PAST ABSTRACTS

Ben Wilby, Manager – Offshore and Onshore Equipment, Westwood Global Energy

• Status of offshore E&P

• Offshore EPC market outlook

• Flexibles and rigid pipeline opportunities

• Regional opportunities

• Future forecasts

Pieter Swart, on behalf of Gasunie

In 2022 the Dutch cabinet increased its targets for offshore wind energy in the North Sea to 21.5 GW to be realized in 2031. In 2024 the Dutch government indicated which wind areas will be realized before 2032. These are wind farms with a distance of up to 150km from the coast, whose energy will come ashore in electrical form (Direct Current/Alternating Current. With the further growth of offshore wind energy after 2030, the Dutch government intends that, besides electricity, hydrogen will also be produced from the offshore wind energy in the North Sea. With limited land-fall points, higher renewable energy capacity than demand, grid congestion, and a need for green gas carriers like hydrogen, large-scale offshore hydrogen production and transportation is expected. Integration of renewable power generation and conversion capacity and hydrogen transmission (e.g. lower pressure) involves very large investments and hence a well-designed infrastructure for hydrogen. Gasunie have conducted a feasibility study an Integrated Offshore Hydrogen Production System in the North Sea.  The lecture will present Technical and Spatial aspects of the concept which fit within the future build-out of offshore hydrogen network up to 2050.

Grethe Malene Sagerup, Project Director - CO₂ Highway Europe, Equinor

• Equinor CCS strategy

• CO2HE value chain perspective including storage portfolio

• Project status and what we have achieved so far

• Challenges and opportunities going forward

• External context – and what it will take

Authors: Lars Amdal (DNV), Leif Collberg (DNV) and Erik Levold (Equinor) 

Determination of the required wall thickness of a pipeline is a simple task and can be made by pencil and paper in minutes. The challenging part is the follow-up design, what mitigations are required to meet all the other limit states for that determined thickness? First the design scenarios must be identified. What are the events to be designed for, what loads will these impose on the pipeline, what will be the response in the pipeline (the load effect) and are these within the capacity of the pipeline? Typically loads from the events may be taken from standards or recommended practices, the loads are then applied in a FE-model and the resulting response is checked versus design criteria in standards. These days engineers try to be smarter, but do we run the risk of fooling ourselves? This presentation will focus on for which scenarios may intervention work be reduced by more advanced FE-analyses, is the uncertainty in the applied loads similar to the resulting response uncertainty, can the capacity be determined by FE? The answer is, as often, ”it depends”. Many pitfalls will be illustrated!

Authors: Arek Bedrossian, Nikolaos Chatzimanolis – Subsea7, Sutton, UK

There are many pipeline loading situations where, according to DNV guidelines, the nature of loading must be classified as either ‘load controlled’ or ‘displacement controlled’, before assessing integrity. In cases where it is not clearly defined in the DNV code as to which condition prevails, load controlled is always advocated, as it ensures conservatism. However, this entails additional cost. The approach described in this paper helps eliminate the need to make assumptions regarding the nature of loading by applying the limit load method. The method, which is widely used in structural and pressure vessel design work, involves proportionally increasing all loads acting on the pipeline in a non-linear FE model and observing the resulting trajectory of the response. If the stable trajectory veers more towards strain limits, then it is concluded that the loading is ‘displacement controlled’. In the example of the escarpment crossing given in this paper, the limit load approach revealed the opposing contributions of local and remote effects on the trajectory. Local effects tend to exaggerate local bending of pipe over sharp protrusions, whereas longer range effects alleviate it. This balance between the two effects is captured effectively by the limit load, sometimes also called ‘design by analysis’, method. The results indicated that with minimal local intervention strain-based criteria can be used for the design of the escarpment crossing. The limit load approach reduced the need for costly bulk remediation measures. The method could potentially also find beneficial applications in other pipeline design and installation loading situations.

