Stress Corrosion Cracking (SCC) is a time dependent mechanism. Three conditions are required at the same location for the formation of SCC namely, susceptible material, susceptible environment and sufficient stress. Pipe age, operating stress level and coating type are significant parameters in determining the susceptibility to near-neutral pH SCC; whereas, additional parameters such as operating temperature and distance from compressor station are considered for high pH SCC. Environmental conditions such as soil type, topography and drainage have also shown correlation to SCC susceptibility. Several integrity assessment methods can be used to identify SCC on pipeline including hydrostatic testing, in-line inspection (ILI), and direct assessment (DA). Because the occurrence of SCC is a complex phenomenon and it depends on many parameters, it is important to develop a risk assessment model that can systematically incorporate all relevant evidences of SCC in a sensible way. This paper presents a robust risk assessment model for SCC, which uses evidence from failure histories, observation from assessments (i.e., digs, pressure tests, and ILIs), and mechanistic understanding of SCC (i.e. susceptible coating, pipe material, stress level, soil properties, etc.). This risk model is transparent and updateable, which allows incorporation of new scientific learnings and findings of SCC.

Pipeline integrity has been threatened at the Dead Horse Creek pipeline crossing in southern Manitoba by a slow-moving slope failure with a potential for crest retrogression. The movement zone extends from the slope crest to the bottom of the creek, a vertical distance of about 25 m and is approximately 80 m long from toe to scarp and 100 m wide along the creek. The slope has degraded over time and is controlled by the combination of local geology, which consists of weak colluvium overlying high plastic clay shale, and creek bank erosion and channel degradation. Saturated soil conditions, a function of poor drainage and elevated seasonal precipitation, have exacerbated the problem over the years. The slope movements have been monitored on a regular basis since 2008 and presented an increasing risk to the integrity of multiple pipelines located in two rights-of-way (ROWs) situated within and immediately adjacent to the failing soil mass. The site is surrounded by various infrastructure and recreational areas that are key to the community, and therefore is considered a high consequence area with respect to potential pipeline failures. To manage the risk and protect pipeline integrity, various stress relief and other mitigating measures have been implemented since 2013 [1], culminating in a major slope rehabilitation project undertaken in 2015, which comprised earthworks, drainage and watercourse improvements, and slope stabilization using stone columns. While the use of stone columns to stabilize embankments is not a new technique, it is not commonly used in the pipeline industry and represents another option for geohazard stabilization in the right situations. This paper presents the slope stabilization techniques employed and discusses the challenges of working on an active moving slope confined by a watercourse and live pipeline assets. The positive benefits of the stabilization measures are illustrated through the use of 2D and 3D numerical modelling, and confirmed through an ongoing geohazard management program that includes site inspection and instrumentation monitoring which continues to show improvements in slope performance post construction.

Terrain analyses and geologic hazards assessments are recognized as important components for pipeline planning, permitting, and asset management. Although the two types of assessments have inherently different objectives and outputs, there is some overlap in the results between the two and they tend to complement each other; thus, there are benefits to conducting the two assessments in parallel, and integrating the results. Likewise, situations may arise where information from both assessments may simultaneously prove useful in driving decision-making. Terrain analyses seek to identify homogenous terrain units based on material types, surface expression, depth to bedrock, slope, drainage, and geomorphological processes. Information compiled during a terrain analysis helps to develop a detailed understanding of the local terrain, which can be used to estimate geotechnical soil properties, provide cost savings, and formulate sound decision-making throughout the life of a pipeline. Geologic hazards assessments generally seek to individually identify, map, characterize, and ultimately allow for mitigation/monitoring of potential geologic hazards, through increasingly detailed geomorphic/geologic assessments. Some typical geologic hazards that are evaluated include landslide, seismic, subsidence, and hydrotechnical hazards. Once identified, a qualitative hazard classification (e.g., low, moderate, high) is generally assigned to each possible hazard, based on several criteria such as the activity level of the geologic process, rate and magnitude of movement of the hazard, the areal extent and proximity of the hazard, the estimated likelihood that the hazard would affect or engage a pipeline during its service life. The hazard classifications are often then tied to recommendations for additional assessment and/or response and mitigation. The identification of a landslide will be used as an example to highlight how the two assessments can overlap and complement one another, but still provide unique information, and how the two assessments can be used in conjunction to inform better decision-making. Both assessments may identify the location of the same landslide or potentially unstable slope. The geologic hazards assessment would further characterize the landslide’s spatial relationship to the pipe both laterally and vertically, its activity level, etc., in order to evaluate the potential hazard the landslide poses to the pipeline. If mitigation was deemed necessary, information from both the terrain mapping and geologic hazards assessment could be used to evaluate the specific characteristics of the landslide, as well as the surrounding terrain, in order to select the most suitable form of mitigation.

