In the light of recent experience of wildfires in Alberta and British Columbia, Alliance Pipeline has strengthened their emergency preparedness in dealing with external fire events that have the potential to affect above-ground facilities connected with their high pressure natural gas pipeline system. As part of this initiative a quantitative methodology has been developed that enables the effects of a wildfire on an above-ground pipeline facility to be assessed. The methodology consists of three linked calculations which assess: 1. the severity of the wildfire, based on information from the Canadian Wildland Fire Information System, 2. the transmission of thermal radiation from the wildfire to the facility, and, 3. the response of equipment, structures and buildings to the incident thermal radiation. The predictions of the methodology agree well with the actual damage observed at a lateral block valve site following a wildfire in 2016. Application to example facility types (block valve sites, meter stations and compressor stations) has demonstrated that, in general, damage is only predicted for more vulnerable items such as cables. The sensitivity of the predictions of the methodology to the input parameters and key modelling uncertainties has been examined. This demonstrates that the results are sensitive to the distance of the facility from the tree line and the assumed vegetation type. This shows the importance of verifying the location relative to the vegetation and selecting the appropriate vegetation type from the Canadian Wildland Fire Information System for site specific assessments. The predictions of the methodology are particularly sensitive to the assumed flame temperature. However, a value has been chosen that gives good agreement with measured thermal radiation values from wildfires. Of the mitigation options considered, the most effective and practical is to increase the distance to the tree line. This measure has the advantage of reducing radiation levels for all items on the site. Even though the work shows that failure of exposed pipework due to wildfires is unlikely, maintaining the flow within pipes is recommended as this increases the radiative flux at which failure is predicted to occur. However, as failure of cables and hence control systems would occur at a lower flux levels the fail-safe actions of such systems needs to be confirmed. Shielding of cables or items of equipment in general is likely to be impractical but could be considered for particularly vulnerable equipment or locations.

CSA Z662, Oil and gas pipeline systems, defines class location as “a geographical area classified according to its approximate population density and other characteristics that are considered when designing and pressure testing piping to be located in the area.” In other words, the purpose of class location designations is to identify areas where specific measures are considered necessary to enhance public safety. Designations range from Class 1 (rural) to Class 4 (urban with high-rise buildings). The current class location framework relies mainly on a location factor (L) to represent reliability. Higher reliability is achieved by using more resistant pipe — that is thicker and/or stronger — to reduce the probability of failure from operational hazards, such as corrosion and mechanical damage caused by line strikes. Currently, the need for a particular level of reliability is driven principally by the number of people impacted. This paper discusses possible measures that can be implemented in the next edition of Z662 that, beyond requiring thicker pipe for certain products, will strengthen the class location designation system by considering the potential impact radius of an ignited gas pipeline rupture, as well as the occupancy and nature of buildings within assessment areas. The paper also discusses possible changes to improve environmental protection by introducing the concept of a designated geographical area (DGA) and associated requirements, enhancements to valve spacing requirements, and the handling of changes to class location designations for existing pipelines through interim measures and retroactivity.

A study was undertaken to evaluate crack arrestor and mainline block valve (MLBV) spacing distances beyond the limits defined in the 49 CFR Part 192 for Class 1 locations for the design of a 42-inch (1,067-mm) OD arctic pipeline. The study assessed whether an MLBV spacing longer than that required by 49 CFR Part 192 for Class 1 locations can provide a level of safety equivalent to that afforded by the spacing recommended in the code. This was accomplished by comparing the hazards in terms of the volume of natural gas released over time, the potential for damage to surrounding structures, and the life safety risk to personnel and the public. The analysis was performed using the software tool PIPESAFE (version 2.20.0), which was developed for a group of pipeline operators by Advantica Technology (now DNV-GL). A full transient analysis of the flow inside the pipeline and through the rupture opening was carried out with automatic shut-off valve (ASV) closures simulated as boundary condition changes at the locations of the valves triggered by the local transient pressure. Gas outflow rates were fed to a structured flame model that calculates the temperature distribution within the flame and the radiant energy emitted and uses the latter to determine the incident thermal radiation field in the area surrounding the rupture, the associated hazard areas and the accumulated thermal radiation dosage over time. These results were compiled into contour plots of thermal radiation intensity for different times; plots of the total area within specific contours of thermal radiation intensity for different times; and plots of the total area within specific contours of accumulated dosage. The dosage-area curves facilitate a direct comparison of the various MLBV and crack arrestor spacing options considered within this study by providing a simple means to establish if the change in spacing causes a substantial change to the affected areas for dosages up to the limits associated with specific levels of lethality to humans and for piloted ignition of wooden structures. It was found that valve spacing has a strong effect on the time at which closure begins to affect the outflow rate. The decline in flow rate after valve closure had significant influence on the thermal radiation field, but these effects only occurred at a relatively late stage. Increasing fracture length led to considerable changes in the shape of the thermal radiation field, but the total footprint within which casualties might be expected in the event of an ignited rupture release and the severity of injuries within the footprint are unaffected by valve closure under the assumed conditions. Similarly, the damage potential to surrounding buildings was unaffected by valve spacing, indicating that increased valve spacing could be implemented in remote, low population density areas without affecting safety.