Author: Kok Siong SOON, Subsea Pipeline Engineer - Engineering Australia, McDermott

Co-author: Mr. Gravina, Senior Manager - Engineering, McDermott International (London)

This paper presents a comprehensive analysis of a mid to deep-water subsea project involving 8-inch and 10-inch pipelines using the J-lay approach. One of the main challenges is navigating the highly dense, pockmarked seabed with limited routing options. A Zigzag Routing using ZRB mitigation strategy is employed to ensure the pipelines avoid pockmark excursion zones while achieving high reliability of planned buckles and reducing the probability of rogue buckles, in accordance with codes, standards, and customer/project requirements. Corrosion-Resistant Alloy (CRA) Hot Rolled Bonded pipes are used to mitigate buckling risks, while mechanically lined pipes (MLP) with different wall thicknesses are chosen for non-buckling zone, offering a cost-effective solution without compromising safety for sour service pipeline. The project also tests the integrity of field joint coatings, confirming their efficiency and leading to their adoption. The project addresses slugging fatigue challenges along the entire route, particularly at the spans of ZRB triggers. 3D Finite Element Analysis (FEA) using ABAQUS software, with Tube-in-Tube (ITT) elements, is utilized to understand the complex interaction between pipeline dynamics and seabed conditions, capturing long-term integrity within lateral buckles. The impact of walking and buckling due to high pipe-soil interaction at localized pipeline embedment is reviewed through the pipeline touchdown profile. The use of Pipe-Clamping-Mattress (PCM) and an Equivalent Friction method in FEA improves efficiency and accuracy. 

These methodologies collectively ensure the subsea pipeline project's success in installability, maintaining pipeline integrity and reliability under challenging deepwater conditions.

Authors: D.A.S.Bruton (Crondall Energy); C.M.Martin (Oxford University); M.Witz (Crondall Energy) 

For most on-bottom pipelines, lateral buckling is virtually inevitable, and the design objective is to control the buckling process by initiating buckles in pre-determined locations. 

In operation, lateral buckles cut a trench bounded by soil berms.  Numerical simulation of this behaviour is a significant simplification, being based on horizontal sweeping under constant vertical load with springs to represent soil berms.  In reality, as the pipe moves laterally it displaces vertically.  The apex of the buckle cuts a trench, inflection points form as the pipe rotates, and vertical contact forces vary along the length of the lateral buckle while the soil berm restraint is load-controlled. 

The authors have developed a state-of-the-art modelling approach that simulates transverse pipe–soil interaction on soft clay, using sequential limit analysis for multiple 2D slices of soil attached to a 3D structural model of a pipeline undergoing lateral buckling, running within existing Abaqus FEA software. This approach has been used to evaluate field examples to:

• Compare predicted fatigue damage with traditional analysis methods, quantifying design conservatism.  

• Assess the response of soil berms, to identify more appropriate berm resistances.

• Model ‘heavy’ pipe, which traditionally requires mitigation such as buoyancy.

This modelling approach has the potential to become the software of choice for assessment of the most challenging pipelines. Capturing realistic predictions efficiently and robustly, it has the potential to make significant savings on mitigation costs.  

Authors: Marco Puliafito and Rupert Rowland, Subsea7

Co-authors: Ashley Ruthnum, Danijel Mijic, Zoran Vidovic and Stylianos Panayides, Subsea7

Routing subsea pipelines through steep and rough escarpments presents significant challenges. Ensuring the integrity of these pipelines can be challenging, and seabed interventions are often necessary. This paper provides an overview of a project Subsea7 has executed where the seabed along one 16-inch and one 12inch trunkline routes presented significant challenges. The trunklines crossed an extremely steep and rough escarpment, characterized by a network of canyons with high longitudinal and transverse slopes, scattered vertical features, variable soil conditions and rock outcrops. Engineering and operational activities were undertaken to plan and execute the necessary seabed rectifications to achieve adequate route profiles for the safe installation and operation of the trunklines through the escarpment. The standout achievement of this operation lays in the scale and complexity of the seabed rectifications required and the efficient engineering and operations which were carried out over a tight schedule of less than one year. To meet the project schedule, design, procurement and offshore operations were performed in parallel, necessitating exceptional coordination among all parties. This included planning for alternative seabed rectifications, such as rock installation or excavation, depending on the seabed features encountered offshore. The engineering activities focused on pipeline routing optimization, on-bottom roughness analyses, and geotechnical assessments. Operational activities included the mobilization of multiple subcontractors, development of robust procedures including detailed decision-making protocols, and continuous multidisciplinary offshore engineering support.

