This paper presents the results of the testing of an oil-on-water leak detection technology for isolated locations without power or communications infrastructure. A special attention was paid to the ability of the sensors to detect hydrocarbon leaks under freezing conditions, with thick ice formed on the surface of the water. A viable solution for remote locations and large water crossings needs ultra low-power solution and/or cyclic operation. The technology evaluated was a fully passive impedance polymer-absorption sensor (PAS) featuring “zero-power” consumption. This technology also provides an additional advantage, “an event memory”, and is perfectly suitable for cyclic operation for detecting moving oil stains. In October 2017 three polymer-absorption sensors of different lengths were placed in outdoor location in Ontario, Canada for long-term testing of reliability in freezing conditions. The sensors were connected to cellular modem for generating alerts. Another battery of three sensors of same lengths was installed in outdoor testing facility near Ottawa, ON, Canada and connected to real-time data acquisition equipment. A preliminary series of leak tests performed in October/November 2017 confirmed the initial assumptions of excellent sensitivity of the hydrocarbon oil-on-water detection based on polymer absorption. The average power consumption of the sensor excitation and its measurement frontend during the first two months of testing were found to be extremely low, a fraction of the power needed for the wireless modem itself. The leak tests were extended to oil under ice detection performed with 5 North-American crude oils and with 3 refined products from Mid-December 2017 to Mid-February 2018. The sensitivity, the sensor excitation/measurement front end power consumption, and the reliability of the sensors were assessed at freezing temperatures, with thickness of the ice comprised between 80 and 100 mm. The paper also presents the availability of stand-alone communication equipment suitable for integrating oil-on-water sensors, as well the energy harvesting or energy storage technologies for different climatic conditions.

In order to meet the increasing worldwide energy demand, there is a need to economically develop remote oil and gas resources. Construction of pipelines is required to connect these resource locations to markets. Such pipeline routes may cross areas of large ground motions such as regions of active seismicity, discontinuous permafrost, and offshore ice gouging. All of these features can subject pipelines to significant longitudinal strains. For these conditions a strain-based design (SBD) approach may be required to maintain pipeline integrity. Welding technology is a key component of pipeline construction. Significant pipeline construction cost savings are enabled with the use of higher strength steels (X80+). Higher strengths enable reduced pipe wall thicknesses, which reduces both weight and girth welding time. However, robust welding technology for high strength SBD pipelines remains challenging. Such applications demand welds with both high strength (>120ksi) and low temperature (−15°C) toughness, combinations that are at the limits of, or beyond, existing commercial technology. This paper discusses the development of an enabling welding technology which offers a superior combination of strength and toughness properties. An iron-nickel (FeNi) martensitic weld metal with a refined mixed cellular microstructure has been developed as a promising high strength weld metal that can be applied for field pipeline construction. This paper describes how this technology has been applied to create welds for X80 strain-based pipelines requiring significant weld strength overmatch and superior ductile tearing resistance. The welding technology can also be applied to X70 grade strain-based pipelines where high toughness is required. This approach has been developed for mainline girth, tie-in girth, and girth repair welding scenarios. Welding procedures are discussed and examples of the mechanical properties achieved and calculated strain capacities are described.

Multiphase transportation is widely used as the oilfield development moving into deepwater. Temperatures will have a drop when multiphase flow from normal region to cold region in the subsea pipelines or experience Joule-Thomson cooling in choke valves. The unexpected temperature drop can lead to viscosity increase and ice suspensions formation, and even ice blockage. In this study, viscosity variation of ice suspensions formed from water-in-oil emulsions was measured. Viscosity started to increase when ice suspension was forming. The experimental results showed that viscosity increased firstly until a maximum value upon ice formation and then decrease to a stable value in the process of ice suspension formed from w/o emulsion. So the critical viscosity included a maximum value and a stable value. The effects of temperature (subcooling) and shear rates on viscosity variation were investigated. Experimental results indicated that ice suspension viscosity increased faster with lower temperature (larger subcooling) and stronger shear disturbance. Heat transfer was a principle factor that determined viscosity increase in the process of ice suspensions formation. Therefore, good insulation of subsea pipelines is required to avoid ice blockage when emulsion flow from normal region to cold region.