Ground deformation from natural or anthropogenic processes is a significant factor in the integrity management plan for natural gas distribution networks. Rapid or large scale deformation can pose an immediate rupture threat. Smaller, more gradual or repeated ground deformations may lead to material stresses, damage and strain accumulation, posing a longer-term threat. Satellite monitoring can play a key role in pipeline integrity management programs by measuring ground deformation over an entire pipeline network, at high spatial and temporal resolutions with the ability to capture both rapid large scale and subtle, repeated ground movement over a longer period of time. Millimeter accuracy ground deformation estimates are derived from radar satellite imagery using InSAR, a well-established and validated remote sensing technique. InSAR is an effective tool for rapidly identifying new regions requiring ground geotechnical surveys, deriving estimates of deformation rate, extents, and evolution of deformation patterns, for validating or extending traditional ground-based measurements, and for forward-looking operational monitoring. We present the results of InSAR ground deformation monitoring over a natural gas distribution pipeline network in Saskatchewan, Canada. At the case study site, small diameter pipelines (up to 40 years old) have been subjected to ground slumping from a retrogressive landslide affecting multiple lakeshore communities and compounded in recent years by a high water table. Some locations have recently experienced slumping at rates greater than 50 cm/yr leading to important structural issues with roads, buildings, water mains, and gas pipelines. The ground movement analysis is based on RADARSAT-2 satellite imagery acquired at 24-day intervals over a short period in 2015. Thousands of suitable measurement points were identified over two communities on opposite shores of the lake. The measured InSAR deformation time series showed deformation toward the lake. The extents of the deformation are clearly delineated by the InSAR measurements.

A proprietary fibre optic sensing technology has been developed and is capable of simultaneously utilising an existing fibre optic communication cable as an integrity-testing sensing cable, thus providing continuous, real-time monitoring of the fibre cable and any structure near the cable (ie., ground, tunnels, ducts, pipes, buildings, equipment, vessels, etc.). With this system, simultaneous fibre optic communications and real-time vibration monitoring was demonstrated using a wavelength multiplexed fibre system for a channel bandwidth of 500 MHz over 18 km of standard singlemode fibre. Real-time vibration monitoring was also demonstrated using standard singlemode and multimode fibre over lengths of 28 km and 53 km, respectively. Trials of the system are currently underway in Australia and the first commercial field installation with this capability is to be completed in mid-1998 in Indonesia. This paper highlights the benefits and potential of this dual-capacity system and details results obtained to-date.

There is an increasing demand for operators of transmission pipelines to maximise the throughput of their pipeline systems. This can be achieved relatively easily with new pipelines, by using limit state design, new materials, novel fabrication techniques etc., Operators are also looking to maximise the throughput of existing transmission pipelines. Obviously, they are not able to make use of new materials etc., but limit state design concepts can be applied to show that a pipeline can be safely uprated to a higher design pressure. The limit state of an engineering structure or component is defined as the mathematical relationship between the parameters associated with a particular failure mode at the onset of failure. To assess the impact on pipeline integrity and safety, a limit state approach incorporating probabilistic analysis has been developed. The approach addresses all credible failure modes and takes account of uncertainties in the relevant parameters for each mode. The probabilistic approach takes the limit state approach a step further by describing the parameters as statistical distributions rather than single values. This allows failure probabilities to be computed which are a more meaningful measure of safety and allow areas of over conservatism (or under conservatism) to be identified. It is important to note that the approach is only as good as the limit states used and the data used to construct the distributions. Clearly uncertainties in both of these can exist and the absolute values of the computed probabilities must be viewed with caution. However, the strength of the approach lies in the relative values of the computed probabilities and previous ‘safe’ operation. If a system has a significant operational history with few or no failures and it can be shown that there is little change in the theoretical failure probability associated with a change in operating conditions, it can be inferred that few or no failures will occur in practice. The paper describes the above approach in detail and outlines a study carried out to determine the effect on pipeline integrity of uprating three pipelines from a current maximum operating pressure of 70 bar to an uprated pressure of 85 bar, exceeding the current design criteria. By application of the limit state approach incorporating probabilistic analysis, it is shown that there would be an insignificant change in failure probability as a result of uprating to 85 bar, and hence that the integrity of the pipelines is unimpaired by uprating.

