The paper seeks to address the challenges faced by High Pressure High Temperature (HPHT) subsea pipelines buckling mitigations and presents a new innovative solution that was evaluated from 2012 to 2016 and first deployed in 2017 then surveyed in 2018 after almost 6 months of operation. Laboratory tests, field tests, small scale tests, full scale tests, analytical derivations and finite element analyses were developed and used to mature the rotating buoyancy technology configuration as a new innovative solution. High pressure and/or high temperature subsea pipelines may experience lateral buckling which require special considerations to mitigate excessive plastic deformation and fatigue during start up and shut down cycle events. One of the widely used mitigation consists of attaching fixed buoyancy modules on engineered sections of the pipeline system. However, postproduction subsea surveys and engineering evaluations showed the currently used buoyancy mitigation methods create large soil berms that may significantly reduce pipeline fatigue life and the opportunity of life extension of the pipeline system. The rotating buoyancy system was developed to help solve this problem and increase the solution robustness to enable potential life extension and possibly reduce the stringent welding requirements at the buckled sections. It represents a step change in the way risks associated with buckling of high temperature and/or high pressure pipelines are managed and effectively mitigated. Between year 2015 and 2016, small scale and large-scale tests were performed using prototype fixed and rotating buoyancy modules to compare the current and new mitigation methods. This paper outlines the methods by which pipe-soil interaction can be simulated. It describes the validation and verification conducted, through experimental testing on both newly developed small-scale and large-scale testing rigs, coupled with computational modelling and analytical predictive calculations. The paper highlights the challenges faced when replicating seabed conditions and pipeline movements. It also highlights novel design aspects which offer improved traction in soft clay environment. The paper also presents the lessons learned during the 2017 offshore installation campaign and the 2018 results of the in-situ survey of the rotating buoyancy modules after the first 6 month of operations and future plans for next generation rotating buoyancy systems including digitalization. The subsea rotating buoyancy is a novel simple system deployed to provide a robust mitigation of subsea pipelines lateral buckling. It provides opportunity for potential increase of subsea pipeline life extension and potentially helps decrease the stringent welding requirement of the pipeline at the buckled sections.

The main objective of this paper is to demonstrate a cost-effective, user-friendly and highly reliable subsea pipeline and subsea structure design automation method developed on a cloud-based digital field twin platform. The FEED and detail design phase of the subsea pipeline and subsea structures are normally quite long and need to run several analyses sequentially to achieve the desired results. In this cloud-based design automation method, a significant number of calculation hours are saved due to systematic and sequential approach with minimum remediation work by reducing human error. In this proposed design automation framework, all the standard pipeline and subsea structure design calculations including code checks based on design standards are performed through a web-based graphical user interface (GUI) designed in cloud-based digital field twin. In the design phase of the subsea pipeline, some more advanced level pipeline finite element analyses are performed for buckling and walking assessment. The design phase of the subsea pipeline consists of different analytical as well as finite element (FE) calculations which are performed systematically and sequentially in cloud-based digital field twin. Various pipeline engineering calculations are performed sequentially and systematically in the cloud using the metadata information available from the digital field data. Some of the standard engineering calculations implemented in the digital field twin are wall thickness calculation (based on design standards), on-bottom stability analysis, span analysis, pipe end expansion analysis, pipeline global buckling analysis etc. All the standard pipeline and subsea structure design calculations are developed in python, which is connected to the cloud-based digital twin through API. For advanced FE analyses for lateral buckling and pipeline walking, the preliminary susceptibilities are assessed through analytical calculations developed through python-based API. For the pipeline FE analysis for lateral buckling and walking assessment, pre-processor and post-processor are developed in python based on various metadata (pipe data, soil, environment) information available in the subsea digital field. The pipeline design calculation outputs are stored in a standardised report format in the cloud platform. The proposed GUI developed for the pipeline and structural design automation is user friendly and the whole process is automated through the python API. This design automation approach significantly reduces the total project cost. Digital Field Twin integrate all the subsea pipeline and structural design calculations and automate the report generation. The proposed digital field twin is very much beneficial for the early stages in the projects where some changes are expected. This subsea pipeline and structural design automation system built on the cloud-based digital field twin through API so that it works as an integrated system giving 3D digital field diagram to perform all the design calculations in one digital platform.