Author: Akash Arun, Graduate Engineer, Peritus International

Typically, governing criteria for pipeline tie-in spool design include allowable loads on the riser bottom flange. This paper presents a project case study where Peritus undertook detailed pipeline tie-in spool design for an offshore Angola platform. Initial riser and tie-in spool modelling showed computed loads exceeded riser bottom flange limits. A major factor was the riser’s transition into static equilibrium after installation (i.e., riser bottom flange weight taken by the spool swan neck). In reality, risers are installed before spool connection; the riser bottom flange remains unstressed until spool attachment, at which point interface loads develop due to component interaction. Capturing this sequence in industry-standard software is challenging, as typical spool modelling programs lack sequential static analysis capability. To address this, an optimized methodology used separate models. First, the riser is analysed alone to determine its as-installed configuration. Separately, a spool-only model with a fixed-end boundary condition calculates interface loads. These loads are then applied to the riser to determine its local stiffness at the interface. Finally, the spool model is revisited and reanalysed with computed stiffness, refining interface loads. This iterative approach better represents real-world installation conditions, reducing excessive conservatism from modelling riser and spool together. In this case study, it resulted in acceptable flange loads and a satisfied client.

Author: Tanzil Ali Khan, Rigid Pipeline Discipline Manager, Subsea7 Malaysia Sdn Bhd

Flow Induced Vibration (FIV) poses significant challenges to the integrity and performance of offshore structures, particularly rigid vertical jumpers suspended above the seabed. Fatigue damage due to FIV often leads to potential fatigue failure of girth welds. This paper investigates the use of buoyancy modules as an innovative and effective mitigation strategy for FIV fatigue in subsea rigid jumpers. Numerical simulations based on project data assess the performance of buoyancy modules in altering the structural natural frequency response, thereby reducing vibration amplitudes and associated stresses. While the use of buoyancy modules to reduce stresses and tie-in loads during normal operation is common, their strategic placement along rigid jumper legs to mitigate FIV fatigue is relatively novel. The paper introduces the fundamental principles of FIV, calculation methods, and its detrimental effects on subsea rigid vertical jumpers. It then presents the design and concept of buoyancy modules as an innovative approach to dampen FIV, incorporating fluid-structure interaction and various operational and environmental conditions. Finite element analysis and advanced computational fluid dynamics (CFD) techniques in the frequency domain are used to examine the effectiveness of buoyancy modules in mitigating FIV fatigue. Case studies from live projects demonstrate the practical implications and benefits of utilizing buoyancy modules on subsea rigid jumpers, considering constraints such as cost, impact on jumper tie-in loads, and vortex induced vibration (VIV). The results highlight the promising potential of buoyancy modules as a viable solution for mitigating FIV in subsea rigid vertical jumpers, providing valuable insights for enhancing structural integrity and safety in offshore engineering.

Author: Moeen Nazari, IKM Ocean Design

Over the last years, the frequency of incidents in Baltic Sea causing damage to pipelines, and telecommunication and power cables has increased. Considering these events and developments in the geopolitical situation, establishing a rapid repair procedure is crucial to ensure that the damaged pipelines and cables are back in service swiftly. In October 2023, the Balticconnector offshore pipeline sustained damage due to a dragged anchor incident, causing a rupture that required repairs. The damage occurred in 60 meters of water depth, within a section of the pipeline surrounded by third-party asset crossings. As a result, the pipeline was displaced from its original course and dislodging rock berms installed at nearby crossings. Given the critical importance of the pipeline and to minimize the shutdown period, repair operations had to begin within weeks. As a result, the lift and shift, in-place, and geotechnical analyses, were conducted almost simultaneously with the offshore operations. To lift and shift the damaged pipe into the repair position, lateral barriers were required to function as turn points. In addition, foundations at 5 locations for heavy subsea repair equipment, with submerged weights ranging between 30 to 72 tonnes, were required. Only limited number of concrete log mattresses were available to be used as foundations on a seabed with extremely soft clay on the top 2-3 meters. This paper outlines the design of the lateral barriers and foundation solution for the repair frames, developed within a narrow timeframe and under significant constraints, including limited equipment, environmental challenges, and the inherent practical limitations of the subsea operations in an area with heavy marine traffic. For the lateral barriers, a combination of clump weights and filter units was proposed and implemented during lift and shift operations. Additionally, an optimized arrangement of two-layered concrete log mattresses was designed for heavier equipment, while single-layered mattresses were used for lighter ones. The lateral barriers and concrete log mattress foundations performed successfully during both the lift and shift, as well as repair operations. Balticconnector repair operation is considered one of the most successful in its kind. As a result, the pipeline was restored to service in April 2024.

