pipeline walking. 

    The project faced significant challenges due to a very uneven seabed with widespread boulders and coral formations. Soft clays along part of the route posed additional complexity. The seabed’s natural irregularities introduced frequent and deep free spans, some with a gap exceeding 10m and extending up to 100m in length. These spans, many of which were interacting, were considered as part of the buckling mitigation strategy. This meant allowing the pipeline to expand into free spans, thereby reducing compressive axial forces which reduced the severity of lateral buckling and removed the requirement for engineered buckle initiators. In summary, the complex design challenges included.

    • Navigating difficult seabed bathymetry and obstructions, such as large boulders and sensitive coral habitats

    • A robust reliable strategy to manage the pipeline axial movement and feed into the lateral buckles

    • Designing the span intervention, which considered the uncertainty in the axial feed-in to relieve lateral buckling and the need to keep the span gap sufficiently small to ensure trawl interaction loads remained at acceptable levels

    • Efficiently placement of rock for span correction and trawl protection, while minimizing environmental impact to the numerous coral formations

    This paper presents the integrated approach to address these challenges. It highlights the solution adopted to manage the complex seabed conditions, environmental constraints, and pipeline integrity risks.

11:40
Irpa project - deepwater S-lay pipe-in-pipe: technical challenges, qualification testing and innovative manufacturing solution
Nicolas Bishop, Lead Engineer, ITP Interpipe

  • The Irpa development represents a significant step change in deepwater subsea pipeline engineering, with a 79km Pipe-in-Pipe (PiP) system installed at water depths of up to 1,350m. This project marked a significant technical challenge, involving the design and delivery of the largest (in terms of PiP and sleeve diameters and thicknesses) and longest subsea PiP system ever developed by ITP Interpipe. 

    This paper presents a comprehensive overview of the Irpa PiP system, focusing on the key technical challenges encountered during design, qualification and manufacturing. The project required scaling up PiP and sliding sleeve technology to unprecedented dimensions, while ensuring compliance with stringent requirements related to thermal performance, structural integrity and installation constraints. 

    To meet client specifications, an extensive qualification programme was implemented. A full scale thermal test was performed to demonstrate that the required insulation performance of the PiP system was achieved under representative conditions. In parallel, a series of qualification tests were conducted on the resin injected beneath the sleeves, including Procedure Qualification Tests and a dedicated sliding test. These tests were critical to validate the mechanical integrity of the sleeve-resin assembly and to demonstrate its resistance to potential significant loads during installation, preventing the sleeve from sliding in the S-lay vessel tensioners or when contacting rollers, which is a critical risk during installation. 

    A major highlight of the project is the introduction of an innovative manufacturing solution developed by ITP Interpipe: a water-cooling system applied during sleeve fabrication. This technology enabled swage welding operations to be carried out at controlled temperatures, significantly improving production efficiency and enabling continuous welding without thermal hold points, removing a key bottleneck in sleeve manufacturing. This was essential given the project scale, with more than 2,000 sleeves manufactured. 

    By sharing lessons learned, qualification strategies and technological advancements, this paper provides valuable insights into the execution of large-scale deepwater PiP projects and demonstrates how innovation and testing can be combined to successfully de-risk critical subsea developments.

12:10
Multistructure deployment in ultradeep offshore Brazil: technical challenges and strategic lessons from Bacalhau
Marina Skadins, Pipeline Group Discipline Lead Rio and Deepesh Kumar, Vessel Interface Manager, Subsea7
Authors: Marina Skadins (Subsea7), Deepesh Kumar (Subsea7), Joao Gouveia (Subsea7), Luca Ercoli-Malacari (Equinor), Camila Cézar (Equinor)

  • The Bacalhau deepwater development offshore Brazil involves the installation of twelve rigid flowlines and eleven risers in a highly congested subsea field. The deployment of dual In-Line Tee (ILT) structures in this environment posed significant engineering and operational challenges, driven by harsh metocean conditions, extended installation windows, and the mechanical constraints of ultra-deepwater pipeline systems.

    To address environmental uncertainties and to enable continuous operation in case of deteriorating weather conditions, a robust installation strategy was developed. This approach involved laying down ILTs on the seabed for temporary abandonment, followed by recovery using support vessels, pipe retrieval, and welding of the second structure.

    This paper focuses on the key engineering and operational challenges encountered during the dual structure installation, such as fatigue at anchor flanges and under the HOC, operational complexity and spatial constraints and highlights the innovative solutions implemented to maintain structural integrity and installation efficiency.