The integrity of subsea pipelines is required to be verified through external surveys and inline inspection to ensure safe operation. If free spans based on external subsea inspection exceed the design calculated allowable free span length, free span corrections are performed by placing grout bags or mechanical supports along the span. However, as free span corrections are very costly, therefore, further free span assessment should be performed prior to any subsea intervention. An alternative approach of "local free span analysis" is proposed to optimize the free span corrections. Local free span assessment can be performed for each survey span exceeding allowable span length taking into consideration the relevant input data applicable for the specific free span location rather than for a section of the subsea pipeline. It shall be noted that during design phase, allowable free span lengths are calculated by dividing the total pipeline length into segments, and for each segment the worst case input data is conservatively taken. On the contrary, local free span analysis approach considers key input factors such as effective axial force, wave and current (environmental) data, water depth and pipe-soil interaction parameters pertinent to explicit span location. Local free span analysis has been successfully applied for free span assessment of a number of operating and new subsea pipelines. This paper will present case studies where revised allowable free span lengths have been calculated prior to previous approach of direct subsea intervention and highlight the associated benefits. Local free span assessment approach will significantly reduce the number of required free span corrections especially for long length subsea pipelines. The optimization of free span corrections will result in significant cost savingsas well as schedule improvement.

To date, there are no publicly available, validated tools or industry accepted guidelines for the assessment of Vortex-Induced Vibration (VIV) fatigue of rigid Jumper (spool) systems. The existing state of practice has been to treat rigid jumper systems as free spanning pipelines and apply the associated design principles in DNV GL recommended practice DNV-RP-F105/DNVGL-RP-F105 (Free Spanning Pipelines). However, widely used rigid jumper systems such as the M-shape jumper systems are subjected to complex flow fields around their legs and bends and fall outside of the test data used to generate the free-span response model in DNV GL Recommended Practice (RP). A Joint Industry Project (JIP) ‘Jumper VIV JIP’ that included BP, ExxonMobil, Petrobras, Saipem and DNV GL was conducted between Dec. of 2014-2016 to collectively tackle the technical issues related to the VIV design of rigid jumper systems. Through the JIP study, measured responses from ExxonMobil's jumper tow test data were used to develop new response curves for jumper systems in pure-current condition. Curves for in-line and cross-flow responses were initially developed by classifying the measured responses into in-line or cross-flow directions and compared against the existing DNVGL-RP-F105 response curves. Due to potential ambiguity in classification and application to Jumper Design, a more general curve that does not rely on directional classification has also been generated. Due to the differences in behavior of rigid jumper systems to that of free spanning pipelines, a new VIV guidance report was developed as part of the JIP deliverable. Principles and philosophies in the DNV-RP-F105 were followed in the development, but with the intent of identifying unique behavior of jumper systems for a subsequent update of the RP. This paper presents the Guidance notes from the JIP and forms the first release of Jumper VIV fatigue assessment approach to the Industry. ExxonMobil's model test data, the only known test data available in the industry, was used in the development of unique response model and the new design guidance. The paper includes the new response model along with VIV screening, safety factors and unique considerations required for fatigue assessment of jumper systems.

