Proceedings of the ASME 27th International Conference on Offshore Mechanics and Arctic Engineering OMAE2008 June 15-20, 2008, Estoril, Portugal

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1 Proceedings of the ASME 27th International Conference on Offshore Mechanics and Arctic Engineering OMAE2008 June 15-20, 2008, Estoril, Portugal OMAE ARCTIC PIPELINE DESIGN CONSIDERATIONS D. DeGeer C-FER Technologies Edmonton, Canada M. Nessim C-FER Technologies Edmonton, Canada ABSTRACT Since the discovery of reserves in arctic regions, operators have been faced with a number of challenges, including assessing appropriate methods of transporting produced hydrocarbons to market. For pipeline systems, designers are required to deal with a number of unique environmental conditions not normally present in other regions of the world. These include ice scour, permafrost thaw and/or frost heave, leak detection and containment, and installation techniques. For offshore applications, novel design alternatives that have been considered to address these issues include pipe-in-pipe systems, non-bonded flexible pipes, composite wrapped pipes, and hybrid pipes. Each alternative offers strengths and weaknesses, depending on the specific hazards or failure event consequences that may exist at the location of interest. For buried onshore pipelines, the key design issue is the potential for high bending strains resulting from frost heave and thaw settlement. For both onshore and offshore pipelines, possible ways to address these issues includes the use of pressure and diameter combinations that lead to thick walls, integration of in-service inspection and maintenance within the design philosophy, stringent quality control for girth welds, and selection of materials with appropriate post yield behaviour. Because of the lack of traditional design solutions to these challenges, limit state, reliability-based and strain-based design methods are now preferred for arctic applications. The implementation of these methods requires a good understanding of linepipe material behaviour, soil loading conditions, ice loading mechanisms, and the consequences associated with product release. They allow the integration of analytical and experimental assessments into the overall design philosophy, which has been shown to improve design concept confidence and reduce overall uncertainty. This paper describes some of the key challenges facing the design of both onshore and offshore pipelines. It describes some of the current design options and how reliability-based and strain-based methods can be used to integrate essential information from a number of analytical and experimental sources into an overall framework that addresses the challenges and leads to optimal design decisions. It discusses the state of the art in this area and identifies knowledge gaps that need to be filled. INTRODUCTION Historically, it has long been speculated that large hydrocarbon reserves may exist in the north. Early geological work and exploratory drilling in Canada in the 1950 s and 1960 s further demonstrated this potential, followed by oil discoveries in the Canadian arctic islands and at Prudhoe Bay on Alaska s North Slope. Along with these discoveries came the realization that further field development, production and transport of these hydrocarbons required huge financial investments, as well as practical solutions to many technical, logistical, and environmental challenges. For many of the smaller discoveries, field development was deemed uneconomical, but the vast Prudhoe Bay reservoirs provided sufficient incentive to proceed with development and production. Another smaller development in the Canadian arctic was also undertaken at Norman Wells, and both projects were based on using pipelines as the means of oil transport to southern markets. Today, these pipelines exist and are still in operation; the Trans Alaska Pipeline System (TAPS), and the 1 Copyright 2008 by ASME

2 Normal Wells pipeline. Figure 1 illustrates the locations of these lines in the North American arctic. and for measuring ground temperatures to estimate thaw depths. These innovative techniques allowed for the successful construction and operation of the Norman Wells line and provided valuable research data to support future assessments [1,2,3]. Figure 1 Trans Alaska and Norman Wells Pipelines The TAPS line was constructed below ground in regions thought to be thawed or thaw-stable (or where permafrost thaw potential could be adequately managed), and above-ground in regions where ground movements were perceived to be excessive due to permafrost thaw or to traversing fault zones. The above ground sections of the pipeline were placed on vertical support members that allowed for the changes in the pipeline length due to thermal effects. These support members themselves used thermo-siphon heat transfer tubes to prevent thawing of the near-surface permafrost. The Norman Wells pipeline is a buried line traversing a number of continuous and discontinuous permafrost zones. Figure 2 illustrates these zones and Figure 3 illustrates the basic ground movement mechanisms affecting buried pipelines traversing