Safety is central to the prosperity of the pipeline industry and the need to maintain high standards of the saftey at all times is of paramount importance and therefore, it is a primary concern of pipeline operator, adquate supervision and controlling the operation of pipelines as will as clearly defined codes of pract-ice, standards and maintenance schedules are necessary if protection is to be afforded to the pipeline system, employees, the puplic at large and enviroment.

BP Exploration (Alaska) Inc. is presently developing the Northstar oilfield, 9.7 km offshore the Alaskan Beaufort Sea coast. Northstar drilling and production facilities will be located at Seal Island and the project includes constructing the first subsea oil production pipeline in the Arctic. The twin 273.1 mm (10-inch) offshore and overland oil and gas pipeline systems are described along with major aspects of the design. A limit state design procedure for pipe bending is employed to safely and efficiently address the principal marine environmental loadings caused by seabed ice gouging and permafrost thaw settlement.

The microstructure of soils (the arrangement of pores and voids, aggregation and surface characteristics of particles) is substantially modified by freezing. Soils so modified differ, in a number of important properties, from soils not previously frozen. Furthermore, each time a soil is frozen there is a redistribution of particles, moisture and solutes. Corrosion of buried pipes is known to be related to the ground conditions. Accordingly the particular nature of frozen ground needs consideration in this respect. Studies of microstructure of samples of freezing, frozen and unfrozen soils, many obtained from a full-scale experimental study of the effects of freezing on a buried pipeline, have provided an explanation for measured changes in bulk geotechnical properties of the materials. The microstructure viewed by optical microscopy, reveals the soil structure as having a complex and striking dependence on freezing history. Scanning electron microscopy shows further details in clay rich soils. Freezing at temperatures occurring in nature normally does not convert all the soil water to ice. The effects of particle surface forces is to reduce the freezing point of the water nearest a mineral surface. The distribution of solutes is radically altered, with pockets of high concentration interconnected by a liquid phase of varying concentration. A variety of other effects, relating to chemical and mechanical properties of soils subjected to freezing, have been demonstrated or can be postulated. Some of these are important in corrosion phenomena. The stresses that have been shown to occur in a pipe as a result of frost heave in the freezing soil, will also tend to increase the possibility of stress corrosion cracking.

To meet the increasing worldwide demand for natural gas, there is a need to safely and economically develop remotely located resources. Pipeline construction is a major activity required to connect these remote resources to markets. Such pipeline routes may cross areas containing geohazards such as discontinuous permafrost, active seismicity and offshore ice gouging. These pipelines may be subjected to longitudinal strains above 0.5%. To safely design pipelines for such conditions, a strain-based design (SBD) approach can be used in addition to conventional allowable stress designs (ASD). Significant pipeline construction cost savings can be achieved with the use of higher strength steels (X70+) due to reduced pipe wall thicknesses (less steel) and faster girth welding. However, a robust welding technology for higher strength SBD pipelines is often a technology gap depending on the target level of longitudinal strain that needs to be accommodated, since such applications often demand excellent weld toughness at low temperatures (−15°C) and high tensile strength (>120ksi). This paper discusses the development of an enabling welding technology that offers a superior combination of strength and toughness compared to commercially available technologies. Acicular ferrite interspersed in martensite (AFIM) has been previously identified as a useful high strength weld metal microstructure that can be applied in field pipeline construction. This paper describes how this microstructure has been used to create welds with excellent strength overmatch and good ductile tearing resistance for X80 SBD pipelines. This approach has been implemented for mainline, double-joining and repair welding applications. This paper describes the welding procedures, mechanical properties achieved, estimated strain capacities, and the results of a full-scale pipe strain capacity test.