Author: Alberto Battistini, Advanced Analysis Dept., Saipem

The In-Service Buckling design of offshore pipelines is widely carried out using probability-based approach to ensure a high reliability for planned buckles formation and an acceptable post-buckling configuration in terms of deformation and loads. The Pro-Buck program is a MATLAB-based tool for analyzing the probability of buckling in pipelines subjected to axial loads induced by pressure and temperature. By calculating critical buckling loads (CBLs) and providing valuable insight into critical points where buckling may occur, Pro-Buck helps evaluate pipeline stability under various conditions. The program uses a Monte Carlo algorithm to capture Virtual Anchor Spacing (VAS) and buckling frictions, generating detailed results that include Characteristic VAS, and pipeline expansion. Pro-Buck introduces an innovative approach that could apply minimal changes to the DNV-RP-F110 methodology and recommendations. It determines soil friction distributions at expected buckles and addresses significant limitations of the traditional approach by sampling lateral friction and out-of-straightness (OOS) factors separately. This separation leads to a more accurate and reliable assessment of buckling risk, resulting in significant cost savings and improved design reliability. Pro-Buck also integrates the calculation of buckling propensity from bathymetric survey data. The results obtained with the Saipem software (Pro-Buck) for one project were successfully replicated with BuckPy, validating both codes and establishing a benchmark for BuckPy. The results from both tools were identical, demonstrating their reliability and accuracy. The paper describes the main capabilities of the probabilistic tool with a focus on the proposed novel approach and potential implementations in DNV-RP-F110. An application is described to highlight the potential benefits in using this advanced engineering tool.

Authors: Adel Jebali, Aubin Malassagne and Wiem Labbene, TechnipFMC.  Rafael F. Solano and Antonio P. G. Romero, Petrobras

Designing controlled lateral buckling for subsea rigid pipelines is crucial for exposed HP/HT flowlines. This design phase typically happens during the project's detailed stages and has been standardized thanks to guidelines (SAFEBUCK JIP, 2015) and recommended practices (DNV-RP-F110, 2021). Triggers such as steel sleepers, distributed buoyancy modules, and the residual curvature method (RCM) initiate controlled buckles. Managing rogue buckles caused by inherent horizontal out-of-straightness (HOOS) from the pipe laying process is a significant challenge. These rogue buckles can lead to conservative designs or reliability issues, as standards cannot cover specific as-laid HOOS for each project. Overestimating triggers to avoid competition with rogues may jeopardize pipeline and equipment integrity significantly. The HOOS and actual flowline routes can only be assessed after post-processing the as-laid survey. Detailed as-laid Finite Element Analysis (FEA), which takes considerable time, is often done after the pipe laying. This creates a significant challenge, as waiting for extended FEA to start production is impractical. Unlike free span corrections, lateral buckling contingency measures to avoid rogue buckles are rarely planned because the as-laid FEA reassessment outcomes come too late. This paper compares a simplified qualitative method using RCM as the main trigger for a deep-water project with an as-laid detailed FEA based on survey data. It also addresses a contingency plan designed before the installation campaign, which was applied due to quick results from a simplified curvature check performed hours after the as-laid survey.

Authors: Ismael Ripoll (Xodus Group) and Carlos Sicilia (TotalEnergies)

The lateral buckling design of surface-laid, subsea pipelines can be optimised by using probabilistic design methods. In areas where the seabed has limited vertical unevenness, the key inputs used in these Monte Carlo simulations are the probability distributions for the pipe-soil interaction and for the lateral out-of-straightness features (OOS). For the pipe-soil interaction response, physical models have been developed based on experimental work and geotechnical principles and distributions can be predicted if adequate geotechnical data is available. For the OOS features however, it is not possible to make predictions based on engineering principles, since these features are the result of random deviations from the intended pipeline route during pipelay. Instead, for this parameter, the industry mostly relies on the empirical distributions that were developed by the Safebuck JIP, based on OOS data from pipelines installed before 2014. These distributions are currently presented in DNV-RP-F110. The approach used in the Safebuck JIP to quantify OOS features consists in performing Finite Element analyses of sections of as-laid survey data to determine the axial force at which a buckle forms (with a certain lateral friction). The ratio of this force and the value predicted by a reference analytical equation (with the same lateral friction) represents the effect of the worst OOS feature in the section analysed. By repeating this process for many sections of survey data, distributions of OOS features can be developed. This paper presents the processing of OOS data from actual projects, following the Safebuck approach. Sensitivity analyses are performed to evaluate the robustness of the approach to quantify OOS features, including the breakout and residual lateral friction and the mobilisation displacements considered in the FE analyses. The sensitivities also consider the robustness of the approach with regards to the scale length considered in the analyses and the appropriateness of the reference analytical equation. Based on these results, the paper proposes a detailed methodology to produce a reliable quantification of the OOS features based on Finite Element modelling of the survey data.