permafrost intervals. Figure 2 Permafrost Conditions To address these potentially large ground movements due to permafrost thaw, the Norman Wells line, which came into operation in the mid-1980 s, adopted a number of unique design measures. The oil entering the line is initially chilled to -1 C, minimizing the possibility of permafrost thermal disturbance and subsequent subsidence. A number of permafrost thaw-sensitive slopes were also insulated from the pipeline to prevent thaw from occurring, and numerous locations were instrumented and monitored for pipe movements Figure 3 Permafrost Frost Heave and Thaw Subsidence For offshore pipelines, designers must contend with the presence of permafrost, ice (both land fast and pack ice), the continually changing coastal shore, and construction/operation in a highly sensitive environment. Seasonal river outflows, subsea currents, and strudel scour may also introduce current induced vibrations and the potential for long subsea spans to develop. Further from shore but still in shallow waters, iceberg and multi-year ice scour potential is a primary driver for design. Minimizing pipeline risk by adopting a deep burial depth may be offset by extraordinarily high trenching costs during a very short construction season. In many cases, adopting a reliability-based approach to optimize burial depth is an effective means of accomplishing an acceptably low level of risk at minimum cost. In these analyses, consideration can also be given to pipeline design options such as pipe-in-pipe (PIP), heavy walled pipe, flexible pipe, and even pipe consisting of a steel pipe wrapped in high density polyethylene [4, 5]. Today, there is a surging interest in the development of arctic oil and gas reserves around the world. Renewed economic and technical feasibility assessments have been initiated for all aspects of development, including drilling, reservoir delineation, and eventual production and hydrocarbon transport. For arctic pipeline systems, improved material behaviour, advanced analytical techniques, wider acceptance of a strain-based design philosophy, and the gathering of historical operational and environmental data have allowed designers to implement an integrated reliability-based approach to the design and operation of an arctic pipeline system. The following sections describe in more detail the specific issues associated with arctic onshore and offshore pipelines, the support offered by testing and analyses, and the implementation of reliability-based design methodologies. 2 Copyright 2008 by ASME

3 OFFSHORE PIPELINE SYSTEMS In the 1970 s and 1980 s, high arctic oil discoveries in the Canadian arctic islands prompted the initiation of offshore pipeline construction studies, aimed at developing successful methods of laying offshore pipelines through the ice to the seafloor. More recently, the Northstar and Liberty pipelines offshore Alaska employed strain-based methodologies to offshore pipeline design. Aside from standard operating pressure containment, the unique loading conditions associated with the arctic suggested that traditional stress-based design would not be economically possible. To implement a reliability-based design methodology, environmental loading conditions and pipeline structural alternatives were investigated within the framework of a strain-based design approach. These investigations included engineering studies that were performed for the Northstar and Liberty pipeline systems, as well as other research studies undertaken at the time to support arctic offshore pipeline design [6,7,8]. Issues relating to design and construction, operation and maintenance, and repairs were assessed on the basis of risk, and a number of pipeline structural design alternatives were proposed for use, including single walled pipe, pipe-in-pipe, non-bonded flexible pipe, and a hybrid pipe consisting of a steel pipe inside an outer sleeve of high density polyethylene (HDPE). These design alternatives are shown in Figure 4 and, as mentioned above, have been the subject of a number of assessments aimed at determining the optimal alternative for arctic offshore pipeline design. required for other alternatives, but this extra trenching cost was offset by the simplicity (and lower cost) of using a traditional single wall concept. Primary loading conditions to be considered in arctic offshore pipeline design include the following: Internal pressure containment Ice gouging Upheaval buckling Permafrost thaw settlement and/or frost heave Strudel scour Internal pressure containment is normally considered using standard stress-based design approaches, and is not usually considered a design case that governs wall thickness. As a primary load, however, the influence of internal pressure on axial strain capacities must be assessed. Ice gouging, or scour, is perhaps the most significant environmental loading condition influencing offshore pipeline design. Figure 5 illustrates the action. It is normally accepted that the pipeline must be buried to deeper than the maximum gouge depth expected over the design life of the pipeline, due to the fact that the soil below the scouring keel will also