Onshore and offshore pipelines may be subjected to mechanical damage during installation and operation due to environmental loads, external forces and third party interference. Pipelines in offshore environment may be prone to mechanical damage from events such as ice gouging, frost heave, and seismic fault movement. For conventional pipelines, the assessment of mechanical damage plays an important role in the development of integrity management programs that may be of greater significance for pipeline systems located in remote harsh environments and that are more prone to anchor drag, seismic loading and ice gouging. This study examines the effect of dents and corrosion loss on pipe mechanical response using continuum finite element methods. ABAQUS/Standard (6.10-1) environment was used to simulate damage events and pipe response. Modelling procedures developed and calibrated against physical and numerical data sets available in public domain were reported previously in Hanif & Kenny 2012, 2013. Once confidence in numerical procedures was established, an analysis model matrix was established to account for a range of influential parameters including pipe/indenter geometry and pressure factor. A nonlinear multivariate regression analysis was conducted to develop strain based empirical tools that characterize the effects of local damage and applied loads on pipeline mechanical response for unconstrained dent conditions. Coupled affect of dent and artificial corrosion loss (in terms of wall thickness reduction in the damage zone) was also analyzed and a sensitivity study was conducted to see the effect of percentage wall loss on pipe response. Finally, operational parameters were varied and resulting stress concentration factors were calculated, that took into account indentations and wall loss, to predict fatigue life of dented pipe segments for both constrained and unconstrained dent conditions.

The Pipeline Ice Risk Assessment & Mitigation JIP (PIRAM) developed a set of engineering models and design procedures for implementation into industry best practices for risk mitigation and protection of pipeline infrastructure from ice keel loading. The models established the pipeline mechanical behaviour in response to ice keel load events, and assessed engineering concepts for protection and risk mitigation strategies. Improved methodologies for contact frequency and ice keel loads determination formed part of the integrated model. This paper presents an overview of this multiyear program and examples of the application of the models in pipeline burial depth assessment in pressure ridge ice gouged seabeds.

In the spring of 2009, the Red River of North Dakota flooded six feet deep and ten miles wide in Pembina County. The flood was followed by arctic temperatures that froze the floodwaters 8-inches thick and also froze around the stems of seven isolation valves. These isolation valves were for pipelines carrying crude oil and natural gas liquid (NGL). The pipeline sizes varied from 36-inch to 18-inch diameters. The ice around the valves was subjected to wind forces of 50 mph putting the valves at risk. Also, when the second spring runoff came, the river current pulled ice down through the valley. This ice flow took out trees, power poles, and damaged a couple of isolation valves. The damage was minimal, but could have been worse. No leaks occurred. This paper will explore the unique problems associated with protecting the valves and delve into keys and principles that led to an innovative solution. Technical issues will be discussed that will help future projects solve problems on how to protect equipment from ice flows. The underlying soils were known for their excessive settlements and low shear strength. The soil was predicted to settle 6-inches after adding eleven feet of fill for protective berms. The preliminary pipe stress calculations based on the predicted settlement of 6-inches put the allowable pipe stress near the limits of acceptability. The valve site was also located miles from the nearest road. The forces from the ice loads in a river can be enormous and engineering judgment had to be used to obtain a practical solution.

The need to use strain-based design is growing due to potential pipeline projects in environments that include permafrost, offshore ice hazards, active seismic areas and high temperature/high pressure operations. Proper design and construction of such pipelines poses numerous special challenges and requires consideration of some important processes that govern the behavior of soils. ExxonMobil has been conducting research to improve understanding of geotechnical mechanisms that result in large plastic strains in the pipelines, and to develop pipeline strain demand prediction methodologies in harsh arctic and seismically active regions. This paper discusses key challenges in strain demand estimates for Arctic onshore and offshore pipelines and is aimed at promoting industry discussion of strain demand prediction methodologies. The paper highlights ExxonMobil’s efforts in developing predictive technologies for strain demand estimation that forms the basis for the design, testing, and model development in strain-based pipeline applications.