When transporting multiple products in a pipeline, it is important to always understand the location of the head and tail of each batch. The operator will know where batch interfaces are in real-time and be ready to swing the valve at the exact time a batch arrives at a station to deliver product to the right storage tank or an end-customer with minimal contamination. It is relatively easy to track multiple batches in a pipeline with no elevation changes, and a fixed internal diameter. However, it is far more complex to track multiple batches in a pipeline with drastic elevation changes and different sizes in diameter. Column separation of the liquid, also known as slack, occurs when the pipeline pressure drops below the vapor pressure calculated at the liquid temperature in a specific area of the pipeline. This effect reduces the amount of liquid volume contained within the pipeline region, changing the actual physical position of the batch head and tail interfaces, and reducing the accuracy of the volume within the region and the corresponding Estimated Times of Arrival at stations. Draining or filling a pipeline section by delivering product at a different rate from what injected causes the same effect. A scientific approach to calculate the areas of slack and volume contained within a pipeline should provide sufficient information to track batches with a high degree of accuracy. However, it is neither simple nor straightforward to simulate this phenomenon offline, and it is much more challenging in an online, real-time environment. Online, additional complexities affect how batches and their interfaces are tracked, causing a big discrepancy between Estimated and Actual Time of Arrivals. This paper discusses an empirical approach developed to calculate the volume contained within a pipeline region by tracking the volume entering and leaving the region. Estimated and Actual Times of Arrival are within a 15-minute time window after a batch has traveled a total distance of 1,200km with drastic elevation changes along the route. This method has proven that batch tracking can be highly accurate and reliable with less of the theoretical assumptions used in a hydraulic simulation package, with no need to model every single characteristic of the pipeline in detail. This removed the uncertainties that attend those assumptions and allowed this system to perform well on a pipeline with severe slack flow and draining/filling operations.

Invariably, oil pump station piping layouts may contain multiple dead-legs brought about by closed valves at one end of side branches, while flows continue through the main runs. During the transportation of heavy crude through the pump station, these dead-legs will be filled with this crude. When a light crude batch is introduced next into the pipeline, following the heavy crude ahead, two phenomena will occur. First, contamination between batches at the interface of the two crudes will occur due to axial turbulent diffusion along the length of the pipeline itself. Second, as the light crude flows through the pump station, and passes by each dead-leg containing residual heavy crude from the preceding batch, the heavy crude trapped in these dead-legs will start to drain out into the passing light crude in the main run. This causes further contamination and spreading of the mixing zone between the two batches. The second source of contamination, which is addressed in this paper, could cause appreciable contamination particularly for large dead-leg sizes and numbers. A computational fluid dynamics (CFD) model has been developed to quantify the drainage rate of the contaminating crude into the main stream and its impact on widening the mixed zone (contamination spread) between the two batches. Two drainage mechanisms of the heavy crude in the dead-legs into the main stream of the light crude have been identified and quantified. Finally, potential innovations to mitigate contamination due to dead legs are presented and quantified for their respective effectiveness in minimizing the contamination spreads between batches of different crudes.

Accidents related to production, processing, storage and transportation of oil and its by-products have been studied extensively because of their social and environmental impacts. However, accidents relating to construction of oil facilities have been largely ignored by researches, perhaps because such accidents involve a smaller group of people and result in smaller-scale environmental impacts. Pipeline construction projects are particularly unique. As opposed to construction of processing plants, pipeline construction covers a very long reach, often involving varying site conditions. Consequently, there are more environmental issues, many of which vary from place to place along the pipeline route as a result of the differing soil, drainage, vegetation and exposure conditions. The variable conditions, exposure and consequences of accidents along a pipeline route result in many challenges related to risk management. Specifically, risk management is difficult as a result of transportation along the pipeline corridor, multiple access routes to the pipeline corridor, unique culture and social issues in various parts of the country, and remote working conditions. Major issues are moving work sites; crossing of different areas of the country with several typical cultural and regional aspects; multiple work sites and the isolation of workers in small groups. These factors make risk management particularly important, but easy to ignore. In this paper we discuss the major potential risks in every phase of the pipeline construction. The paper describes the company’s process for managing risk during pipeline construction. It identified the limitations of traditional safety management systems in coping with the critical problems related to environmental and safety issues. Many company are using integrated management systems as the major tools to control risk. Such systems cover health, safety and environmental issues (HSE). PETROBARS, as the largest Brazilian oil company and one of the leading oil companies in the world, has adopted the HSE system. The system focuses on employee participation in implementation of the HSE system.

