One of the challenges of transporting Natural Gas Liquids (NGL) is to ensure that the flow should be delivered with standards of safety, reliability, and efficiency while conducting repairs on the pipeline. This paper discusses the difficulties that had to be overcome to repair a damaged NGL pipeline by third parties performed in the Andean Mountains in Ayacucho, Perú, on NGL pipeline operated by Compañía Operadora de Gas del Amazonas (COGA). This pipeline and a parallel one also operated by (COGA) are the main source of supply of NGL and Natural Gas (NG) to the city of Lima, capital of Perú. To repair the Third-Party damage, an emergency committee COLE by its acronym in Spanish (Local Emergency Operative Committee) was formed with the purpose to coordinate the actions for the execution of the repair and meet the Quality, Safety, Social and Environment standards. The committee had an important tool, the Operational Contingency Plan, which provided guidelines for dealing with an emergency. The job required isolating a section of 14-inch NGL transportation pipeline and a bypass to keep the pipeline operational. The work had a tight schedule that needed to be followed to reduce the environmental, safety and service risks. The situation presented several challenges including the use of double barriers to safeguard personnel and facility equipment during the pipeline repair. This double block methodology had to be applied to meet environmental and safety concerns. The damage was located at 4,495 meters above sea level (masl). The strike caused an NGL leak resulting in the installation of an NGL containment and storage system. This location lacked the logistical facilities for the attention of a pipe repair operation, adverse conditions of cold climate, desolate land and other conditions that had to be overcome. This paper discusses how social, safety, environment and logistical challenges were overcome to repair a damaged caused by third parties in an NGL pipeline, which resulted in timely repair completion and uninterrupted flow of NGL.

Canada and Australia are remarkably similar countries. Characteristics such as geography, politics, native land issues, and population are notably similar, while the climate may be considered the most obvious difference between the two countries. The pipeline industries are similar as well, but yet very different in some respects too. This presentation will explore some of the similarities and differences between the pipeline industries in both countries. The focus of the discussion will be mainly on long-distance, cross-country gas transmission pipelines. The author of this paper spent 4 years working for TransCanada PipeLines in Calgary in a pipeline design and construction capacity, and has spent 2.5 years working for an engineering consultant firm, Egis Consulting Australia, in a variety of roles on oil and gas projects in Australia. Topics to be addressed include the general pipeline industry organisation and the infrastructure in both countries. The history of the development of the pipeline industry in each country provides insight as to why each is organised the way it is today. While neither system is “better” than the other, there are certain advantages to Canada’s system (nationally regulated) over Australia’s system (currently state-regulated). The design codes of each country will be compared and contrasted. The pipeline design codes alternate in level of detail and strictness of requirements. Again, it cannot be said that one is “better” than the other, although in some cases one country’s code is much more useful than the other for pipeline designers. Construction techniques affected by the terrain and climate in each country will be explored. Typical pipeline construction activities are well known to pipeliners all over the globe: clear and grade, trench, string pipe, weld pipe, coat welds, lower in, backfill and clean up. The order of these activities may change, depending on the terrain and the season, and the methods of completing each activity will also depend on the terrain and the season, however the principles remain the same. Australia and Canada differ in aspects such as climate, terrain and watercourse type, and therefore each country has developed methods to handle these issues. Finally, some of the current and future opportunities for the 21 st century for the pipeline industry in both countries will be discussed. This discussion will include items such as operations and maintenance issues, Canada’s northern development opportunities, and Australia’s national gas grid possibilities.

The climate in which pipeline companies operate continues to change. Industry failures, related to public safety and environmental concerns, are now front page news. New and proposed regulations such as drug and alcohol testing of employees, instruments internal inspection and standardise oil spill response plans, are modifying the way pipeline companies operate. Paralleling this influences, the market place is also changing. Declining domestic production refinery closures and new specification for refined products are altering the pipe line distribution system. All of these changes are presenting new opportunities and many challenges. In 1995, when CONPET S.A.PLOIESTI Formalised Pipeline Integrity Program, the reasons for the program were to: - What is the location to pipeline rehabilitation? - What is failure probability? This paper reviews some aspects of the pipeline accident statistic to the CONSTANTA DIVISION parts of CONPET S.A.PLOIESTI.