    The successful execution of the Bacalhau campaign demonstrates the feasibility and reliability of dual ILT installations in ultra-deepwater settings, offering valuable insights for future developments in similarly demanding offshore environments

12:40
Networking lunch

Afternoon session chair

SESSION 8: REMEDIATION AND INSPECTION

13:40
GMC connected riser: water injection riser – turnkey replacement scope, West Africa (2022)
Martin MacPhee, Technical Sales Manager, GMC Limited

  • GMC have specialized in turnkey replacements of drain and sea-water caissons for over 10 years in the UKCS. In fabricating pipe or joint sections with the GMC Mechanical Connector, rapid installation time, increased structural strength and pressure sealing capability is offered. The technology was enhanced and then deployed on a platform in West Africa for a critical water-injection (WI) riser replacement project to stimulate an existing reservoir for the operator. The GMC connector is a linear make-up, pin and box mechanical connector, with dual gas tight, all metal seals. It consists of rings concentric teeth – forming the structural strength of the connector – which engage together to form a maintenance free connection. It is typically made-up in one minute, using proprietary GMC tooling. The connector had been previously deployed in a smaller size (6” OD) in this field as a jumper spool, capable of transporting hydrocarbons. The connector was also designed with an innovative gasket seal-ring, adding further all metal seal barriers to enhance joint integrity. Following contract award, GMC completed the engineering and fabrication of the riser in only twelve working weeks. GMC mobilised a multi-skilled team to install temporary aids, recover the existing riser, and install the new riser. The riser was recovered in three days, with the new riser installed safely in a further three days, at an inclination of 10 degrees. Installation from the topside meant an enhanced install time, minimal platform modifications and a fully ‘cold-work’ installation. 

14:10
Overcoming waxing risks: state of art of mechanical cleaning proven journey to 100% ILI data reaching operational excellence in subsea multiphase pipelines
Robert Reinhart, CEO, RPC-Tec and Wilson Santamaria, Senior Product Manager, RPC-Tec

14:40
Ultrasonic in-line inspection of deepwater assets: state-of-the-art update
Colum Holtam, Director – Subsea, Quest Integrity (Baker Hughes)

  • Wax deposition in subsea multiphase crude oil pipelines remains a major threat to flow assurance, structural integrity assessment, and reliable inline inspection (ILI). Hardened paraffin layers degrade sensor performance, damage inspection tools, and undermine data quality. Conventional cleaning with cup and descaling pigs mostly compacts wax into the pipe wall, requiring many runs yet still failing to achieve the bare metal cleanliness needed for highquality inspection data.

    A leading Mediterranean oil producer faced severe waxing in two systems (12"–17 km offshore and 12"–12 km offshoreonshore pipeline). The operator conducted a reference ILI campaign that recovered only 50% of the data and caused irreparable sensor damage after 56 passes of standard pigs over 25 days. The objective of obtaining reliable ILI data was not achieved exposing the need for a proven alternative of cleaning.

    RPC-Tec responded by deploying its Mechanical Cleaning Technology using tailored Hydro Mechanical Cleaning Tools. The portfolio combined BASIC-TOOL to mobilize soft deposits, SCRAPING TOOL to remove hard wax from the pipe wall, TIGER TOOL for detailed cleaning of corrosion pits, and ROTATING TOOL to fragment extremely hard deposits.

    RPC-Tec’s HMCT solution assisted on ILI data collection quality from 78% in the first campaign (with no sensor damage), to 99% in the second, and 100% in the third, enabling accurate tracking of corrosion evolution and demonstrating the robustness of the cleaning strategy. Cleaning durations were effectively halved versus the reference campaign, with cleaning runs reduced by a factor of three and stable, predictable flow conditions restored. For operators, reduces operational and safety risk, lowers costs from downtime and reruns, and delivers the cleanliness required for highquality ILI, while supporting bestinclass maintenance and extended pipeline service life in demanding subsea environments.

  • This paper aims to provide an update on the state-of-the-art for ultrasonic (UT) in-line inspection (ILI) of deepwater assets and dispel some lingering o shore ILI myths and misconceptions. Regular ILIs are key to effective integrity management of deepwater risers and pipelines. Minimally invasive and easy to deploy tools, combined with efficient inspection planning, allow operators to mitigate risks and maximize production. 

    Ten years ago, Quest Integrity (now a part of Baker Hughes) was approached by a major o shore operator to challenge convention and develop a high pressure, small diameter UT ILI tool to inspect deepwater risers and flowlines, without sacrificing the form factor and navigational capabilities of our existing fleet of ILI tools. Since that original 4-inch subsea ILI tool development, the high-pressure fleet has grown in both physical size and operational breadth. Driven by evolving industry needs and support from numerous deepwater operators along the way, ILI solutions now exist for subsea systems that just a few years ago would have been automatically deemed “unpiggable”. Today, this includes cloud-based analysis and assessment capabilities, giving operators unprecedented access to their inspection results to support risk-based inspection planning and integrity management, from pre-commissioning to life extension and everything in between. 

    A series of deepwater project case studies will be used to demonstrate how ILI technology and capabilities have evolved with the industry, including multi-diameter pipeline inspections, bi directional inspections by design or necessity, riser-only inspections for life extension, smart cleaning verification methods, subsea launch-receive solutions for single line tiebacks, and flexible pipe inspections. Details will also be shared on the status of the next frontier of UT ILI development, adding reliable girth weld crack detection capabilities to the existing fleet of small diameter deepwater tools. 