Deep water pipelines operating under high pressures and temperatures are susceptible to gradual global axial movements over a number of heating and cooling cycles – A phenomenon known as axial walking. These cyclic axial movements that occur in high pressure-high temperature(HPHT) offshore pipelines are usually induced by four mechanisms: Seabed slopes along the pipeline route Riser base tension induced by a steel catenary riser at the end of a pipeline Thermal transients during startup/shutdown cycles Multiphase flow behaviour like slug-induced flows, start up, shut down and ramp up operations Several mitigation measures for pipeline walking as a results of these mechanisms have been developed and studied over the years with the most common being the use of hold-back anchors installed either at the middle or the end of a pipeline, the latter being the preferred method. Historically, estimation of the required anchor force to restrict pipeline axial movement has been premised on the amount of soil frictional resistance required to equal the driving force due to temperature and pressure. This methodology can lead to erroneously high estimates of the required anchor force for walking mitigation, leading to large-sized pipeline anchors with an attendant increase in capital expenditure associated with pipeline projects. This paper estimates, with a higher degree of accuracy, the required anchor force to mitigate axial walking due to seabed slope or steel catenary riser(SCR) tension. The methodology described in this work involves the use of a mathematical proof to show that the magnitude of the walking mitigation force for a pipeline susceptible to walking is directly proportional to the pipeline submerged weight. The solution was also validated by a finite element analysis(FEA). The finite element analysis was carried out using the multipurpose industry FEA tool, Abaqus with the pipeline modelled using beam elements and the soil modelled using three dimensional analytically rigid elements. The coulomb friction model was used with frictional forces defined in the axial direction only. Several cases were analysed in Abaqus using several pipeline sizes and soil friction coefficients in order to validate the analytical results. The analytical and FEA results agree quite well and show that the restraining force required to mitigate pipeline walking due to global seabed slope and SCR tension is solely dependent on the pipeline submerged weight and SCR tension respectively. This paper proffers a cost-effective mitigation to seabed slope and SCR induced walking by showing that pipeline walking mitigation is not dependent on the magnitude of the axial friction resistance which usually requires large mitigation forces to counter the large frictional forces that may result particularly when we have a fairly long pipeline.

Mobile mudmats are increasingly adopted as foundation solution for subsea structures in offshore field developments, to allow their horizontal movement under the cyclically imposed expansion/contraction operating loads from the connected lines. The foundation compliance grants the dissipation of the applied loads while the structure slides on the seabed and the required base dimensions are reduced. Foldable solutions can even be installed integrated with the related lines, passing through the pipelay vessel tower. The described experience is based upon design and installation of mobile mudmats for subsea structures in the last twenty years of activity in several deepwater areas all over the world. The design has been improved with time and its robustness has been demonstrated using alternative analytical approaches and Finite Element Model of the system with proper definition of soil-foundation behavior through equivalent springs. The geotechnical engineering effort focused to ensure the foundation adequate bearing capacity and its ability to slide under repeated thermal/pressure expansion loads during design lifetime, without developing excessive settlements and pitch/roll unacceptable rotations that could compromise the system performance. The purpose of the present work is to raise awareness of the need for reference international criteria for the design of mobile foundations, which represent an important solution for a subsea field development. Available Codes and Standards do not cover the relevant aspects of the mobile foundation engineering: they are based upon fixed foundation concept, which is expected to be stable under all the applied load combinations without developing any significant displacement. The mobile foundation engineering challenge is to accept that a failure mechanism develops in sliding condition while proper design criteria of system stability and reliability are fulfilled. Valuable and impressive research works have been carried out and published on the subject in the recent years. However, for practical application, specific criteria are required to provide a unique basic reference for design (minimum safety requirements/methodology/guidelines), which might be supported or not by more detailed and complex approaches, as occurs for traditional "fixed" foundations. Subsea structures could be regarded in the future as special components of the pipeline with a proper methodology to investigate their interaction with the seabed for the subsequent structural analyses.

Standard pipe-in-pipe (PiP) technology consists of an inner flowline insulated with high performance dry insulation and an outer carrier pipe that protects the insulation. Electrically Trace Heated Pipe-in-Pipe (ETH-PiP) technology is an adaptation of the standard PiP where electrical trace heating (ETH) and fiber optic (FO) cables are wound around the flowline, under the insulation, to provide active heating and temperature monitoring of the conveyed fluid. ETH-PiP allows operators to optimise field layout and production and minimise the risk of pipeline blockages. Reel-lay is an efficient installation method for subsea pipelines. Reel-lay is well suited to ETH-PiP as critical fabrication activities can take place onshore and before pipeline installation. Reeled PiP flowlines are subjected to plastic bending. During offshore installation, the flowline may see a combination of this plastic bending and high axial tension due to the catenary. The combined loading leads to permanent elongation of the inner pipe which has the potential to transfer tensile loads into the electrical and optical cables. Moreover, the annulus space between the inner flowline and outer carrier pipe is reduced during reeling which may put electrical components at risk of mechanical damage. This paper discusses an extensive qualification programme which was performed to quantify the cable loading during installation, and to demonstrate the subsequent cable and splice integrity and fitness for service. A physical bending trial was performed where several ETH-PiP specimens were subjected to plastic bending on a cantilever bending rig while axial tension was applied to the flowline. This represents an industry first for a practical test which realistically replicates the loading conditions experienced by a PiP system during reeled installation. Throughout the bending trial, the cables were strain-gauged to record axial tension, and the anulus space around the cables/splices was measured to record radial compression. Following bending, the cables and splices were removed from the test specimens and subjected to third party electrical and optical testing to verify integrity. The qualification scope not only verified that cable integrity is maintained throughout reeling, but also quantified the loads involved. Data gathered from the testing was subsequently used to benchmark finite-element (FE) reeling models. These models allow more accurate prediction of cable loading on future reeled ETH-PiP systems, including deep water pipelines.