In spite of current world economic climates, recognition that alternative energy sources to the traditional fossil fuels has to be explored and understood. One potential energy source being researched and developed is hydrogen gas. Currently the most economical method of transporting large quantities of hydrogen gas is through steel pipelines. It is well known that hydrogen embrittlement has the potential to degrade steel’s mechanical properties when hydrogen migrates into the steel matrix. Consequently, the current pipeline infrastructure used in hydrogen transport is typically operated in a conservative fashion. This operational practice is not conducive to economical movement of significant volumes of hydrogen gas as an alternative to fossil fuels. The degradation of the mechanical properties of steels in hydrogen service is known to depend on the microstructure of the steel. Understanding the levels of mechanical property degradation of a given microstructure when exposed to hydrogen gas under pressure can be used to evaluate the suitability of the existing pipeline infrastructure for hydrogen service and guide alloy and microstructure design for new hydrogen pipeline infrastructure. To this end, the microstructures of relevant steels and their mechanical properties in relevant gaseous hydrogen environments must be fully characterized to establish suitability for transporting hydrogen. Previously data from a US Department of Energy/private sector funded project to evaluate four commercially available pipeline steels alloy/microstructure performance in the presences of gaseous hydrogen was presented in 2010. Interest in this previous work from industry and the ASME B31.12 Hydrogen Piping and Pipeline Systems codes and standards committee resulted in additional funding for continued evaluation of additional pipeline steel alloys/microstructures in the presences of gaseous hydrogen. Samples from API grades X52 (1960’s and current vintage designs), X70 (1980’s and current vintage) and X80 along with various samples from an X52 induction bend pipe and one pressure vessel steel A516 Gr 70 are being evaluated. Microstructural characterization, fracture toughness and fatigue testing in the presence of gaseous hydrogen at 800 psig and 3,000 psig are being conducted. This paper will describe the fracture toughness results achieved to date on various commercially available pipeline steels used in the existing North American pipeline infrastructure in the presence of gaseous hydrogen at pressures relevant for transport in pipelines. Microstructures and fracture toughness performances will be compared between these in this study along with those published previously. In addition, recommendations for future work related to gaining a better understanding of steel pipeline performance in hydrogen service will be discussed.

Landslides are one of the main threats in maintaining pipeline integrity and depend directly on natural geological and geotechnical conditions. External factors such as weather, rainfall, and others, can trigger land movements and displace the pipeline. The Ecuadorian OCP (Heavy Crude Oil Pipeline) is a buried pipeline going in an East to West direction, crossing 485 kilometers of the Ecuadorian territory. It starts in the Amazon Region (approximately 300 meters above sea level), and then climbs the Andes Mountains (4060 meters above sea level in its tallest portion), to then descend to the shores of the Pacific Ocean. The OCP pipeline crosses many regions with varying climates, varying rainfall patterns, variable morphologies, diversity of soils, and areas affected by tectonic faults, among others. In order to prevent pipeline failures, OCP Ecuador has instituted programs to perform preventive and corrective actions in order to handle the following geological concerns: • Intervention of a specialized geotechnical team to identify and monitor critical points along the pipeline route. This team identifies unstable sites based on the observations of cracks, land movements, or other visual deformations of the pipeline route and its surroundings. • Upkeep of the preventive program. • Execution of third-level studies required to understand specific unstable zones in detail: nature of the subsoil, underground water level, geo-mechanic characteristics, stability factor, and stabilization works. • Geotechnical instrumentation used: inclinometers to search the spread of movement, shifting direction, speed, (landslide location); strain gauges for preventive control of pipeline strain, alert levels, efficiency of stabilization works; and topographic surveys to monitor superficial movements. • Data processing and mapping on GIS Software. • Annual over-flights to detect massive landslides. • Internal inspectors (online-ILI) providing a wide range of information: geometry measurements, curvature monitoring, pipeline displacement, etc. In addition, it allows detection of probable zones depicting soil movement. The purpose of this technical paper is to present the methodology applied by OCP Ecuador to prevent failure of the pipeline along its route.