deforms, imposing high shear and bending loads on the buried line. Research has been undertaken over the years to estimate what may be considered a safe burial depth [9, 10]. Upheaval buckling potential, caused by differences between installation and operating temperatures, may also influence burial depth. Figure 5 Ice Scour on an Offshore Pipeline Figure 4 Liberty Offshore Pipeline Alternatives Each design alternative offers advantages over the others, and will impact a number of cost-related issues. For example, a flexible pipe may be more resistant to corrosion, is lighter, can be installed quicker, but it is more expensive and more costly to repair. For a PIP system, installation time may be longer and the initial cost may be high, but the depth of cover can be less and the outer pipe offers secondary leak containment. Leak detection systems can be placed in the annulus of a PIP, as can insulation for flow assurance. The Northstar pipeline was constructed using a traditional single wall design on the basis of meeting an acceptably low risk of spill potential at the lowest cost. The pipeline needed to be buried to a greater depth than In general, the optimal depth is the shallowest depth that allows for the safe operation of the pipeline, and depends on the soil conditions existing along the pipeline route, the potential for upheaval buckling, and the maximum expected depth of ice gouging. Thus, determining the expected gouge depths along the pipeline route and modeling the pipe-soil interaction during ice gouging events are critical steps in the design process. In many instances, ice gouging is considered the most important loading condition for offshore pipeline design, but it is also considered the most uncertain in terms of predictability. Recent work has been directed towards understanding ice keel strength and probabilistically characterizing gouge depth, and ice keel penetration using seabed gouge survey data [11,12]. Work has also progressed towards improved modeling 3 Copyright 2008 by ASME

4 techniques of the gouging process [13] and integrating these data with historical seabed mapping data. This is an area of active research that aims at reducing the overall uncertainty associated with ice keel interactions with the seabed. Permafrost thaw settlement and frost heave potential are also important factors in offshore arctic pipeline design, and must be considered in the near-shore regions in which they may be present along the buried subsea pipeline route. Both conditions will impose long-term displacement controlled bending on the pipeline, and may contribute to pipeline strain limit utilization. Strudel scour occurs when seasonal river outflows precede sea ice cover thawing, resulting in water flowing on top of the sea ice. The flowing water may penetrate a depression or crack in the sea ice, causing a downward flowing erosion effect through the ice and jetting below to the pipeline. In some instances, strudel scour can be large and erode the seabed. Although strudel scour must be considered in pipeline design, its probability of occurrence at the location of a pipeline tends to be low, and ice scour burial depth requirements may already provide protection from this phenomenon Strain-based design has developed over recent years to facilitate realistic pipeline designs under these conditions, but there still remains a high degree of uncertainty regarding ice gouge, permafrost thaw, and frost heave displacements on offshore arctic pipelines. Assessing loading conditions and identifying appropriate compressive and tensile strain limits is currently being performed on a project-by-project basis. Operational and integrity management programs may also influence the ultimate design of arctic offshore pipeline systems, and integrating design, operation, and maintenance into an overall reliability design approach is ultimately desired. ONSHORE PIPELINE SYSTEMS The Norman Wells pipeline and the buried portions of the trans-alaska pipeline system provided good information relating to the impact of ground movements on pipeline integrity. The successful operation of these lines, coupled with recent technical advancements in strain-based pipeline design approaches, has prompted pipeline designers to consider burying arctic pipelines wherever possible. Since a buried pipeline is also preferred from an environmental point of view, this alternative has been the focus of recent Arctic pipeline projects in northern Canada and Alaska. A number of design options have also been considered for onshore arctic pipelines, including heavy-walled pipe, high strength pipe, heavily insulated pipe, and un-bonded flexible pipe [5]. The benefits of using high strength linepipe for arctic applications have been demonstrated in recent years [14], and research continues to progress into very high yield strengths of 100 and 120 ksi [15]. At present, single-walled, high grade steel linepipe is generally considered the preferred design option for long transmission lines. The key design issue for arctic onshore pipelines is the large deformations that could result from frost heave, thaw settlement and slope movements. In contrast to