Rock berms are used for many different offshore pipeline applications such as protection from anchors and trawlers, mitigation against pipeline global buckling and improvement of pipelines on-bottom stability. Understanding the lateral resistance provided by rock berms to pipelines is essential for all the above applications. This paper presents insights into lateral resistance of rock berms restraining pipelines by finite element analyses. Pipelines of various diameters (0.2 m-1.5 m) within typical rock berm geometries were modelled in PLAXIS 2D to evaluate the peak lateral resistance provided by the rock berm to the pipe. The finite element model was validated against available full-scale test data. The results of the numerical analyses demonstrate that the peak lateral resistance of a pipeline in rock berm depends mainly on the unit weight and the frictional properties of the rock, while the mobilization to reach the peak resistance is dependent on the rock berm stiffness. Based on the results from this study, a simplified design chart is presented which provides the lower bound peak lateral resistance for a given pipe diameter under typical rock berm with cover to top of pipe in the range of 0.3 m to 1 m. This design chart could be used by engineers undertaking preliminary design assessment of pipelines in rock berms.

In order to deliver on the ambitious schedule for the Johan Sverdrup development, the operator and the Johan Sverdrup-partners also needed to make some innovative bets on new technology. This paper explores two areas – innovations in installation and pipeline technology – that played a key role in the development of the mega-project. In particular the decision to qualify and become the world`s first user of the single-lift installation technology developed for the vessel Pioneering Spirit ended up changing the very concept for construction, installation and completion of three of the four topsides that make up the Johan Sverdrup field center in the first phase of the development. The technology – developed by the installation contractor and qualified for first use worldwide by the operator – saved an estimated 2.5 million offshore manhours from the offshore completion phase, which significantly reduced safety risks and helped shave months off the development schedule. The first-ever use of the technology to install topsides took place in June 2018 with the single-lift installation of the drilling platform topsides on the Johan Sverdrup field. And in March 2019, the two remaining topsides weighing a total of 44,000 tonnes were lifted in place in the span of only 3 days, including the heaviest offshore lift ever executed with the installation of the 26,500 tonnes processing platform. The paper also intends to explore how the same innovative mindset and focus also played a role in introducing new pipeline technology – in particular, the world`s first use of remote-controlled and diver-less hyperbaric welding of the ‘’36 oil export pipeline to the Johan Sverdrup riser platform. The paper also discusses how the project benefited from further industrialization of the hot-tapping technology used for the first time by the operator in 2012 on the Åsgard subsea project, when connecting the Johan Sverdrup gas export pipeline to the ‘live’ Statpipe gas pipeline. Part 1 of this paper covers single lift installation of topsides, Part 2 covers diver less hyperbaric welding.