Environmental noise has become a significant concern for compressor station operations. Typical compressor buildings provide limited attenuation of the noise from the compressor package. In addition, ventilation openings, windows, doors and explosion panels can significantly downgrade the building’s potential acoustical performance. Similarly, exterior equipment such as aerial coolers, yard piping and exhaust silencers are noise contributors that cause challenging design constraints towards achieving practical noise control solutions. Integration of all of these aspects means that the economic retrofit of existing compressor station noise sources, particularly the compressor buildings themselves, has proven to be a difficult challenge. Consideration of construction complexity and cost in the “Balanced Design” process ensures that the final design is practical, economical and expedient. This paper discusses in detail the components of an approach that has been successfully used to provide cost effective noise control at existing compressor stations.

This paper describes the GIS system developed for the Pemex’ pipeline network in the Valley of Mexico. The pipeline UTM coordinates, which are the basis of the GIS, were obtained from the high accuracy Geopig ® inertial and caliper surveys. The survey data also included information on pipeline features and anomalies, and was incorporated into the GIS together with the metal loss data from the past in-line inspections. The system is based on the ArcView ® GIS Software with the Arc View 3D Analyst™ extension that allows both the cartography and pipeline data to be viewed in 3-D space. It stores information on pipeline plan, profile, girth weld locations, dents, wall thickness, bending strains, metal loss and other features in relation to known landmarks such as roads, buildings, political boundaries and hydrology. This allows for very efficient and accurate location of pipe defects and anomalies, which is particularly beneficial where there are several pipelines running in the same right-of-way. It helps to eliminate unnecessary excavations, as well as to coordinate, plan and schedule pipeline repairs. The additional benefit of a multi-pipeline GIS system is the ability to store various information for all the pipelines in one database, which is easy to manage and update. The GIS also gives the ability to plot detailed maps, query data for effective solutions and visualize scenarios.

Current defect assessment procedures of large engineering structures, including pipeline systems and their welded components such as field girth welds, employ crack growth resistance curves in terms of J -resistance or CTOD-resistance curves. Standardized techniques for crack growth resistance testing of structural steels are based upon laboratory measurements of load-displacement records and adopt two related estimation formulas for fracture toughness values: 1) estimating J from plastic work based on crack mouth opening displacement (CMOD), and 2) determining the CTOD value from first evaluating the plastic component of J using the plastic work defined by the area under the load vs. CMOD curve and then converting it into the corresponding value of plastic CTOD. This work addresses an investigation on the relationship between J and CTOD for three-point SE(B) and clamped SE(T) fracture specimens based upon extensive numerical analyses conducted for crack configurations with varying crack sizes. These analyses include stationary and crack growth plane-strain results to determine J and CTOD for the cracked configurations based on load-displacement records. The numerical computations show strong similarities between the J -CTOD relationship for stationary and growth analysis with important implications for experimental measurements of CTOD-resistance curves. The study provides a body of results which enables establishing accurate relationships between J and CTOD for use in testing protocols for toughness measurements.