The importance of using strain-based design pipelines is growing due to the increasing number of projects in challenging environments such as permafrost, offshore ice hazards, active seismic areas, and in high temperature/high pressure operations. To ensure pipeline integrity in environmentally sensitive areas and overall cost effectiveness, a strain-based design approach needs to consider all key interrelated design aspects including strain demand, design methods, material selection, strain capacity validation, and impact on construction and operation. To that end, significant research and development efforts have been made by the industry to facilitate the qualification of strain-based designed pipelines. This paper describes methods developed for the qualification of strain-based design pipelines, and demonstrates how recently developed strain capacity prediction tools, calibrated by full scale testing, can facilitate concept selection, material qualification and integrity verification of such pipelines.

A subscour soil displacement model is a key component to determine the safe burial depth of offshore pipelines in ice scoured environments. In order to calibrate numerical models and physical tests carried out in geotechnical centrifuges, 3D ice scour tests were carried out in a dredging flume at a scale approaching that of observed scour depths in the Caspian sea. Two soil failure mechanisms were observed. For steep keels, the soil is mainly pushed up into a mound in front of the keel. For shallow angle keels most of the scoured soil is forced under the keel and to the side of the indentor. Each mechanism results in a different subscour displacement pattern. Subscour displacement equations that include the effect of soil properties and keel angle are presented. While these equations are considered an improvement on existing sub-scour models, there remain limitations to their application in 3D sub-scour until further information relating scour depth and width to soil strength becomes available.

Assessment and development of pipeline projects in northern Canada, such as the proposed Mackenzie Valley gas pipeline (MGP), are hampered by a lack of baseline terrain geoscience information including drift thickness, sediment type, presence of massive ground ice, and the availability of granular aggregate resources. Clearly there is a need by Industry, Regulators, Aboriginal groups, and others, to understand the nature and character of near-surface earth materials, in order that pipeline proposals can be properly developed, evaluated, and when approved, proceed with the greatest degree of environmental sustainability and economic efficiency. While numerous field-based reports and surficial geology maps have been prepared for the MGP, there are long stretches along the proposed route for which little near-surface geoscience information is available. This is even more apt for areas outside the defined MGP corridor, where the likelihood of tie-in and gathering pipeline systems exist. Drillers’ logs, recorded during auger drilling of seismic shotholes, represent a virtually untapped resource of regional baseline geoscience information. The Geological Survey of Canada recently produced a digital archive of 76,000 shothole records from the Northwest Territories and Yukon, which had originally been collected on file cards in response to the 1970’s MGP proposal. Released in 2007 as a freely downloadable Open File report (#5465), the archive provides users with an Access database of drillers’ logs and derivative GIS maps in which shapefiles of drift isopach thickness, potential granular aggregate resources, geohazards, permafrost and ground ice occurrences, and muskeg thickness can be opened, viewed, and queried, or otherwise incorporated into GIS platforms of the user’s choice. Realizing the amount of additional archival shothole information held by Industry, and the great utility of bringing this forth in a public database and derivative GIS, a subsequent project has focused on capturing and integrating additional data. Receiving near-universal support by the Petroleum Industry, a Version 2 of the database and GIS is currently being assembled, and is scheduled for release in 2009 with some quarter million individual shothole drillers’ records. This presentation highlights the nature, character and distribution of shothole drillers’ logs in northern Canada. It also reviews the derived GIS layers, and how this baseline geoscience information can be beneficially utilized by the Pipeline and related infrastructure development industries, particularly as it may apply to focusing future field studies. It also serves as a key reference tool for those assessing pipeline development proposals.

In many of the major oil and gas fields in the North American Arctic, gravel is abundant and close to the production fields and the pipeline routes. In many other Arctic areas in Europe and Asia, gravel is almost non-existent. As new fields are being developed, gravel free areas are being encountered in more areas such as the National Petroleum Reserve Alaska (NPRA) and many of the Russian oil fields west and east of the Ural Mountains and into the Yamal Peninsula. Without free draining gravel, access and development of these new fields becomes more costly, more schedule sensitive, and more complicated. This paper looks at options for roads, pads, and access for developing the oil fields and building and operating the pipelines in areas where gravel deposits are sparse. Some of the options that are discussed and evaluated are using: 1. Additives to increase the strength of available fine-grained materials. 2. Ice and snow pads and roads. 3. Seasonal scheduling of construction. 4. Various road and pad surfacing options including: a) Year-around ice pads, b) Concrete pads and pavements, and c) Mats constructed of various materials. 5. Dredging and draining to obtain available sandy materials from waterways. 6. Geofabrics to contain ice rich materials placed in winter. 7. Methods for maintaining the thermal state of winter placed embankment.