Lateral buckling mitigation design for HPHT pipe-in-pipe system is technically challenging and at times the reliability of proven buckling mitigation options may come into severe technical scrutiny for some HPHT pipe in pipe systems on the undulating seabed. The Residual Curvature Method (RCM) presents as an alternative technical option for such cases. The technique comprises understraightening in intermittent sections of the ‘as-laid’ pipeline which form ‘expansion loops’ and provide a proven, reliable and cost-effective buckling mitigation. The method was successfully implemented in Statoil’s Skuld project in 2012 and subsequently a few other projects worldwide which are all single pipeline systems. However, the RC method was not used as a buckling mitigation method for a pipe in pipe system to date to the knowledge of the authors. Residual curvature method could be proven superior for HPHT Pipe-in-Pipe Systems to other lateral buckling methods (thanks to controlled well-developed buckles at pre-determined locations) under some favourable design conditions. This paper shows the robustness of the technique for a typical 12" / 16" HPHT pipe in pipe system with an operating pressure of 300barg and 150°C operating in a maximum water depth of 2000m as a case study. The PIP system is considered to be laid by a reel-lay method, which is amenable to inducing the residual curvature at the pre-determined RC locations during pipelay process. The study includes the special considerations required in deploying the method on an undulating seabed taking into account unplanned buckles or spans and the necessary adjustment to be made to pre-determined buckle sites. The study includes the effects of inner pipe snaking (with residual curvature) within a near straight outer pipe due to the reeling process and its impact on the lateral buckling behaviour. Other design features that may have a significant effect on the RC method are discussed.

Corrosion protection is a key aspect of all subsea developments. Indeed the complexity of subsea pipe maintenance and repair makes it necessary to provide solutions suitable for the full life time of the field. Though sensitive applications such as production lines transporting corrosive compounds, CO 2 and H 2 S for instance, immediately comes to mind when mentioning corrosion, other applications, though seemingly less demanding, also require to be properly addressed from a corrosion perspective. One of these applications is water injection lines. Corrosion in these lines is usually tackled with using a wide range of approaches depending on operation philosophy: topside treatment, corrosion allowance, cladding or plastic liners. A balance usually has to be found between how extensively the injected water is processed topsides and what other corrosion mitigations methods are deployed. This assessment should be carefully conducted the selected approach will impact procurement and installation costs. For instance, increasing the pipe wall thickness to cope with corrosion would results in higher lay vessel installation capabilities as well as longer welding time while relying on clad pipes would negatively impact procurement costs and require more complex NDT methods to be implemented. Plastic liners offer a relevant alternative though their implementation has to be carefully assessed so as to ensure it remains cost competitive. To that extent, the Fusion Bonded Joint has been developed and qualified. This system ensures the continuity of the plastic layer at carbon steel weld locations while limiting the offshore cycle time thus preserving lay rates of the installation vessel. This paper includes an overview the technology itself as well as a summary of the extensive qualification campaign that has been carried out. A global overview of the testing campaign will be provided from the early stages of the development to the full scale testing of the technology in an environment representative of its actual operating conditions. Topics discussed will include: prototyping of the system and associated tools, qualification of the electro-fusion welding process as well as its control and qualification of the carbon steel welding process. The main challenges and outcomes of tests performed will be presented and discussed. A focus on the specificities of the fatigue testing campaign will be presented including fatigue string design as well as fatigue performance of plastic electro-fusion weld. Eventually, the applicability of the FBJ to reeling will be discussed.

In the "lower for longer" barrel price environment, new projects and field developments need cost effective improved approaches; amongst them, the concept of "Progressive Subsea Field Construction". In this alternative concept, construction of elements that are not critical to first oil but only here to support the assets integrity - typically subsea pipelines foundations and consolidating structures - is deferred to the operational life of the facilities, thus benefiting the cash-flow and net present value of a project. This principle is well known to field architects that strive at ensuring that the cash generated from early production is used to finance the rest of the development - "Production while drilling" is a typical example of such approach. In the vision conveyed in this paper, part of the structural construction can be delivered as a continuous (staged) service rather than an initial investment. The paper analyzes two real cases of pipelines in deep-water West Africa, representing the evolution of the state of the art over the past 15 years. It then benchmarks these real cases against a novel approach, to demonstrate the benefits of continuous service in staged construction and integrity management. Results provided in this paper demonstrate that there is benefit to the economics of a project, a minimal increase of 2% of a pipeline system Net Present Value, in setting a monitoring procedure, a monitoring device (like a resident subsea inspection vehicle) and data management system to allow for continuous construction. The paper also demonstrates that economic benefit is furthermore amplified when time comes to extend the life of the asset, in such case the Net Present Value of the same system increases by 5%. Since the case study focuses on pipeline anchoring, the paper also attempts at showing this concept could be used more extensively in full field developments. Indeed, the novel approach proposed in this paper opens the door to a completely novel collaboration model between contractors and operators, establishing continuity of construction during the full life cycle of a field. It aims at generating discussions and new ways of thinking to help the industry evolve towards lower costs of development and more sustainable contracting models.