offshore lines that may cross short, near-shore sections of permafrost, the proposed Alaskan and Canadian onshore arctic lines will traverse very long distances across continuous and discontinuous permafrost zones. These regions may also contain soils with very high ice contents, increasing the potential for large pipeline deformations. It may be necessary to control soil deformations by a number of design/operational methods, including controlling product temperature, increasing the wall thickness, insulating, using thermo-siphons, varying the burial depth, and perhaps even removing and replacing large portions of soil around the pipeline route. In addition, because these soil deformations occur over long periods of time (years), it is important to monitor pipeline deformations and soil temperatures during operation, and this monitoring program should be considered during the design stage of the pipeline. DESIGN It has been widely recognized that elastic design methods are impractical for the potentially large ground movements associated with frost heave, thaw settlement, and ice gouging, and that a certain amount of plastic deformation must be anticipated and accepted. This is possible in the context of Arctic pipelines because, as mentioned above, the identified ground movements are a deformation controlled loading process. For onshore pipelines that are subject to thaw settlement or frost heave, the load carrying capacity of the pipeline will not result in an uncontrolled increase in deformation that leads ultimately to rupture and product release. Permafrost thaw and frost heave are ground movement processes that result in stable, controlled pipe deformations. However, to ensure that leaks or ruptures do not eventually occur under these stable ground movement conditions, pipeline deformations can be monitored to identify high deformation locations and appropriate action can be taken to ensure strains do not reach unacceptable levels. For offshore lines, ice gouging events are generally considered rare, but they can result in large soil displacements over very short periods of time. Design cases involving ice gouging require site specific information in order to assess the risk of event occurrence. Seabed gouge data, coupled with advanced modeling techniques will estimate the influence of soil deformations on pipe integrity. Burial depths are then adjusted, and further analyses are performed to ensure pipe strains are within accepted limits. Under these varying conditions of ground movement potential, a safe pipeline requires a combination of design and operational measures. It is also recognized that design and operational measures are not mutually exclusive, and the interacting combinations must be appropriately considered. The design process includes developing an understanding of the strains imposed on the pipe (strain demand) and the safe strain limits that the pipe can withstand without failure (strain capacity). Along with the throughput capacity and pressure profile, this information can be used to select an appropriate set of design parameters (diameter, wall thickness and grade). The operational issues involved include the selection of an appropriate monitoring strategy that defines the inspection method to be used, the frequency of inspection, the intervention criteria and the mitigation methods. The key design condition that must be met in selecting these design and maintenance parameters is that the strain capacity must exceed the strain demand with a sufficient safety margin throughout the lifetime of the pipeline. A brief discussion of some of the key technical issues needed to meet this condition is given in the following: 4 Copyright 2008 by ASME

5 Strain Demand Quantification of the strain demand side of the design condition requires a comprehensive understanding of the pipeline route to characterize such parameters as: proximity to river outflows that could initiate strudel scour; frequency of potential frozen / unfrozen interfaces; soil characteristics governing the potential for frost heave / thaw settlement and sub-gouge deformations (for example, soil type, soil gradation, moisture content, ground temperature and active zone depth); and frozen/unfrozen soil mechanical properties. In addition, geothermal models are required to determine the potential freeze/thaw deformations caused by changes in the thermal regime as the buried pipeline is operated at a certain temperature gradient. A pipe-soil interaction model is then required to calculate pipe strains. For frost heave, the ground deformation is dependent on the pipe response, causing the geothermal and pipe-soil interaction models to be coupled. Although models exist to analyze this problem, these models are quite complex. For offshore pipelines, ground deformation is also dependent on ice keel/seafloor interactions, adding further complexity to the required modeling. Another issue that relates to strain demand estimation is the effect of differences between the wall thicknesses and mechanical properties of adjacent pipe joints. The weaker and/or thinner joint will attract higher strains causing the strain demand to be amplified