Above ground petroleum product storage tanks are tanks or other containers that are above ground, partially buried, bunkered, or in a subterranean vault. These are built to store petroleum product for pipeline system, oilfield and refinery. Tank fires are one of the most terrible accidents in oil pipeline transportation stations. Tank fires pose a significant hazard to people, buildings, process piping, the environment and other facilities as a result of thermal radiation exposure. It is necessary and meaningful to study the distribution of the thermal radiation of a tank fire for emergency response, prevention and reducing loss. To analyze potential tank fire incidents at a pipeline station, a three-dimensional station model was built using a computational fluid dynamics (Abbreviated as CFD, is a branch of fluid mechanics that uses numerical methods and algorithms to solve and analyze problems that involve fluid flows) software package to evaluate the thermal radiation distribution under different conditions. Numerical simulations were carried out for a total of six simulation scenarios to analyze 3 types of potential fires for 2 different liquid products (gasoline and diesel). The three kinds of fires that were modeled included: 1) disk pool fire on top of the tank; 2) ring pool fire on the top of a tank; and 3) pool fire in a dike. The simulation evaluates the effect of the thermal radiation on facilities and people. The simulation results show that the water cooling system is effective at decreasing the magnitude of thermal radiation exposure and as a result is effective at protecting nearby tanks and facilities. Without water protection, the disk fire or ring fire can destroy or damage nearby structures significantly. The results of the simulation also show that the dike pool fire can have a catastrophic consequence to nearby facilities. Further the analysis showed that environmental wind does not change the thermal radiation distribution significantly. The results of the simulation point out countermeasure activities to enhance fire prevention at oil pipeline transportation stations in a scientific way.

Oil and gas transmission pipelines have a good safety record; however, like any engineering structure, pipelines do occasionally fail. The main causes of pipeline failures in North America and Europe are defects, such as damage due to external interference, corrosion defects, or material defects. Consequently, the pipeline industry developed its own ‘pipeline-specific’ methods for assessing the significance of these defects. These pipeline-specific methods have their origins in fracture mechanics, but the complexity of the underlying failure mechanisms was addressed through empiricism. Over the intervening years, more accurate ‘pipeline-specific’ methods have been developed that better model the underlying failure mechanisms. The toughness of line pipe steels is typically characterised in terms of the Charpy V-notch impact energy. This is a qualitative measure of toughness. The pipeline-specific methods use empirical correlations between Charpy V-notch impact energy and fracture toughness. In parallel to the development of the pipeline-specific methods, fracture mechanics has been generalised in standards such as BSI 7910: 2005 and API 579-1/ASME FFS-1, using the ‘failure assessment diagram’ (FAD). The pipeline-specific methods and the methods in these general (‘generic’) standards have common roots. The pipeline industry has used its pipeline-specific methods for 50 years, as there was little need to use the generic methods. This was because most of the defects detected in pipelines were corrosion or damage (e.g. dents), where pipeline-specific methods were well-researched and validated. The increasing sophistication of in-line inspection methods (‘intelligent pigs’) in the pipeline industry mean that cracks in pipelines are now easily detected. Additionally, recent failures caused by crack-like defects (e.g. the San Bruno failure in the USA in 2010), mean that the industry needs guidance on how to assess these crack-like defects. There is little or no guidance on pipeline-specific methods for crack-like defects. Therefore, the industry has adopted the generic methods, without any evaluation of their relevance or accuracy. The similarities and differences between the generic and pipeline-specific methods for crack-like defects in pipelines are illustrated in this paper through comparison with published full-scale test data for pipes containing notches and cracks. The significance of correlations between Charpy V-notch impact energy and fracture toughness is highlighted. In conclusion, a commentary is given on how and when to take advantage of either approach. The critical gaps in the existing methods are also identified.

A new mathematical model of heat distribution in permafrost soils is considered taking into account different climatic and physical factors. The first group of factors includes consideration of solar radiation, seasonal changes of air temperature, leading to periodic thawing (freezing) of soil, and possible snow layers. The second group of factors is the heterogeneity of the soil, the presence of a number of piles, or foundation structures, seasonal cooling devices. Seasonal cooling devices are vapor-fluid devices consisting of a hermetically sealed and seasoned with coolant, metal pipe with diameter 57 mm, length up to 10 meters or more, consisting of aerial parts (condenser fins) up to 2.5 meters and an underground part. These devices operate without external power sources only by the laws of physics. Taking into account these factors leads to solution of three-dimensional quasilinear heat distribution equation (quasi-linear equation due to the dependence of the thermophysical parameters on temperature) of the Stefan problem in a rectangular parallelepiped, but also with a nonlinear boundary condition at the soil surface associated with solar radiation. It is assumed that the lateral faces of the computational domain are insulated and are chosen sufficiently far from the location of engineering structures, and a computational grid of large dimension to be used, with adaptation to the heat (cold) sources. Software product is designed for numerical simulation of thermal fields in permafrost and melted soil, taking into account thermal diffusion properties of the soil and heat exchange between the soil and air, including also due to heat loss by radiation. The paper is devoted to the results of numerical simulations carried out for the project work in several oil and gas fields in Russia, located in the permafrost zone.