Slope instabilities and consequent mass gravity flows are major hazards for offshore pipelines, flowlines, cables and umbilicals crossing submarine slopes. Although several methods are available to evaluate the stability of submarine slopes, uncertainty remains over the evolution of the failed soil mass from slide initiation to complete run-out, which may lead to impact and damage of the assets even at significant distances from the initial failure. This paper is intended to apply in-situ knowledge required for the evaluation of the risk of damage and displacements of offshore pipelines caused by the impact of forecasted submarine mass transport events, typically defined as debris flows. A step-by-step methodology is proposed to define design event scenarios tied to site specific geological and geotechnical characterization, calibrate numerical models aimed to ultimately assess mass flow trajectories and impact forces on a given pipeline segment, and to drive pipeline structural response analysis. A fluid dynamics debris flow model, accounting for the seabed 3D bathymetry, has been developed to predict the propagation of debris flows from inception to runout. The model is calibrated against recent well-identified local debris flow deposits, mapped and characterized in terms of preconditioning factors, triggering mechanisms, resulting morphologies, flow dynamics and ages through the use of a combination of geophysical, geotechnical and geological tools. Specific laboratory tests are performed at relevant location and depths, to evaluate the expected rheological behavior and ranges of yield strength and viscosity of the failed soil mass. Design scenarios are then selected based on local morphology and tied to dynamic slope stability evaluations which define the likelihood of the event and initial failed volume. Model input parameters are critically evaluated based on relevant calibration cases. For each simulated scenario, results include the trajectory and run out distance of the mass flow events, along with the distribution of flow velocity and thickness in time and at each location along the flow path. Finally, the main parameters governing the effect of debris flow events on pipelines exposed on seabed are evaluated for incorporation in spatio-temporal pipeline structural response analysis. As with any engineering analysis, results are only as reliable as input. In the case of debris flow impact on pipelines, it is critical that analyses are carefully constrained with field and laboratory data. At each step in the process engineers and geologists must assess the site conditions, and insure that results are meaningful. This applies to all steps in the process, from the initial site characterization and identification of credible geohazard scenarios, selection of modeling methodology, evaluation of rheological parameters (preferably measured in the laboratory), model calibration and matching to field observations, through the final numerical modeling of the pipeline response to impact. The methodology outlined below identifies the main steps in the analysis, and highlights the need to verify engineering results with field observations.

Subsea pipelines are usually buried in shallow waters for physical protection. Buried pipelines may experience large lateral displacement in different occasions such as ice gouging, ground movement, significant thermal gradients, and dragging by anchors, fish traps, etc. Backfilling materials are often heavily remoulded under functional and environmental loads and are considerably softer than trenched native ground. This, in turn, affects the failure mechanisms in the surrounding soil and the lateral load-displacement response of the pipeline, consequently. These important considerations are covered less often in the design codes and standards. In this study, the lateral pipeline-backfill-trench interaction was studied through centrifuge testing of sixteen distinct pipe-soil configurations under drained and partially drained conditions. A transparent observation window combined with digital cameras were used for Particle Image Velocimetry (PIV) analysis. A range of instruments was installed on the pipeline, backfill, and the trench to obtain the key data and the lateral p-y response of the buried pipe. The influence of several key parameters on the lateral pipeline response was also investigated including backfilling properties, trench geometry, interaction rate effect, and burial depth. The results showed that the failure mechanisms, affected by various pipeline-backfill-trench interaction parameters, have a significant impact on the lateral p-y response and the ultimate soil resistance. The study program provided an in-depth insight into this challenging area and prepared the ground for proposing new models and methodologies for incorporating more realistic conditions for pipeline design subjected to large lateral displacements.