Author: Jamie McPhail, Consultant Engineer and Subsea Commissioning Team Lead, Wood

Pre-commissioning and commissioning of subsea systems is a vital project phase where assurances are given that construction and installation of the subsea system has been completed correctly and that the systems are safe to start up.  However, as this phase is generally the final phase before handover to the operations team, it is often not given the consideration it truly requires from project initiation. Project teams often fall fowl of seeking little to no input from the pre-commissioning and commissioning team until system designs have been finalised and manufacturing is underway with little to no scope for modification.  

For the vast majority of subsea projects, the construction and installation campaign is the most expensive aspect for obvious reasons, however what many projects fail to realise is that subsea system pre-commissioning and commissioning can also have significant cost impacts due to the regular requirement for offshore support vessels, large temporary equipment spreads, significant volumes of speciality chemicals, and bespoke equipment such as temporary pig launchers and receivers (PLRs) etc. This paper aims to highlight the importance of early engagement with subsea pre-commissioning and commissioning teams and how this can have a significant positive impact on overall project delivery, cost and performance.  

Authors: Alexander Guy, Erika Johana Tovar, Joakim Backlund, Anette Groven and Philip Flaherty, Halliburton

Alexander Knight, Sjur Hovelsen, Elena Voskresenskaya, Jarle Øverland, Kjell André Stensland and Svein Viggo Aanesen, Equinor

Masoud Ghorbaniyan and Ojonimi Samuel Haruna, NOV

Statpipe pipeline systems have been transporting rich and dry gas from several fields in the Norwegian North Sea to the Kårstø gas processing plant since 1985. To extend its service life, a new landfall solution was developed, consisting of a subsea tunnel for landing the existing pipelines with new pipelines in the landing tunnel on the seabed, connecting to a valve station onshore. This paper reviews the job sequence to make this operation successful.

The complex operations included decommissioning of the existing 28-in. and 30-in. pipelines, their mechanical isolation, cutting and tie-in to the new pipelines both subsea and onshore, and pre-commissioning and commissioning jobs in the novel pipeline systems. The process involved, in some cases, simultaneous land and offshore activities, and the utilization of a substantial amount of seawater flowing through the pipelines to be discharged to sea. One main challenge was supply and management of such large quantities of water and its post-treatment making it acceptable for discharge at this shoreline location, imposing very strict discharge limits (0.001mg/L) on Hg and Pb.

More than 20,000m3 of contaminated seawater was successfully filtered by a 7000m2 0.1micron ultra filtration unit, allowing all particulate matter to be removed which included ‘Black Dust’ particles, and other contaminants (such as mercury and lead), permitting a safe discharge into the open sea near shore. This amount of seawater, equivalent to approximately seven Olympic swimming pools was handled on the fly, assisted by some significant buffer volumes. This novel solution prevented potential project delays and mitigated subsequent economic and environmental impacts, such as CO₂ emissions. The consequences of unsuccessful water treatment would have been very significant and resulted in substantial time delays, cost impact and CO₂ emissions. 

Utilizing this high-capacity ultra filtration unit for the first time in this application the Statpipe systems with 28-in. and 30-in. pipelines were successfully commissioned, enabling hydrocarbon transport, improving operational efficiency, and extending the service life until 2050 as planned. 

This paper will discuss how intercompany collaboration, good communication, and engineered solutions enabled the safe and successful execution of a complex project with several operations. The project aimed to extend the lifetime of one of the most important pipeline systems in Norway, which transports hydrocarbons to Europe, while providing sustainable solutions.

Author: Antoine Marret, Technical Manager, Saipem

Direct Electrical Heating Pipe-in-Pipe (DEH-PiP) has been around since its development and installation by Shell in the early 2000’s. It is a well-known and field-proven solution for subsea flowline heating, but it exhibits a relatively poor electrical efficiency compared to emerging Heat-Traced PiPs. However, with some improvements, the technology can be a very competitive option for subsea flowline heating. As a result, SAIPEM developed a High-Performance version of the DEH-PiP by introducing two new innovative elements. 