The ductile fracture arrest capability of gas pipelines is seen as one of the most important factors in the future acceptance of new high strength pipeline steels for high pressure applications. New North-European pipeline project is based on application of X70 pipes designed for high gas pressure of 9,8MPa. To study fracture propagation behavior in cold climate the full scale tests were carried out using longitudinally and spiral welded pipes with different microstructure of base metal. Results of the tests with crack propagation studies in predominately ferrite-pearlite (FP) and acicular ferrite (AF) steels possessing similar Charpy energy are presented. Crack propagation mechanisms in base metal and along spiral weld were studied and are presented with strain distribution along crack.

The fourth report from the Intergovernmental Panel on Climate Change states that “Warming of the climate system is unequivocal...” It further states that there is a “very high confidence that the global average net effect of human activities since 1750 has been one of warming.” One of the proposed technologies that may play a role in the transition to a low-carbon economy is carbon dioxide capture and storage (CCS). The widespread adoption of CCS will require the transportation of the CO 2 from where it is captured to where it is to be stored. Pipelines can be expected to play a significant role in the required transportation infrastructure. The transportation of CO 2 by long-distance transmission pipeline is established technology; there are examples of CO 2 pipelines in USA, Europe and Africa. The required infrastructure for CCS may involve new pipelines and/or the change-of-use of existing pipelines from their current service to CO 2 service. Fracture control is concerned with designing a pipeline with a high tolerance to defects introduced during manufacturing, construction and service; and preventing, or minimising the length of, long running fractures. The decompression characteristics of CO 2 mean that CO 2 pipelines may be more susceptible to long running fractures than hydrocarbon gas pipelines. Long running fractures in CO 2 pipelines may be preventable by specifying a line pipe steel toughness that ensures that the ‘arrest pressure’ is greater than the ‘saturation pressure’ or by using mechanical crack arrestors. The preferred choice is control through steel toughness because it assures shorter fracture lengths. The ‘saturation pressure’ depends upon the operating temperature and pressure, and the composition of the fluid. ‘Captured’ CO 2 may contain different types or proportions of impurities to ‘reservoir’ CO 2 . Impurities, such as hydrogen or methane, have a significant effect on the decompression characteristics of CO 2 , increasing the ‘saturation pressure’. The implication is that the presence of impurities means that a higher toughness is required for fracture arrest compared to that for pure CO 2 . The effect of impurities on the decompression characteristics of CO 2 are investigated through the use of the BWRS equation of state. The results are compared with experimental data in the published literature. The implications for the development of a CCS transportation infrastructure are discussed.

Traditional pipeline technology will be severely challenged as developments continue in arctic regions. Cost-effective solutions to these challenges can be found through innovative technology and its implementation. TransCanada PipeLines has been involved in a series of technology programs that have been implemented in challenging climates including permafrost. In addition TransCanada is also involved in ongoing programs whose aim is to reduce the cost of Northern pipelines whilst at the same time provide structural assurance and reliability. This paper will describe the overall approach to developing cost-effective solutions and how these programs are interconnected. The topics to be covered will include the approach to strain-based design and how TransCanada has been taking advantage of the approach in its implementation of higher strength steels. The work also includes the approach taken in terms of the design for the effect of mismatch between the pipe and weld metal properties. The strain-based approach is also being extended to a structural reliability methodology and the work conducted to date will be briefly discussed. A significant portion of the design of a Northern pipeline relies on the development of a frost heave-thaw settlement methodology and the current philosophy and its validation will be discussed. A prime consideration of the regulatory bodies is the assurance of structural integrity and fracture control plans. The work currently ongoing at TransCanada on fracture safe behaviour will be discussed. Additional discussion on construction related topics will be covered including welding, buoyancy control, directional drilling and trenching.