In this paper, the sources of uncertainty in the design of buried offshore pipelines against upheaval buckling in cohesionless seabed soils are combined and propagated within a reliability-based framework. The objective of this effort was to assess the inherent risk for pipelines that are designed as per standard practice, which is based on semi-empirical approaches that assume vertical or inclined slip line models within the overlying soil mass. A comprehensive database that consists of 143 laboratory experiments involving uplift of pipes through sand beds was compiled to assess the model uncertainty. The statistics describing the model uncertainty could be used by researchers and practitioners when assessing the risk of upheaval buckling of pipelines in cohesionless seabed soils. Results of the model uncertainty analysis indicate that the models of Schaminee et al. (1990) and Bransby et al. (2002) result in predicted soil uplift resistances that are on average 21% and 41% smaller than the resistances measured in the laboratory tests, respectively. The two methods also exhibit large model uncertainties with respective coefficients of variation (COV) of 0.39 and 0.37 for the ratio of measured to predicted resistance. The methods by White et al. (2001) and DNV (2007) are less conservative and less uncertain, with average under-predictions on the order of 2% and 9%, respectively and COVs on the order of 0.30 and 0.32. The reliability analysis results indicate that the probabilities of failure are sensitive to the design factor of safety, with probabilities of failure decreasing from around 1% to 0.001% as the factor of safety is increased from 2 to 3. For any given factor of safety, the probability of failure was found to be sensitive to the method used to predict the uplift resistance, and insensitive to the relative density and the temperature and pressure values adopted.

This paper presents the application of a reliability based design methodology for interference between trawl gear and pipelines, and the associated cost savings in subsea rock installation. As part of Wintershall Norge's Maria development project, a 26 km long 14″ production flowline with DEH (Direct Electrical Heating) and a 46 km (43 km + 3 km infield) long 12″ water injection pipeline has been installed and left exposed on the seabed. The seabed topography in the area is un-even and scarred by iceberg ploughmarks, leading to a significant number of large free spans. Furthermore, fishing activity must be taken into account in the design of these pipelines. According to DNV-RP-F111, if the trawl gear hits in a free span, the pull-over load will be significantly higher than if it hits a section in contact with the seabed. Preliminary analysis indicated that by using the LRFD (Load and Resistance Factor Design) approach as per DNV-RP-F111, a large number of free spans would require rock infill in order to limit the trawl pull-over load. In order to optimize the design and potentially reduce the requirement for free span infill, an optimised methodology based on SRA (Structural Reliability Analysis) was proposed by Wintershall, developed by DNV GL and implemented by Subsea 7 during detail design phase. The optimised methodology involves FE analyses of the sensitivity to various parameters and Monte Carlo simulations, in order to quantitatively assess the probability of failure. Specific FE models analysing the bending moment capacity and response were established. The various input parameters were assessed and included as distributions if deemed required from the sensitivity analysis. Finally, a Monte Carlo simulation was performed to calculate the probability of failure. It was demonstrated that the target safety levels defined by DNV-OS-F101 were reached without free span infill, and hence significant savings in subsea rock installation could be achieved without any deviation from the DNV-OS-F101 code. Cost saving due to reduced subsea rock installation scope is estimated to 7.6 mill Euro. Wintershall facilitated a close dialogue between DNV GL and Subsea 7 throughout the work progress. This resulted in a constructive and open approach, ensuring efficient delivery of the detailed design in line with project schedule. The work carried out has demonstrated two relevant examples where performing a SRA, as opposed to a LRFD, has resulted in a significant reduction of seabed intervention requirements and an associated cost saving, while still being in compliance with DNV-OS-F101 target safety levels. To our knowledge this is the first time the SRA method has been applied for trawl interference design on a live project, and on a CRA (Corrosion Resistant Alloy) lined pipeline with DEH system attached. The success was made possible by close collaboration between the parties involved; Wintershall, DNV GL and Subsea 7.