around the girth weld and requiring an appropriate correction for analysis results that typically assume identical pipe joint properties. Tensile and Compressive Strain Capacity Since tolerance to axial strain is not a significant issue for most conventional pipelines (which are only subject to axial loads in limited isolated sections), established models to determined strain capacity levels are not available and this remains an area of active research [16,17,18]. At this point in time, strain limits are established on a project-by-project basis through extensive analyses and testing. Compressive strain capacity is typically determined through bending tests and FEA (Figure 6). It is dependent on the D/T ratio, internal pressure and post-yield material behaviour. The approach used is to carry out a limited number of full scale tests and use them to calibrate a finite element model. The model is then used to generate solutions for sufficient cases that cover the relevant range of expected input parameters. The test data and finite element results can be used to generate simplified empirical models and to characterize the error associated with these models. Tensile strain capacity, normally governed by the strain capacity of the girth weld region, has typically been determined through a combination of curved wide-plate tests (Figure 7) and FEA or semi-empirical models. These models are typically based on attempts to modify fracture assessment criteria in the form of failure assessment diagrams [19]; and they often lead to highly conservative criteria with large uncertainties. These diagrams imply the presence of a plastic collapse load and, if the pipeline stress strain response is relatively flat in the plastic region, are not representative of strain capacities. Tensile strain-based design procedures have been the subject of active research in recent years, aimed at relating girth weld region crack driving forces to nominal pipeline strain levels [18]. This approach, which assumes that the tensile limit state is attained when the crack driving force reaches the toughness of the material, appears to demonstrate good predictability, and has been accepted for use in the Canadian pipeline standard [20]. The approach considers material properties, toughness, and defect geometry for calculation of tensile strain limits. Curved wide plate tests are also performed to determine the strain capacity and to validate the above-mentioned models. Figure 6 Bend Testing and FEA at C-FER Figure 7 Curved Wide Plate Tests 5 Copyright 2008 by ASME

6 Recent work has demonstrated that curved wide plate tests are not completely representative of the tensile strain capacity of pipe in a bi-axial state of stress (i.e. under internal pressure), and this has led to a number of projects aimed at investigating and accounting for this effect (e.g. the on-going joint industry program sponsored by Pipeline Hazardous Material Safety Administration, PHMSA, the Pipeline Research Council International, PRCI, and a number of operating companies). Tensile strain limits are also dependent on weld defect size and this makes it necessary to consider welding methods and flaw acceptance criteria as an integral part of the design process. Tensile strain capacity, in general, is most influenced by defect size, material toughness and weld strength mismatch with the parent pipeline material. Material Specifications Strain capacity is dependent on the shape of the stress strain relationship immediately past the yield point. The required material behaviour is therefore not fully captured by the material yield strength or by the yield-to-tensile ratio. In addition, the capacity is dependent on both the tensile and compressive properties in the axial direction, and the tensile properties in the circumferential direction. Thermal treatments from the coating process may also alter the shape of the stress strain curve and the resulting strain capacity [21]. Ideally, the shape of the stress strain curves in axial tension, axial compression and hoop tension need to be controlled. Practically, however, it is necessary to define a limited number of discrete material properties that can be reasonably specified, achieved by the pipe mills and verified during construction. This poses a significant challenge that needs to be addressed through a cooperative effort involving both pipeline owners, steel manufacturers and pipe mills. Monitoring In Line Inspection (ILI) using geometry tools is generally recognized as the main method of monitoring for ground deformations. The tools provide curvatures averaged over a finite length that depends on the length of the tool. Estimation of the tensile and compressive strains from inspection data involves a number of uncertainties. In addition to random error, a correction needs to be made to account for the fact that the curvatures provided represent an averaged value that can miss local strain peaks within the averaging distance. More importantly, the curvature data obtained from ILI do not account for axial strains. Approaches to correct for these errors and account for the associated uncertainties are required. In addition, a