The integrity management of a pipeline with stress corrosion cracking was accomplished in two distinct phases. The initial phase, from 1993 to 1996, consisted of excavations that quantified damage (stress corrosion cracking & corrosion), fracture mechanics modeling and hydrostatic testing, with a short-term objective of restoring Maximum Operating Pressure (MOP). Limited testing was conducted to evaluate the hydrostatic line on the 610 mm (24″) diameter line. The second phase, from 1996 until present, included running a shear wave ultrasonic tool, a zero degree ultrasonic tool, fracture mechanics modeling and rehabilitation digs. The extensive data collection during rehabilitation was utilized to evaluate the relationships between cracking susceptibility and degree of Stress Corrosion Cracking (SCC) with parameters such as soil type, drainage, topography and magnitude of pressure fluctuations. Corrosion products predominantly consisted of iron carbonate, very much characteristic of the low pH SCC mechanism. Following the shear wave ultrasonic tool, a zero-degree compression wave ultrasonic tool was utilized to characterize the long axial corrosion locations with potential shallow cracking. A re-inspection plan was developed using crack growth rates, hydraulic simulations of pressure fluctuations and excavation data. The reliability of the pipeline was increased and the overall integrity management costs were reduced. Presently, hydrotesting is not being used to manage integrity of Rainbow’s system.

Two types of stray current which affect the cathodic protection of underground pipeline are discussed. One is the stray current by DC transit system and the other is that originated from the nearby cathodic protection system. The popular evaluation methods of the pipe-to-siol potential measurement was undertaken to evaluate the corrosion activity of pipeline. In case when the pipe was affected by the stray current, the measured pipe-to soil potential was significantly deviated from the mean value resulting in normal distribution. Analysis of such distribution pattern has revealed that the pipe under investigation was in the condition of insufficient protection (noble mean potential and high asymmetry coefficient) due to the considerable effect of stray current (high standard deviation value). It was also confirmed that the efficiency of drainage system was so low (<10%) due to the improper selection of drainage point. Simultaneous measurement of the magnitude and direction of the sheath current resulted in information about the place where stray current entered into pipe and escaped to soil. For the second case of stray current problem, it is shown that it has been caused by the combined interference from nearby CP system.

As the natural gas pipeline system in Western Canada expands northward, it traverses the discontinuous permafrost zone. As the ground temperature of the frozen soil in this zone is just below freezing, it can be expected that within the design life of a pipeline the permafrost adjacent to it will melt due to the disturbance of the insulating cover by construction activities. Differential settlement at the thawing frozen/unfrozen soil interfaces gives rise to pipeline strain. Based on the calculated settlement and resulting strain level, a cost effective mechanical or civil design solution can be selected to mitigate the differential settlement problem. Since these design solutions can be costly, it is desirable to combine them with a pipeline route that traverses the least amount of discontinuous permafrost terrain while minimizing the overall length of the pipeline. This paper will detail the framework utilized to select the routing for a package of pipeline projects in northwestern Alberta. The process began with a review of the state of the art in permafrost engineering in order to benefit from past experiences. Airphoto interpretation and terrain mapping were performed for potential pipeline corridors. Preliminary routing options through the corridors were chosen from this mapping information that minimized both pipeline length and amount of permafrost terrain traversed. The next step was to collect field data for each route that would determine the extent and characteristics of the permafrost. Essentially two sets of field data were collected: geophysical mapping of representative sections of each terrain type and physical sampling of the permafrost. Boreholes were located following field interpretation of the geophysical data to ensure they were optimally located to help in calibration of the geophysical data. Permafrost samples were tested in the laboratory for thaw settlement. Anticipated thaw settlements were used to estimate pipe strain levels. This information was then extrapolated for the entire proposed pipeline route and used to finalize both the pipeline route and the differential settlement design options. Monitoring sites will be instrumented to obtain data on the longer term performance of the pipeline, as well as for assessing permafrost degradation effects on the right-of-way such as settlement and impact on drainage patterns. It is believed that the increased front end effort will result in lower operating costs and an overall reduced life-cycle cost. This basic design methodology can be applied to any project that traverses discontinuous permafrost terrain.