During the life of a gas pipeline, some significant changes in the population may happen along its route. Such changes are indirectly evaluated by the increase in the amount of buildings constructed along the route, which determines the so called Location Class. Such changes, when pipeline is operating, provoke differences between what is required by the standards and what is actually done. The main goal of this paper is to present a risk-based methodology for the guideline development which can be used in decision-making concerning what to do in case of any location class change. Particularly, it has given special attention to the requirements which are imposed for the pipeline operational license continuation in Brazil. Moreover, a summary of the main solutions found in other countries together with a guideline, customized for the Brazilian reality, is presented.

The United Kingdom Onshore Pipeline Operators Association (UKOPA) was formed by UK pipeline operators to provide a common forum for representing pipeline operators interests in the safe management of pipelines. This includes ensuring that UK pipeline codes include best practice, and that there is a common view in terms of compliance with these codes. Major hazard cross country pipelines are laid on 3 rd party land, and in general have an operational life typically greater than 50 years. The land use in the vicinity of any pipeline will change with time, and buildings will be constructed adjacent to the pipeline route. This can result in population density and proximity infringements, and the pipeline becoming non-compliant with the code. Accordingly, a land use planning system is applied so that the safety of, and risk to, developments in the vicinity of major hazard pipelines are assessed at the planning stage. In the UK, the Health & Safety Executive (HSE) are statutory consultees to this process, and they set a quantitative risk-based consultation zone around major hazard pipelines, where the risks to people and developments must be assessed. Quantitative risk assessment (QRA) requires expertise, and the results obtained are dependent upon consequence and failure models, input data, assumptions and criteria. UKOPA has worked to obtain cross-stakeholder agreement on how QRA is applied to land use planning assessments. A major part of the strategy to achieve this was the development of supplements for the UK design codes IGE/TD/1 and PD 8010, to provide authoritative and accepted guidance on the risk analysis of: i) Site specific pipeline details, for example increased wall thickness, pipeline protection (such as slabbing), depth of cover, damage type and failure mode, and ii) The impact of mitigation measures which could be applied as part of the development. The availability of this codified advice would ensure a standard and consistent approach, and reduce the potential for disagreement between stakeholders on the acceptability of proposed developments. This paper describes the guidance given in these code supplements in relation to consequence modelling, prediction of failure frequency, application of risk criteria, implementation of risk mitigation and summaries the assessment example provided.

The most common form of secondary containment for petroleum tanks is an earthen dike structure. Precast, pre-stressed concrete wall structures, however, can offer effective secondary containment, especially for sites that encroach on existing infrastructure, property limits, or environmentally sensitive areas. A secondary containment system constructed with concrete walls occupies a much smaller footprint than an earthen dike structure. This reduction in footprint can be critical, particularly in today’s expanding market which is placing increasing pressure on available site properties including, in many cases, the need to acquire permits for the development of environmentally sensitive areas. The new Tank #79 and Tank #80 projects at the Enbridge Griffith Terminal utilized an 880 lineal foot precast, pre-stressed concrete containment wall system. The existing site soils were sandy and unsuitable for containment berm construction. Therefore, earthen dike structure construction would have required imported clay material. However, the primary motivation for using the structural wall system at the Griffith Terminal was to reduce wetland impacts on the adjacent protected Hoosier Prairie Wetland. The concrete containment wall system saved approximately one half acre of wetland which significantly reduced wetland mitigation costs and also fulfilled the wetland permitting requirement to reduce (minimize) wetland disturbance. Finding a vendor with past experience in the fabrication of precast, pre-stressed concrete panels suitable for secondary containment was a challenge due to their limited prior use in similar containment wall systems. For the design, detailing and fabrication of this system Enbridge worked closely with precast concrete fabricators to define a typical pre-cast panel which was economical, could be easily installed, was structurally suitable for containment design forces and which would prove durable in a cold-weather environment. Additional considerations included proper sealing of adjacent wall panel joints, selecting and detailing a suitable impermeable liner to bridge the wall to the tank lot clay layer, and design and installation of supporting concrete caissons and steel piles for wall panel vertical and lateral support. The Tank #79 and #80 projects at the Griffith Terminal have benefited from the decision to depart from the traditional earthen berm and construct a structural containment wall system. These benefits included reduced wetland and overall project footprint impacts, accelerated project environmental permitting and an accelerated project construction schedule.