15:10
Networking break

SESSION 9: NEW DEVELOPMENTS IN PIPELINE DESIGN

15:30
Comparative study of the effect of modal damping on free spanning unbonded flexible pipelines & risers
Linlin Jiao, Principal Engineer, DNV
Authors: Linlin Jiao, Principal Engineer - Shuai Yuan, Senior Engineer - Mário Caruso, Principal Engineer (DNV)

16:00
Effect of axial force on pipeline burst resistance, an update
Chris Cooper, Technical Authority – Rigid Pipelines, TechnipFMC
Authors: P. Krawczyk & C. Cooper, TechnipFMC

  • Flexible pipelines and risers are slender subsea structures designed to transport fluids such as oil, gas, water, and chemicals. The flexible pipelines typically rest on the seabed, while risers are suspended in water connecting subsea systems to surface facilities. Free spans in flexible pipelines often arise due to seabed unevenness, scouring, or installation configurations, making them vulnerable to static and dynamic environmental loads due to Vortex Induced Vibration (VIV) and direct wave action. VIV might pose a significant fatigue risk to these structures, which needs mitigation strategies to maintain structural integrity. The unbounded flexible pipeline normally consists of helix components or unbounded components arranged in a helical geometry which behave with a non-linear structural response. During VIV excitation, the stick/slip behaviour among interior components generate an energy dissipation through friction between different components’ movement which generates an amplitude dependent structural damping and tends to reduce the VIV response. This is the so-called modal damping. Comparing to the flexible pipeline on the seabed, risers normally have high slenderness ratios and low natural frequencies. They are prone to VIV across multiple modes (often more than 10), with significant curvature along their length. Higher modes are associated with increased modal damping, making this effect particularly relevant for risers. In flexible pipelines, modal damping is less explored, possibly due to fewer excited modes and shorter span lengths. This study presents a comparative analysis of modal damping effects on flexible pipelines and risers, supported by numerical simulations and case studies. The findings highlight the structural and dynamic distinctions between these systems when accounting for the effect of modal damping.  

  • Subsea pipelines are often subject to significant compressive axial forces when in operation. Until recently, the impact of these compressive forces on the pipeline burst resistance was assumed to be negligible. However, this assumption has been shown to be misleading. Work published by the authors in 2023 suggested that axial force can reduce the burst resistance by up to 20% in some practical situations, such as high-temperature buried pipelines. This previous study, which consisted of a finite element analysis of a length of 'nominal' pipe feeding into the 'weak link' burst joint was considered conservative. This was mainly due to the material strength mismatch between the nominal pipe feeding into the weak link and the weak link itself. Countering this conservatism was uncertainty on the definition of the weak link burst joint geometry. 

    Industry guidance on this topic remains limited. DNV-ST-F101 states that the effect of axial force on burst should be considered but does not explain how. This paper provides an update on this topic based on additional studies undertaken by TechnipFMC. A small refinement to the weak joint definition is proposed, which is based on some detailed wall thickness measurements of seamless pipe joints. Additionally, a more representative material strength mismatch between the nominal pipe and the weak link burst joint is adopted in the finite element analysis. Findings on corrosion resistant alloys (CRA) material pipelines and carbon steel pipelines with corrosion are presented. Results show that these refinements have a positive impact on the conclusions, significantly reducing the reduction in burst resistance. This may help explain why there have been no reported failures to date caused by the axial compressive force reducing the pipeline burst resistance. 

16:30
Pressure containment and compressive force: recent developments from Preshot JIP 

Authors: Carlos Sicilia Gaillard (TotalEnergies), Nicholas Vaughan (DNV), Sigbjørn Røneid (DNV)

  • Pipes that are subject to compressive axial force may exhibit reduced burst capacity. This is because compressive stress in one axis lowers the effective tensile stress in the orthogonal direction required to cause yield. In practice, for a given level of tensile hoop stress the combined stress state is closer to the yield surface if the axial stress is compressive. End-cap forces generate tensile axial stresses, but compression can arise if the pipeline is exposed to elevated temperature and subject to axial restraint.

    For a simple case with uniform geometry and material properties, calculating the burst capacity for both load-controlled and displacement-controlled axial compression is straight forward. However in a real pipeline, stochastic variation in the material and geometry along the pipeline, even in spite of nominally uniform design, means that the ‘system effect’ ensures the pipeline bursts at the location with lowest capacity. The loading at this particular location cannot be simply derived from the functional loads, instead it is also a function of the properties of the rest of the pipe. So even if the properties of the weakest location are known, the capacity cannot be calculated from this input alone.

    In this paper we account for a restrained pipe exposed to temperature elevation with a statistically described pipeline and examine the burst process. Axial yielding in some locations of the pipe which do not burst affect the loading and therefore ultimate burst capacity for the pipeline. A framework for addressing the problem is presented.

17:00
Chairman’s concluding remarks and close of conference