Effective and successful project management of today’s pipeline projects is a challenging and complex task. For the most part, these complexities are not due to technical issues, but pertain to “soft management issues” (communications, team building/alignment, stakeholder management, etc.) that must be immediately and aggressively addressed during project initiation. That is, a key success factor for these projects is setting up for success, upfront at the very beginning, and ensuring the right resources and processes are in place to manage the “soft side” as the project progresses. This includes initiating continuing processes to check the status of the project team climate, interaction health, and development of a “risk sharing/monitoring” culture.

In the near future, the construction of northern pipelines for transmission of natural gas will begin in North America. Construction in the harsh northern climate, with temperatures as low as −45°C, and remote location will impose unique challenges with respect to protective coatings. It is critical that the design of coatings be adequate to protect the pipelines under long-term, severe environmental conditions, including the extreme climatic conditions that will apply in the North before the pipe is installed and operation begins. There are many quality coatings from which to choose for application on new pipelines. The main issue is in understanding how to select and use coatings on pipelines in new regimes (e.g. Northern pipelines), which may operate in a different environment than do existing pipelines. Uniform, standardized tests that would simulate the conditions during construction and operation of Northern pipelines will allow external pipeline coatings to be selected with confidence regarding anticipated long-term performance under operational conditions. Selection of mainline coatings is important, but there is also a need to focus on field-applied coatings for both repairs and joints. Methodologies and standards that are available to evaluate coatings are reviewed in this paper.

Pipelines in northern climates can be impacted by geohazards that are unique to cold regions. Some of these include frost heave, thaw settlement, solifluction, icings, glaciers, ice-rich slopes, and others. This paper will discuss most of these geohazards as they have been monitored, mitigated, and managed along the Trans Alaska Pipeline (TAPS) and other pipelines in Alaska and Russia. Early analyses of frost heave and thaw settlement of piles concluded that frost heave and thaw settlement would be controlled by installing passive heat removal devices (heat pipes). In permafrost areas heat pipes have generally worked well. In unfrozen terrain or discontinuous permafrost the heat pipes have not been able to maintain stability. Examples of each of these situations will be discussed. Steep rolling terrain makes up a significant part of the TAPS route. Some of the slopes are in permafrost and others are in thawed ground. For the past 15 years, surveillance and monitoring of some of the slopes along the pipeline route has documented the response of slopes in frozen ground. Warmer (that is near 0 degrees C) ice-rich slopes can creep. An example of this is documented on a slope instrumented with inclinometers and thermistors. Other slope movements related to pore pressure increases caused by active layer containment of unfrozen groundwater flows will be discussed. The impact of solifluction zones on pipeline construction and routing will be addressed as it has been managed along the TAPS. Other near surface slope movements that appear to be similar to solifluction have been observed along the pipeline right-of-way on the workpad. This paper will address an interrelationship of these observed slope behaviors. In doing this the interaction of slope seeps and the freeze front as it forms in fall and then recedes in spring and summer is compared to observations of engineered projects. Icings can be observed in several locations along TAPS. In some cases these can be related to slope movements. In other cases the icings have reached the aboveground and caused maintenance issues. TAPS was designed to avoid future surges of several large glaciers. In most years these glaciers have retreated and have not been a significant issue. A recent large earthquake caused a landslide on the largest glacier near TAPS and resulted in some review of the activity on that glacier. In 2002 a large earthquake centered near TAPS caused liquefaction in some areas, breakage of ice in lakes in some locations, and sand boils very close to the pipe. These observations will be related to the thinly frozen active layer over a deep talik during the earthquake.

Microalloyed steels possess good strength, toughness and excellent weldability, all of which are necessary attributes for oil and gas pipelines in northern climates. These properties are attributed in part to the presence of nano-sized Nb/Ti carbide precipitates. In order to understand the strengthening mechanisms and to optimize the strengthening effects, it is necessary to quantify the size distribution, volume fraction and chemical speciation of these precipitates. However, characterization techniques suitable for quantifying fine precipitates are limited. A matrix dissolution method has been developed to extract the nano-sized precipitates from microalloyed steels. The results from Grade 100 microalloyed steel are presented in this paper.