baseline curvature profile needs to be established immediately after construction in order to ensure that strains induced during pipeline construction are not treated as ground movement- induced. The monitoring process is also likely to incorporate site analyses for high-strain locations that are identified using ILI data. This process may involve collecting site-specific data and running site-specific analyses. To set appropriate criteria for intervention, the potential errors associated with these site-specific analyses need to be understood and characterized as well. Monitoring should also include a means of detecting leaks and, for offshore lines, the presence of hydrocarbons in the sea or in the sea ice must also be an integral part of the monitoring program. Research has progressed in this area to address high uncertainties regarding monitoring techniques [22,23], but more is needed to reliably assess the full impact and cost of leaks/ruptures in an arctic environment. RELIABILITY-BASED DESIGN FRAMEWORK Because of the significant uncertainties associated with the inputs and models used in the design process, it is suggested that reliability-based design methods provide the most rational approach. Implementing a reliability-based approach requires the characterization and probabilistic modeling of all input parameters that are subject to significant uncertainty. It also requires that the complex geothermal/structural models used be reduced to a simplified format that is amenable to being used within a probabilistic model. In addition, the reliability analysis in this case is time-dependent because ground movement strains change with time and are influenced by the on-going monitoring and maintenance activities forming part of the design/operational philosophy. Reliability-based design and assessment is an iterative process to search for a cost-effective set of design and operational parameters that meet a set of target reliability levels for all applicable limit states. Figure 8 shows the basic steps involved in the process, and the main inputs required for each step. The first three steps compile the models and data required to calculate reliability, by identifying the relevant limit states, formulating a limit state functions for each, and selecting appropriate probabilistic models for the corresponding basic random variables. Route Data and Loading Conditions Deterministic Behaviour Models Statistical Data Operational Parameters and Regulations Probability Calculation Method Target Reliability Levels Identify Relevant Limit States Develop Limit State Functions Develop Probabilistic Models of Basic Variables Select Design Parameters and Maintenance Plan Calculate Reliability Reliability Target met? Yes Economic Criteria met? Yes Acceptable Design Figure 8 Reliability-based Design Process No No 6 Copyright 2008 by ASME

7 The design process, which has been adopted as a nonmandatory Annex in the CSA Z662 pipeline standard [20], begins by selecting an initial set of design and maintenance parameters. All parameters that are required to calculate lifetime reliability must be defined at this stage. These include basic design parameters, such as steel grade and wall thickness. For Arctic pipelines, they also include manufacturing and construction parameters such as material testing and weld inspection procedures and inspection/maintenance criteria such as in-line inspection frequency and strain thresholds for intervention. Reliability is calculated as a function of time and compared to the target values. Solutions that meet the target reliability levels are subjected to an economic assessment to ensure that the safety criteria are met at a reasonable cost. Viable solutions are compared on an iterative basis until a costeffective solution that meets the target reliability levels is found. Reliability-based design addresses the true structural behaviour of the pipeline by identifying the true failure modes and producing designs that mitigate the actual consequences of these failures. This avoids unrealistic design criteria that lead to unduly conservative designs. It results in consistent safety levels because the target reliability levels are linked to the seriousness of each failure mode. For example, a higher reliability target would typically be required for a tensile rupture than for a stable local buckling failure. This ensures that conservatism is placed where it is most needed, leading to minimum cost designs for a given level of overall safety. Another benefit of the methodology is the integration of design and operational decisions. Since reliability is a function of both design and operational parameters, reliability gains due to inservice maintenance activities can be incorporated at the design stage, resulting in potential reductions in capital expenditures. Finally, the reliability-based approach is highly adaptable to new problems because it is based on analyzing the design issues from first principles and does not rely on empirical evidence collected through trial and error. SUMMARY This paper has provided a brief history of pipeline developments in the North American Arctic, including some of the