Proposed development of a gas pipeline southward from the Mackenzie Delta and the presence of known accumulations of gas and oil in the southern Beaufort Sea suggest that construction of pipelines and associated infrastructure in the nearshore are likely to be proposed in the future. Recent surveys undertaken by Natural Resources Canada and its partners have focused on the shallow, poorly mapped nearshore region of the Mackenzie Delta (<6 m water depth) that extends ∼50 km offshore and lies largely within the landfast ice zone. Ice-keel scouring, strudel scour and nearsurface ice-bonding are being investigated. High resolution sidescan sonar and multibeam bathymetry systems were used to map the seabed over three consecutive years and show that ice keel scouring of the seabed is extensive. The maximum scour depth measured was 0.6 m in 6 m water depth with an average scour depth of 0.2 m. The same scours were visible in repeat surveys indicating that sedimentation was sufficiently low during the study, so that the scours were not infilled. Strudel drainage and associated seabed scour occurs when spring-melt river water overflows onto the surface of the landfast and bottomfast ice once discharge exceeds under-ice channel capacity, then drains back through the floating landfast ice via cracks and holes. Although common offshore of small deltas on the Alaska and Yukon coast, these features were first documented in the Mackenzie Delta area during field surveys in 2006 and 2007 that revealed strudel drainage (radial drainage patterns) features on the ice surface. A total of three strudel scours were later identified using swath-survey equipment in 1.2 m of water. The largest scour was 20 m wide with a maximum depth of 0.8 m below the surrounding seabed. Extensive surveys in Alaska have identified strudel scours exceeding 3 m below the seabed. Nearsurface ice-bonding and permafrost are known to occur in shallow water where sea ice freezes to the seabed. A combination of Synthetic Aperture Radar (SAR), ground penetrating radar (GPR) and multi-year ground temperature measurements have been used to map the horizontal and vertical extent of nearsurface ice bonding in extensive shoals found off the front of the Mackenzie Delta. In the shallowest water depths permafrost extends to 22 m below the seabed with an active layer of less than 1.2 m. In deeper water, permafrost disappears but seasonal frost can form in the upper 2–3 m of the seabed.

BP Exploration (Alaska) Inc. completed the installation of the first subsea Arctic oil production pipeline in April 2000 for the Northstar Development Project. The drilling and production facilities are located at Seal Island, approximately 10 km offshore of the Alaskan Beaufort Sea coast. Twin 273.1 mm (10-inch) oil and gas pipeline systems run approximately 10 km from Seal Island, through a lagoon area, to a shore crossing, and then overland for approximately 18 km. The unique aspects of this design included the pipeline environmental loadings, geotechnical considerations, and the use of limit state design procedures for extreme loading conditions. Environmental loadings and geotechnical conditions (in-situ and backfill) along the pipeline route were a major factor in the design of the offshore portion of the pipelines. Data collection of environmental conditions (e.g. ice gouging and strudel scour) and proper evaluation of the same were required to provide appropriate design data. Comprehensive field and laboratory programs were undertaken to generate the necessary geotechnical data for design. The evaluation of and design for unique Arctic environmental loading conditions including ice gouging, offshore permafrost, upheaval buckling, and strudel scour are described. Trenching and backfilling aspects of the pipeline design are also discussed. The paper closes with a general overview of the pipeline operations since the start of oil production in November 2001.