Erosion is a common problem at pipeline watercourse crossings. Watercourses are naturally vulnerable to erosion but the risk is particularly acute after sub-soil and armour materials have been disturbed by trenching and backfilling during pipeline construction. The process of pipeline exposure at watercourse crossings can be grouped into these types. One common type of erosion phenomenon is episodic exposure resulting from general and local scour. This is associated with temporary river scour during flood events. It includes general scour involving temporary lowering or the entire river bed during high flows, as well as local scour which involves development of a scour hole during high flow events at a predictable location on the river bed. River engineers have adopted various design methods to ensure sufficient pipeline burial depth which minimizes pipeline exposure due to such periodic occurrences. A second type of erosion phenomenon causing pipeline exposure is progressive river channel bed and bank erosion. This is not a function of a single event but occurs periodically, resulting in progressive removal of pipeline cover. Progressive erosion at pipeline crossings includes riverbed degradation, bank erosion and growth of gullies. River bed degradation (progressive river bed lowering) is a complex phenomenon associated with the stage of geomorphic development of the drainage basin. Its prediction is based on a sound understanding of sediment supply, river hydraulics and river outlet conditions. Bank erosion is a common occurrence and is readily observed. It may be a continuous or episodic occurrence and is often related to the river’s tendency to change its meander pattern, cross sectional shape or bed level. Growth of gullies is a very common cause of erosion at pipeline crossings and results from changes in land use, soil composition, and landscape drainage networks. Techniques for predicting progressive erosion are not well developed and widely understood. As a result, progressive erosion is a common cause of erosion and even pipeline exposure at pipeline crossings of rivers, streams, and gullies. A third mechanism of pipeline exposure is river avulsion. This is often associated with a tortuously meandering channel, a steep braided channel with a wide flood plain or an immature channel on a delta. Methods of avoiding or controlling erosion are based on a sound understanding of causal factors. Each river crossing location is unique and the local risks of pipeline exposure must address specific local conditions. Methods of estimating the risk of local and general scour, progressive erosion, and river avulsions are discussed. Methods of mitigating erosion at pipeline crossings include proper siting of pipeline crossings, deep burial, conventional armouring and a combination of bank toe protection and upper bank vegetation cover.

The geotechnical aspect of the design of off-shore oil and gas pipelines is a challenge due to inherent uncertainties in predicting soil-pipe interaction behaviour. Physical modeling is often sought after to gain insight into such problems. This is especially true for pipelines laid in deep waters that are partially embedded in the seabed. This paper presents initial observations arising from full-scale laboratory simulations of typical soil-pipe interaction scenarios of partially buried steel pipes. Bare and epoxy-coated NPS18 steel pipes, each measuring 2.5 m in length, were separately tested in a soil chamber by simulating: (i) lateral pipe displacement; and (ii) longitudinal pipe displacement, under partial embedment in two idealized soil bed models, i.e., in a coarse-grained soil bed model with full drainage, and a fully-saturated fine-grained soil bed model with partial drainage.

A major slope in southern Manitoba has been experiencing deep seated movements of approximately 60mm per year. This 24m high × 85m long slope contains a pipeline right of way with five large diameter crude oil lines that were constructed from 1950–1998. It is estimated that the slope has moved up to 3 meters since the pipeline installations. Management of the effects of this slope movement on the pipelines has involved cross-functional strategies that include geotechnical, integrity, and stress evaluations. A finite element analysis (FEA), which considers the interaction between the soil movement and pipeline, was generated to evaluate the pipeline stresses caused by the slope movements to date. The results indicated that the strain capacity on one of the pipelines may be near its limit. Correspondingly and in order to be conservative, a stress relief was conducted on three of the pipelines within the right-of-way. This mitigation involved excavating the pipelines 360 degrees which allowed for their decoupling from the surrounding soil, and the associated pipeline spring back was surveyed. Prior to backfilling, a low friction geotextile was installed around the excavated pipelines to help mitigate future movements. Drainage improvements and a toe berm were also installed to improve the slope stability. Several strain measurement technologies that have been the subject of previous Pipeline Research Council projects were also installed at the site. Stress probe measurements were taken before and after the stress relief; a fiber optic cable was installed; inline inspection bending strain measurements were analyzed; and the FEA analysis was used to model the strains before and after the stress relief. All of these technologies are compared to the measurements from strain gauges that were read both before and after the stress reliefs were conducted.