Substantial differences amongst metallurgical and mechanical properties of base metal (BM), weld metal (WM) and heat-affected zone (HAZ) occur in general in welded steel structures It is common practice in various engineering structures to evaluate the fracture performance of welded structures by mechanical testing. Especially, the HAZ of steel welded joints shows a gradient of microstructure and mechanical properties from the fusion line to the unaffected base metal. This study is concerned with the effects of metallurgical and mechanical factors on the fracture performance of API 5L X65 pipeline steel weldments, as they are generally used for main natural gas transmission pipelines in Korea. First of all, we investigated the microscopic and macroscopic fracture behavior of the various micro-zones within the HAZ from the viewpoint of metallurgical factors. The effects of mechanical factors such as welding residual stress in steel weldment and strength mismatch between BM and WM, particularly in high strength steel weldments, are also analyzed. Therefore, the fracture performance of API 5L X65 pipeline steel weldment was mainly dependent on the change of macrostructure and its distribution in the welded joints.

Oil and gas transmission pipelines have a good safety record. This is due to a combination of good design, materials and operating practices. However, like any engineering structure, pipelines do occasionally fail. The major causes of pipeline failures around the world are external interference and corrosion; therefore, assessment methods are needed to determine the severity of such defects when they are detected in pipelines. Defects occurring during the fabrication of a pipeline are usually assessed against recognised and proven quality control (workmanship) limits. These workmanship limits are somewhat arbitrary, but they have been proven over time. However, a pipeline will invariably contain larger defects at some stage during its life, and these will require a ‘fitness-for-purpose’ assessment to determine whether or not to repair the pipeline. Consequently, the past 40 years has seen a large number of full scale tests of defects in pipelines, and the development of a number of methods for assessing the significance of defects. Some of these methods have been incorporated into industry guidance, others are to be found in the published literature. However, there is no definitive guidance that draws together all of the assessment techniques, or assesses each method against the published test data, or recommends best practice in their application. To address this industry need, a Joint Industry Project has been sponsored by fifteen international oil and gas companies to develop a Pipeline Defect Assessment Manual (PDAM). PDAM documents the best available techniques currently available for the assessment of pipeline defects (such as corrosion, dents, gouges, weld defects, etc.) in a simple and easy-to-use manual, and gives guidance in their use. PDAM is based on an extensive critical review of pipeline fitness-for-purpose methods and published test data. It is intended to be another tool to help pipeline engineers maintain the high level of pipeline safety. In addition to identifying the best methods, PDAM has served to identify a number of limitations in the current understanding of the behaviour of defects in pipelines, and the empirical limits in the application of existing methods. This paper discusses the PDAM project, in the context of both the current best practice available for defect assessment and the limitations of current knowledge.

As central processing of multi-phase well effluent is becoming more common than field processing, sour gas gathering systems must be maintained at temperatures that do not allow the formation of hydrates. For short systems, heating the gas at the well site (to maintain a temperature that will prevent hydrate formation) or adding methanol to the fluid (to suppress the hydrate temperature) may be acceptable. For large gathering systems, a method of reheating the gas in transit is necessary. The conventional method for reheating sour gas gathering systems is to bring the multi-phase effluent above ground and send it through a heat exchanger. This method requires significant piping, valves, fittings, etc., and results in increased friction pressure losses and brings with it the difficulty of opening the mainline valve (either manually or remotely) when the pipeline requires pigging — all of which will increase capital and operating costs. Reheating above ground also requires toxic/corrosive fluids to be brought to the surface, in closer proximity to operations personnel, causing additional safety and environmental concerns. An underground in-line heating system has been developed to reduce the economic and operational impact of reheating the multi-phase hydrocarbons. The inline heating system eliminates the need to divert the multi-phase effluent from the pipeline by using a single-pass heat exchanger that operates below ground as part of the pipeline. Recirculated glycol is used as the heating medium for this system. The compact, below-ground facility requires only valving on the glycol circuit piping and will keep sour process fluids isolated and away from enclosed buildings where operating staff are present and out of more complex piping with greater potential to leak. As the underground heater is part of the pipeline, pigging operations can continue unhindered. Seven underground in-line heaters have been designed and installed by CIMARRON Engineering Ltd. since 1995. The installed heating systems have been proven to be reliable and easy to use. The underground inline heaters have been found to cost significantly less than the conventional above ground heating system. Other potential uses for the buried heater are: heating of viscous fluids, such as heavy oil (to eliminate need for diluent) and using the heat exchanger for cooling of gas following compression.