The Northstar project is the first crude oil production facility constructed offshore in the Beaufort Sea. Produced crude oil is transferred via a buried subsea pipeline to shore and overland to the Trans Alaska Pipeline Pump Station PS1 facility. During the permitting process, concern was expressed that a very small chronic leak in the subsea oil line would remain undetected during the winter months of continuous ice cover. Therefore, the US Army Corps of Engineers stipulated that a prototype leak detection system be installed that would capable of detecting a threshold leak less than 32 BOPD. This paper addresses the efforts to develop and install the LEOS leak detection system for arctic operations. The system is based on the well-established LEOS leak detection technology (manufactured by Framatome ANP, formerly by Siemens AG). The system comprises a perforated plastic tube with a thin water impermeable acetate outer sheath that allows hydrocarbon molecules to diffuse into the air filled tube. The air inside the tube is replaced periodically (every 24 hours) and is passed through a hydrocarbon-sensing module. The module contains resistors sensitive to the presence of very small concentrations of hydrocarbon molecules. The presence and location of a leak is determined by measuring the time taken for the localized concentration of hydrocarbon molecules associated with a leak to reach the end of the tube. LEOS components and materials were engineered to survive installation during arctic winter conditions. It was also necessary to protect the plastic LEOS sensor tube as it was lowered through the ice, attached to the pipeline, into a pre-excavated trench and then backfilled. The 10km long LEOS tube was delivered to site in 31-coiled 300m (1000-ft) bundles that were transported from Germany to Alaska. The LEOS sensing tube was preinstalled in a protective outer polyethylene tube which was unreeled through a reverse bending jig. Crude oil production started at the Northstar production facility in October 2001 and the LEOS system has been operational since then and is providing the highest degree of assurance that no oil is escaping from the pipeline.

Geophysical surveys map variations in physical properties of subsurface materials, many of which can have a direct impact on pipeline design and construction. This paper provides an overview of complementary geophysical methods available in the geophysical toolbox and shows, through the use of case histories, examples of the applicability of the methods for specific pipeline design and construction scenarios. In the context of pipeline design and construction, the objectives of a geophysical survey typically include one or more of the following applications: • muskeg mapping (thickness, lateral extent); • permafrost delineation (variations in ice content, frozen/unfrozen boundaries); • depth to bedrock; • rippability of bedrock; • soil type delineation (corrosion protection, granular inventories); • subsurface conditions at water crossings for horizontal directional drill planning using detailed investigations (boulder horizons, abandoned workings, depth to bedrock). To successfully address these objectives, it is often necessary to utilize more than one geophysical technique. Geophysical methods commonly employed in pipeline investigations include the following: • seismic refraction (marine and land based); • seismic reflection (marine and land based); • electromagnetics; • electrical imaging; • ground penetrating radar (marine and land based); • sonar. The fullest utility of geophysical information is achieved when combined with complementary approaches to provide the end-user with a value-added, cost effective approach. These other method include: airphoto interpretation, satellite imagery, and drilling. The incorporation of auxiliary data sets results in geophysical sections that provide a means of interpolating subsurface conditions between drill holes and reducing the risk associated with encountering surprises. These sections can also be used to provide for more accurate cost estimates by their inclusion in bid documents while at the same time ensuring a better data base for pipeline design. In addition to the advantages of using a geophysical toolbox, the ramifications of the pitfalls of geophysical approaches will also be discussed through the use of case histories illustrating situations in which an inappropriate geophysical technique was applied.

Renewed interest in offshore arctic oil and gas has led to the need for pipeline designs able to minimize environmental risk. A risk evaluation was conducted to assess the relative merits of pipeline concept designs for the Liberty Pipeline, which is intended to carry oil from BP/Amoco’s Liberty site to onshore Alaska. The Liberty site is inshore of the Barrier Islands in the Alaskan Beaufort Sea, in 22 feet of water. The offshore portion of the pipeline is 6.12 miles long. Risk was defined as the oil volume expected to be spilled over the 20-year life of the Liberty Pipeline. Risks due to ice gouging, strudel scour, permafrost thaw subsidence, thermal loads leading to upheaval buckling, corrosion, third party activities, and operational failures were evaluated. Failure probabilities were assessed based on analyses of the pipeline’s response and failure criteria that were established. A consequence model was set up to quantify the oil volume released during a pipeline failure, considering the mode and location of failure as well as leak detection systems. The risk was evaluated by summing the product of event probability and consequence for each hazard. The relative risk is discussed for each pipeline design.