On November, 2010 Petrobras defined the necessity of one additional gas export pipeline in Santos Basin Pre-Salt area to improve the capacity of the export gas network and assure the objectives defined in the Strategic Plan. Nowadays there are two gas export pipelines in operation to export the gas from pre-salt area: Rota 1 connecting Lula Sul field to onshore facilities in Caraguatatuba/SP and Rota 2 connecting Lula Área de Iracema Sul to onshore facilities in Cabiunas/RJ. The new 20-in and 24-in gas export pipeline named Rota 3 is approximately 307km long and connects Lula Norte field in Santos Basin to Jaconé Beach/Maricá It has 15 spare hubs and 3 PLEMs for future connections to Sépia, Berbigão, Atapu, Sururu, Buzios and Libra fields. Also, Rota 3 is interconnected to export gas pipeline Rota 2 in a loop to permit gas exportation through Maricá and Cabiúnas. This paper addresses the pipeline design optimizations based on standard DNV-0S-F101 and on several consulting to national and international pipe suppliers. Full scale qualifications tests were performed in accordance with DNV-0S-F101 to permit the use of the alfafab factor identical to one for the supplied 20-in UOE pipes. All qualification process was witnessed by DNV. Additional simplifications were introduced aiming to costs reduction and in order to improve attractiveness of EPCI (Engineering, Procurement, Construction and Installation) contract. Installation contractors were invited to suggest simplifications to the project. Lessons learned during the design, BID process and installation phase of the project are also envisaged.

With the increasing demand in the gas field developments around the world which typically characterizes a large diameter subsea to shore gas export pipelines, tie-in connectors become necessary to be able provide to connection between various subsea structures. To qualify a new large bore connector present significant cost and schedule challenge especially for pipe sizes above 34′ and associated risks during installation. BHGE with its 25 plus years of experience and track record in this product category has successfully developed and installed 42′ subsea clamp connector combined with proprietary open-PLET technology which has increased the reliability and safety during installation. The 42′ M5 connector was used to tie-in the Ichthys gas export trunkline to the subsea structures which to date is world's largest subsea connector for flowlines tie-ins.

Objectives/Scope: This paper describes a project to facilitate cost effective and reliable surveillance of cathodic protection performance on two parallel rock dumped pipelines. The lines are located in Total's Edradour Glenlivet field one 12″ production flow line and one 6″ MEG line with a 2″ piggyback service line. The objective was to be able to verify that cathodic protection levels on all the lines met requirements. This method was selected based on shortcomings of other available survey techniques which are also discussed and compared. The broader implications of changing offshore pipeline survey methodology to reduce cost and improve accuracy are also covered. Methods, Procedures, Process: The basic approach is to place test stations at intervals along the route of the lines on the edge of the rock dump. These test points are electro-mechanically connected to the pipes prior to the rocks being installed. The ROV installable attachment clamp design is reviewed along with the key points of the installation procedure. The selection of test location spacing will be discussed along with the options for life cycle survey on the system. Results, Observations, Conclusions: Installation will be discussed along with the initial commissioning results. We will also look at the first verification survey on the system after the rock dump. The simplicity of the pipeline survey and the broader implications for integrity management cost reduction will be reviewed. Novel/Additive Information: The practice of installing test points on offshore pipelines is quite new but is gaining more momentum as the obvious cost and data value improvements become apparent. The currently used systems will soon evolve into smart systems that will allow autonomous underwater vehicles (AUV's) do the work. The method used on this particular project was the first time that the mattress based test stations have been applied to a newly installed pipeline, the first time under a rock dump and the first time on parallel pipelines.

This paper describes a development initiative intended to reduce significantly design cost and duration using digitalization. Subsea pipeline design, and in-place studies in particular, is a complex process that is broken down into a systematic sequence of calculations, all connected to a normalized and serialized meta model. The pipeline digital data model is interpreted by a framework that distributes and collects design data to various algorithms and software, thus automating the entire pipeline design workflow down to production of standardized design reports. The implementation of such an objective requires: Developing a systematic design methodology, covering industry standards as well as the client's special requirements, under a "one-size-fits-most" process; Standardizing a data model serving as a meta-model to necessary models and solvers; Standardizing data format and exchange protocol so that all models are served with required inputs and instructions; Coding design procedures as unitary applications collecting inputs from and relaying relevant results to the data model; Integrating applications into a framework that serves inputs and collects outputs from models and calculations to produce final standardized reports. Design reports with input data, results and methodology are automatically created or updated under various file formats or templates. Engineering productivity is improved drastically and the impact of rework is minimized. The productivity gain is multiplied when the design is still in the early stage and when multiple multi-disciplinary design cycles, including the stakeholder's review, are necessary.