The first is an Aluminium Liner on the inner face of the Outer pipe. Most of the return current flowing in the outer pipe being channelled in this millimetric internal layer made of very conductive and non-magnetic material, the ohmic and hysteretic losses in the outer pipe are highly reduced. The electrical efficiency of the system, thus enhanced up to 95%, leads to:

• Increased flowline step-out by lowering the voltage supply level;

• Reduced power consumption when compared to classical Direct Electrical Heating technologies and thus reduced GHG emissions in production. 

The second is an innovative solution to fulfil the shear stop function needed in a Pipe-in-Pipe, but without metallic bulkheads. Such bulkheads are then replaced by rigid and isolating mechanical links made of composite material allowing an improvement on the lay rate by 20% while improving thermal efficiency and safety in offshore operations.

Authors: Martin MacPhee, Senior Applications Engineer, GMC and Emilien Bonnet, Pipeline Engineer, Total Energies

Every steel grade has a water depth limit for riser system and pipeline catenary applications above which the resistance associated with thickness increases cannot compensate for the load from additional weight.

Mechanical connectors machined directly onto line pipes allow using higher steel grades without facing weldability issues, enabling development of deeper fields. Absence of girth welds furthermore significantly improve fatigue performances which are critical for riser systems in sour environments. A high strength, HPHT mechanical pin and coupling system, developed and tested by GMC Limited and Total Energies, is presented as a solution as an enabler for deepwater developments, whilst reducing project costs, removing welding, NDT and coating from the critical path (offshore installation phase). In addition to S-lay or J-lay vessels, the possibility to install from drilling ships can widen the range of suitable vessels as well as weather windows. Built on the success of the field-proven GMC pipeline connector, the hybrid ‘HC Series’ system incorporates a non-rotational, push-fit mechanical connector, with multiple gas tight, patented metal seals on the OD and ID. Designed for sour service and features independent Inconel gasket seals which interface with Inconel clad areas within the ID profile. The structural strength of the joint is provided by multiple rings of precision machined teeth, which engage to form a maintenance-free connection, made-up within one minute. It can furthermore be disconnected within the same timeframe for repeat re-use. Non-threaded design and tests under tension as part of make-up procedure ensures reliability of the connection.

Ryan Sangster, Managing Director, Paradigm Flow Services

Paradigm's Flexi-Coil® is an advanced, patented technology with over a decade’s successful track record of effectively resolving offshore pipeline blockages caused by hydrates, wax, asphaltenes, and sand.

The miniaturized composite coiled tubing design of Flexi-Coil® allows Operators to directly target challenging blockages from platform topsides, removing the need for subsea operations, vessel support, or diver intervention — a distinguishing feature of this technology. Flexi-Coil® is characterized by its capacity to navigate complex pipeline geometries, handling over 1,000 cumulative degrees of pipeline bends and an extended operational reach of up to 6 kilometres from the riser entry point. Upon reaching the blockage interface, the system employs high-pressure jetting to disintegrate obstructive deposits and facilitates debris circulation back to the production facility for separation and disposal. Unlike conventional steel systems, Flexi-Coil® utilizes a high-pressure, neutrally buoyant composite coil tubing, which enables traversal through intricate pipeline configurations and reach extended distances without the risk of abrasion or damage to pipeline and flexible riser internals. This results in a fully remediated system, restored to bare pipe conditions. This groundbreaking approach provides Operators with enhanced control over remediation projects, promoting a faster and more effective return to full production capacity. This presentation shall cover recent case studies that demonstrate Flexi-Coil’s ability to resolve complex flow assurance challenges using minimally invasive technology.

Authors: Dario Gravina¹,²*, Selda Oterkus¹, and Erkan Oterkus¹, ¹Department of Naval Architecture, Ocean and Marine Engineering, University of Strathclyde ²McDermott International