design issues and methods of mitigating the environmental effects most significantly influencing pipeline structural integrity. These early developments have provided valuable data from which current design approaches have benefited. The primary issues of present-day concern for both onshore and offshore arctic pipeline design issues have been summarized, including some of the research currently underway to address the large uncertainties associated with ice scour and permafrost thaw subsidence / frost heave. Analytical and experimental advancements in pipeline strain demand and capacity, coupled with environmental concerns, have prompted designers today to consider burying onshore lines wherever possible. For offshore lines, similar advancements in seabed mapping and analytical capabilities have provided a rational means of assessing ice gouge potential. Although technical advancements are continuing in our understanding of tensile and compressive strain limits, strain-based design approaches have been shown to be the preferred method. Design limits are normally determined on a project-by-project basis, taking account of site specific conditions such as the presence of ice bergs, permafrost and soil conditions along the route. Considering pipeline maintenance activities at the design stage offers several advantages that have been identified in this paper, allowing for the implementation of a rational means of assessing system risk over the life of the pipeline. A summary of a reliability-based framework has been provided within the context of pipeline design ad maintenance, including the explicit assessment of maintenance activities at the design stage, offering a cost-effective approach to design and maintenance. Arctic pipeline design and operation practices are evolving towards a reliability-based design approach. The unique loads associated with the arctic, the extreme sensitivity of the environment, the adaptability of reliability-based design to incorporate specific design and operational cases, and the ability to consider maintenance activities at the design stage, offers an optimal means of achieving an acceptable level of risk over the lifetime of an arctic pipeline. REFERENCES [1] Bone, R. M Norman Wells: The Oil Center of the Northwest Territories. ARCTIC, Vol. 37, No. 1, March, pp [2] Wilkie, S., Doblanko, R. and Fladager, S Northern Canadian Pipeline Deals With Effects of Soil Movement. Oil & Gas Journal, May 14, pp [3] Oswell, J., Hanna, A., Doblanko, R. and Wilkie, S Instrumentation Yields Geotechnical Picture of Slope Movements Along Northern Canadian Pipeline. Oil & Gas Journal, May 21, pp [4] McBeth, R An Overview of Pipeline Configuration Alternatives. Presentation at the Alaskan Arctic Pipeline Workshop, Minerals Management Service, Anchorage, November. 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8 [11] Stepanov, I Can Seabed Gouge Survey Data Be Applied to Prediction of Maximum Depths of Ice Keel Penetration? Proceedings of the 2 nd Ice Scour & Arctic Marine Pipelines Workshop, Mombetsu, Japan, February, pp [12] Palmer, A Geotechnical Evidence of Ice Scour As A Guide to Pipeline Burial Depth. Canadian Geotechnical Journal, vol 34, pp [13] Konuk, I., Yu, S. and Fredj, A Do Winkler Models Work: A Case Study For Ice Scour Problem. Proceedings of the 25 th Conference on Offshore Mechanics and Arctic engineering, OMAE , Hamburg, June. [14] Corbett, K., Bowen, R. and Petersen, C High Strength Steel Pipeline Economics. Proceedings of the 13 th International Offshore and Polar Engineering Conference, Hawaii, May, pp [15] Papka, S., Stevens, J., Macia, M., Fairchild, D. and Petersen, C Full-size Testing and Analysis of X120 Linepipe. International Journal of Offshore and Polar Engineering, Vol. 14, No. 1, March. [16] Zimmerman, T., Timms, C., Xie, J. and Asante, J Buckling Resistance of Large Diameter Spiral Welded Linepipe. Proceedings of the International Pipeline Conference, IPC , Calgary, October. [17] Dorey, A., Murray, D. and Cheng, R Critical Buckling Strain Equations for Energy Pipelines - Parametric Study. Journal of Offshore Mechanics and Arctic Engineering, Vol. 128, No. 3, August, pp [18] Wang, Y-Y., Liu, M., Rudland, D. and Horsley, D Strain Based Design of High Strength Pipelines. Proceedings of the 17 th International Offshore and Polar Engineering Conference, Lisbon, July, pp [19] BS Guide on Methods for Assessing the Acceptability of Flaws in Metallic Structures, British Standards Institute. [20] CSA Z Oil and Gas Pipeline Systems. Canadian Standards Association, 5 th ed., June. [21] Timms, C., DeGeer, D. and McLamb, M Effects of a Thermal Coating Process on X100 UOE Line Pipe. Proceedings of the 24 th International Conference on Offshore Mechanics and Arctic Engineering, OMAE , Halkidiki, Greece, June. [22] Scott, S. and Barrufet, M Worldwide Assessment of Industry Leak Detection Capabilities for Single & Multiphase Pipelines. Minerals Management Service Report CA-31003, August. [23] Dickens, D New and Innovative Equipment and Technologies for the Remote Sensing and Surveillance of Oil In and Under Ice. Minerals Management Service Report , March. 8 Copyright 2008 by ASME