Pipeline crossings of sensitive, state or federally-regulated resources are occasionally unavoidable and can substantially increase project costs and negatively affect project timelines. During due-diligence surveys for invasive plants, field botanists identified an undocumented calcareous fen and associated state-listed wetland plants along the route of Enbridge’s LSr and Alberta Clipper pipelines in northwest Minnesota. Calcareous fens are rare peat-accumulating wetlands dominated by groundwater discharge, a high mineral content, and are protected by state law. Their hydrology and chemistry provide an environment for a suite of state-listed plants that are specifically adapted and unique to calcareous fens. By state statute, calcareous fens may not be filled, drained, or otherwise degraded by any activity unless the Commissioner of the Minnesota Department of Natural Resources (DNR) authorizes the activity under an approved Fen Management Plan. The proposed LSr and Alberta Clipper Pipeline route in the area was collocated with existing Enbridge pipelines installed before the fen was identified. State regulatory staff quickly officially recognized the Gully 30 Calcareous Fen which initiated a lengthy permitting process to authorize Enbridge to construct the LSr and Alberta Clipper Pipelines through the Gully 30 Calcareous Fen. Avoiding the fen would have involved an impracticable reroute along several miles of greenfield. The state (DNR) and federal (Army Corps of Engineers) process involved detailed characterization of the resource, development and approval of an alternatives analysis according to Section 404(b)(1) guidelines, and drafting and approval of a project-specific Fen Management Plan which stipulated specific construction mitigation procedures including winter construction and protective temporary drainage, and post construction monitoring requirements. This presentation introduces the calcareous fen resource and examines the permitting and iterative, comment-response construction-design process as an example of successful collaboration between state and federal agencies and Enbridge to construct a pipeline through a highly regulated, sensitive natural resource while maintaining schedule.

With the method of characteristic (MOC) and analysis for the dynamic state of trapped air, this study could be performed on the basic theory of gas-liquid two phase unsteady flow, and cavitation and bubble dynamics, to obtain the overpressure value during pigging. For a long slope pipeline, a severe rupture occurred in the vicinity of a drainage pipe during a segmental pigging process. In contrast to earlier accidents induced by hydraulic transients, the unique combination of topography and geometry of the drainage pipe was a key factor. Generally, a pipeline profile complexity has a significant effect on both the liquid-fill flow behavior and the state of trapped air, both of which are factors contributing to cavitation and water hammer. Pigging is a common technological process that has been studied for many years, but has rarely been analyzed by hydraulic transient methods with consideration for pig motion in a pipeline. From local data, it is shown that transient pig motion has a huge influence on operating conditions, especially outlet pressure. The purpose of this study was to identify the damage mechanism. Following extensive study, it was determined that cavitation and vapor cavity collapse cause instantaneous overpressure due to the interaction of topography, geometry of the drainage pipe, and pig motion. It would be rather difficult to simulate the pig motion by a conventional MOC and the simple water hammer equation for the collapse of large vapor cavities at a high point. Therefore, a new approach which describes the moving boundary with a dual-grid model has been implemented, along with an explicit solution procedure.

It is generally believed that physical and chemical condition of the pipeline environment (such as soil texture, drainage, ground topography, cathodic protection level, pH, etc) in addition to pipeline construction factors (such as pipe vs. ground slope, type and quality of the pipe coating, etc.) affect the incidence and severity of external corrosion and SCC on pipelines. In an attempt to identify locations of highest susceptibility to external corrosion and cracking on a tape coated Enbridge pipeline, and to aid integrity management processes; Enbridge embarked on a project investigating landscape factors which might affect the severity of external corrosion and stress corrosion cracking (SCC) on the pipeline. Results showed that some of the investigated factors had positive correlations with the severity of external corrosion and SCC on the tape coated pipeline. However, despite the positive correlations observed, they were not strong enough to be used as an independent predictive tool.