Stress corrosion cracking (SCC) in the presence of absorbed hydrogen is a critical failure mechanism in structural materials, particularly in high-strength alloys used in aggressive environments. Traditional finite element analysis (FEA) methodologies often fail to accurately capture the complex interplay between hydrogen diffusion, local stress states, and material degradation mechanisms. This study proposes an alternative FEA methodology in ABAQUS to model hydrogen-induced SCC by integrating hydrogen-enhanced decohesion (HEDE) and hydrogen-enhanced localized plasticity (HELP) as the predominant failure mechanisms. The proposed framework incorporates a coupled diffusion-stress analysis to simulate hydrogen transport and accumulation at critical microstructural sites, such as grain boundaries and dislocation cores. The HEDE mechanism is modelled by reducing the cohesive strength of atomic bonds in the presence of hydrogen, while the HELP mechanism is captured through localized softening and enhanced plasticity in hydrogen-rich regions. A series of user-defined material subroutine are developed to implement these mechanisms, enabling the simulation of crack initiation and propagation in dynamic hydrogen coverage (DHC) under combined mechanical loading and hydrogen exposure. The methodology is validated against experimental data from slow strain rate tests and fracture toughness measurements on high-strength steel and nickel based alloys. Results demonstrate the ability of the proposed model to predict crack growth rates, fracture paths, and hydrogen embrittlement susceptibility with improved accuracy compared to conventional approaches. The work provides a robust computational tool for assessing the integrity of hydrogen-exposed structures and offshore pipeline and offers insights into mitigating SCC in engineering applications.

Authors: Alasdair Clyne, Business Line Manager, Integrity Services, ROSEN (UK) and Michael Tewes, Head of Business Line Hydrogen and Future Fuels, ROSEN (Germany)

The energy transition towards the use of more sustainable fuels is gathering pace.  From the pipeline perspective, this transition involves the building of new, or repurposing of existing, pipelines away from traditional methane (CH4) transportation to hydrogen (H2) as an alternative clean fuel, or carbon dioxide (CO2) with respect to carbon capture, utilisation and storage (CCUS).  These drivers for alternative use of existing pipelines present pipeline operators and owners with new challenges in terms of maintaining pipeline integrity.  For example, the potential embrittling effect of hydrogen on pipe steel is well known, giving rise to an increased threat from crack-like defects.   In addition, there is a risk that both hydrogen and carbon dioxide can damage the ILI tools themselves, and pipeline operational challenges may be significantly more taxing when transporting these “new” products. This paper firstly summarises the available ILI technologies for the detection and sizing of crack-like defects, namely electromagnetic acoustic transducer (EMAT) and ultrasonic (UT) crack detection, together with their relative merits.  The paper will then focus on EMAT technology, which was developed with gas pipeline operators in mind to avoid the need for a liquid batch.  Finally, the paper will focus on the challenges to be overcome when running in different gaseous products, together with the specific challenges associated with crack inspection in offshore gas pipelines from both the technical and operational perspectives.

Authors: Ammar Al Helal, Curtin Corrosion Centre Curtin University

Tiago Kaspary – Cladtek Do Brazil Rio de Janeiro Brazil
Fatma Abdelghafar – WA School of Mines-Minerals Energy and Chemical Engineering WASM-MECE Curtin University 

Ahmed Reda – Cladtek International PTY LTD Perth Australia/Curtin University

The transportation of carbon dioxide CO₂ through pipelines is essential for large-scale carbon capture utilisation and storage CCUS projects. Carbon steel remains the primary material of choice due to its cost-effectiveness, strength, mechanical properties and availability. However, the long-term reliability of carbon steel in CO₂-rich environments is affected by corrosion risks, impurity interactions and material degradation particularly under dense-phase and supercritical conditions. Industry standards outline material selection, corrosion control and integrity management practices alongside various mitigation strategies. This review focuses on directly comparing these mitigation measures for carbon steel against the alternative of using Mechanically Lined Pipe MLP, considering both technical performance and economic feasibility.

The effectiveness of mitigation strategies such as stream dehydration, corrosion inhibitors, internal lining and advanced real-time monitoring techniques is evaluated in the context of CO₂ transport. The analysis highlights how these mitigations enhance carbon steel pipeline longevity and compares their performance to the benefits and limitations of MLP. Particular attention is given to the effects of dissolved water (below solubility limit), free water (above solubility limit), sulfur dioxide, nitrogen oxides and oxygen on material integrity, as well as the influence of phase transitions and pressure fluctuations. The distinction between free water and dissolved water is addressed, noting that free water promotes corrosion while dissolved water below the solubility limit does not pose a significant risk. The review also considers the economic and practical implications of selecting either CS with mitigations or MLP, ensuring a holistic perspective on material selection for CO₂ pipelines. Relevant gaps in current knowledge affecting material performance in CO₂ transport are also identified and discussed. These findings improve pipeline infrastructure resilience and ensure safer and more efficient deployment of CCUS technologies.