The concept of proof testing engineering structures has its origins in antiquity. The pre-commissioning hydrostatic test (also known as the pre-service pressure test) has been an important part of the process of commissioning a newly constructed pipeline for over 50 years, since its beginnings in the 1950s in the USA. The purpose of the hydrotest is several-fold: to prove the leak tightness of the pipeline system at a pressure above the design pressure, as a strength (proof) test to identify (fail) defects and sub-standard pipe, and to prove a safety margin above the pipeline design pressure. Historical data, from PARLOC (Pipeline and Riser Loss of Containment), the OPS (Office of Pipeline Safety) 30 day Incident Reports, and the published literature on the number and causes of pre-commissioning hydrotest failures has been reviewed. The historical data covers onshore gas transmission pipelines in the USA and the UK, and gas and liquid pipelines in the North Sea. The data covers the period from 1952 to 2005, although there are significant gaps in the data (e.g. the OPS data for the USA does not report test failures after 1984). In this paper, the historical data is summarised over this period, by year, in terms of the number of failures per km, and trends in the frequency and type of failures are identified. Comparison of USA and UK experience, or onshore and offshore experience, is contentious because of the influences of different design codes, and local custom and practice. The USA and UK pipeline design code requirements for the hydrotest are summarised in the paper, and it is shown that some of the trends in the failure data may be explained by the differences between the codes. Failures during the hydrotest are rare, but occasionally they do occur. The general consensus is that failures during the precommissioning hydrostatic test are now less common, and that failures due to defective line pipe (rather than due to leaking fittings) are rare. The historical data supports this consensus, but it also highlights that it is largely based on anecdotal evidence rather than data and analysis, because information on test failures is not now routinely gathered and published. The results of the historical review demonstrate that understanding the causes and reasons for hydrotest failures is important for learning from past mistakes, and also for identifying those cases where it may be possible to dispense with a pre-commissioning hydrotest. Reliable historical data on hydrotest failures is necessary to quantify trends over time, and to understand the causes of failures. The pipeline industry as a whole is not coherently recording this data. It should be.

Our Client was commissioned to construct an onshore high pressure gas pipeline. The pipeline was to be about 50km in length, 1066mm diameter, 15.88mm nominal wall thickness and constructed from X65 material. During the route selection phase it was discovered that it would be very difficult to avoid passing the pipeline through a locally highly populated area. In view of this it was naturally decided that the pipeline should be constructed from heavy wall sectioned pipe to mitigate the threat of failure due to causes including mechanical damage and corrosion. However, there was still a concern that the residual risk, even when the above mitigating measure had been taken, would still be unacceptably high. In view of this Andrew Francis & Associates Ltd (AFAA) were commissioned to assess the remaining risk levels using a quantified risk assessment technique in accordance with the UK pipeline design code, IGE/TD/1 Edition 4, which provides for the use of such techniques. The technique used by AFAA involved detailed Structural Reliability Analysis (SRA) combined with an assessment of the consequences of failure. AFAA began the study by identifying the possible failure modes and these included mechanical damage, external corrosion, fatigue crack growth and AC induced corrosion. However, discussions were held between AFAA and the Client and after giving due consideration to the benefits of modern construction standards, and the use of Fusion Bonded Epoxy (FBE) coating, it was agreed that the only significant threat to integrity was mechanical damage. AFAA used SRA to determine the likelihood of failure due to mechanical damage based on a state-of-art-limit state function taking account of key areas of uncertainty including variations in defect dimensions and material properties. A consequence model was used to determine the possible effects on the local population if a rupture of the pipeline was to occur. The consequence model was used to determine the amount of thermal dose that personnel, in the vicinity of the release, might receive, taking account of the transient nature of the gas flow. The mitigating effects of nearby buildings that would afford shelter from the effects of the thermal radiation levels were naturally taken into account. The results were expressed in terms of an F/N curve and assessed against the risk criteria contained in IGE//TD/1. It was concluded from the analysis that the proposed design did not pose an unacceptable level of risk and moreover that part of the proposed heavy wall section was unnecessary. However, in the interests of conservatism our customer proceeded with the original design. This paper describes the modelling technique used by AFAA and clearly presents the results and conclusions of the analysis.