OSBRA is a 20 ″ multiproduct pipeline operated by TRANSPETRO that supplies Diesel oil, gasoline and liquefied petroleum gas (LPG) from REPLAN, the Brazilian major refinery, to five Tank Farms located along the country Midwestern region. In 2001, five years after OSBRA first commissioning, TRANSPETRO initiated several projects to improve the pipeline and Tank Farms operational performance on quality, measurement, safety and environmental care. A project portfolio management system was established in order to keep control of projects conducted along the 964 kilometers of pipeline, its Tank Farms and two unmanned pump stations. Learned lessons and good practices were adopted from typical project management cases on the pipeline industry, such as: tank drainage, effluents and fire protection systems; improvements on pipeline measurement and control systems; improvements on pipeline leak detection system; tank construction; short length pipelines construction; truck loading and unloading terminal facilities; jet fuel receiving, storage and delivering system; technology developing projects and so on. Some of these projects were conducted based on PETROBRAS traditional experience on project management, some were conducted according to the Independent Project Analysis Institute - IPA and the best recommended practices from the PMI’s PMBOK® Guide, and others were conducted considering a mix of both practices. During the project, the members of the project team and its stakeholders were geographically spread out through several sites. This paper presents how the OSBRA project portfolio has been managed by a reduced multi-disciplinary team, including safety and environmental professionals, in order to keep each project aligned to meet its essential operational and business objectives.

The Ruby Pipeline is a 42-inch diameter pipeline that will transmit natural gas 675 miles from Opal, Wyoming, to Malin, Oregon. The pipeline alignment crosses landforms designated as playas at several locations in Utah and Nevada. Federal agencies reviewing environmental documents requested mitigation based on the concept that playas collect and hold rainwater on impervious clay bottoms for long periods of time, and that an open-cut trench could drain ephemeral lakes by penetrating impervious clay bottom soil layers and permanently alter the surface water hydrology of the playas. Trench plugs, segregation of excavated impervious soil, limited construction right-of-way, impervious backfill, and construction during the ‘dry’ season were the recommended mitigation measures, presumably to reduce the potential for surface water collected on the playa to drain into the subsurface through a trench cut across the playa. The surface-water hydrology concern may pertain to playa environments in semiarid areas such as the southern High Plains of the United States, notably northern Texas. The playas crossed by the Ruby Pipeline are lakebeds of major ancient lakes (Lake Bonneville in Utah, and Lake Lahontan and Lake Meinzer in Nevada) that were hundreds of feet deep and occupied extensive, topographically closed drainage basins. These lakebed playas are dominated by shallow groundwater. Surface water collects on the playa surfaces but is not responsible for playa formation or preservation. The water tends to be salty in lakebed playas in Utah and Nevada compared to fresh water in the ephemeral playa lakes in northern Texas. This brief case history describing playas dominated by groundwater instead of surface water may help advance the understanding that mitigation useful for surface-water dominated playas is not needed for groundwater-dominated playas. Geotechnical investigation included soil borings, test pits, laboratory testing, and surface geophysical surveys (seismic refraction and refraction microtremor [ReMi] methods).

External corrosion growth rate is an essential parameter to establish the time interval between successive pipe integrity evaluations. Actual corrosion rates are difficult to measure or predict. NACE Standard RP0502 [1] recommends several methods including comparison with historical data, buried coupons, electrical resistance (ER), and Linear Polarization Resistance (LPR) measurements. This paper presents a testing program and procedure to validate the use of the LPR and ER methods to enhance the estimation of corrosion growth rates and improve the selection of reassessment intervals of gas transmission pipelines. Laboratory and field tests were performed using the LPR and ER technologies. The evaluation of soil parameters that affect localized corrosion included its type, moisture content, pH, resistivity, drainage characteristics, chloride and sulfite levels, and soil Redox potential. The results show that the LPR device provides instantaneous measurement of corrosion potential and it may be used to reflect the variations of corrosion rates with the changes of soil conditions, moisture, and temperature. However, LPR measurements are more efficient in saturated soils with uncertainty about its validity in partially and totally dry soils. Consequently, seasonal changes in soil conditions make it difficult to estimate total corrosion growth rate. On the other hand, the measurements using the ER method provided consistent estimates for long-term corrosion growth rates. Corrosion growth rates were also evaluated from a previous study by the National Institute of Standards (NIST) [2]. A procedure was developed to correlate soil properties to corrosion rates from the ER measurements and NIST data. The procedure was implemented in a computer program to provide an estimate of corrosion rate based on the soil input data and allows the operator to use the ER probes to improve the reliability of corrosion rate estimates.

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.