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Codes, Standards and Regulations: Integrity Through Risk Management

2000;():V001T01A001. doi:10.1115/IPC2000-100.
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1999 marks an important anniversary for Enbridge Pipelines Inc. of Canada and its U.S.-based affiliate, the Lakehead Pipe Line Company Ltd.: for 50 years we have been the primary link between the large oil production areas of western Canada and major market hubs in the U.S. midwest and eastern Canada. In retrospect, this strong history of success is chiefly due to thorough and logical planning and choice selection in all aspects of company endeavors.

At Enbridge, as in countless other firms in a wide-range of industries, decision making was often the product of expert consensus and years of solid experience in dealing with similar situations. This approach has worked well for Enbridge and our stakeholders for five decades, as evidenced by the reliability, efficiency, and safety record of our pipeline system. However, as the millenium nears, we are increasingly finding formalized processes that integrate quantitative models and qualitative analysis helpful in planning and execution for both the short- and long-term. Several broad trends at the root of this movement include the heightened pace of change; the increasingly complex web of relevant factors; the growing magnitude of the consequences associated with sub-optimal decisions; the need for thorough documentation; and the apparent benefits of a framework that enables objectivity and consistency. In short, an approach that completely and systematically evaluates the multitude of dynamic factors that affect the ultimate outcome of the matter at issue is necessary. Although the term “risk management” is now often used to describe this process, Enbridge — along with many other responsible firms in the pipeline operating and other industries — has always practiced the underlying principles.

This paper addresses the background of “risk management” in both the Canadian and U.S. pipeline industry, as well as accepted theory. It also encompasses the progression of risk management at Enbridge Pipelines, up to and including current initiatives. The usefulness of risk analysis, risk assessment, and risk management tools will be discussed, along with the overriding necessity of a well thought-out process, firm corporate commitment, and qualified expertise. Much of the focus will address the ongoing evolution and maturity of a comprehensive and well-integrated risk management program within the Enbridge North American business units. The criticality of maintaining focus on the core business function — in this case, pipeline operations — will also be addressed. In addition, past learning’s as well as future opportunities and challenges will be reviewed.

Commentary by Dr. Valentin Fuster
2000;():V001T01A002. doi:10.1115/IPC2000-101.
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Chevron Canada Resources recently completed a hot tap on the Simonette high-pressure sour gas transmission line near Grande Prairie, Alberta. The hot tap was required to bring on new production into the Simonette pipeline without shutting in existing production. The hot tap was completed under full line pressure and gas/condenstate flow during the winter with temperatures averaging −20°C.

The design pressure of the 12 “ Gr. 359 Cat II pipeline is 9930 kPa and the line operates at 8200 kPa. The gas in the main transmission line is approximately 2% H2S and 4% CO2. The gas being brought on through the 4″ hot tap tie-in was 21% H2S and 5% CO2. At the tie-in point the transmission line temperature was 3°C.

Safely welding on the pipeline under these conditions was a considerable technical challenge. In welding sour service lines it is critical that the final weld hardness be below Vickers 248 micro hardness. This can be very difficult to achieve when welding on a line transporting a quenching medium of gas and condensate. In addition, hydrogen charging of the steel from operation in sour service can lead to hydrogen embrittlement during welding.

Ludwig & Associates developed the hot tap weld procedure and extensively tested the procedure to ensure that suitable weld microhardness was achievable under pipeline operating conditions. As part of the procedure development the welder who would perform the hot tap was tested repeatedly until he could confidently and successfully complete the weld. During fieldwork, the welding was rigorously monitored to ensure procedural compliance thereby minimizing the possibility of elevated hardness zones within the completed weldment.

This paper will detail with the technical development of the hot tap welding procedure and the successful field implementation.

Commentary by Dr. Valentin Fuster
2000;():V001T01A003. doi:10.1115/IPC2000-102.
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TransCanada is meeting the challenges of enhanced pipeline safety and reliability in a competitive environment by combining new technologies in an innovative way to help manage risk. TransCanada is building on existing capabilities with development of a new pipeline risk assessment system to identify and prioritize segments on the 38,000 km system that will require particular attention for condition monitoring and mitigation. The system wide risk-based system incorporates a data storage and maintenance asset, tools for risk analysis, as well as tools to view, summarize and learn from the data, including a geographical information system. First use of the new system occurred in 1999.

Commentary by Dr. Valentin Fuster
2000;():V001T01A004. doi:10.1115/IPC2000-103.
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Risk is a function of the probability and consequence of an event that negatively impacts pipeline operations. These events may range from the shut-in of a compressor to a pipeline rupture. In order to quantify risk, it is important to have a thorough method of evaluating the probability and severity of the incident. Until recently, the methods used to assess risk have been mostly subjective and qualitative. Enhanced methods are now available that allow pipeline companies to gain a better understanding of the true risk and to realistically determine the availability and reliability of the pipeline. These methods facilitate balancing the cost of extra safeguards or protection layers with the actual risk of an event occurring, ultimately improving the financial success of a pipeline company.

Topics: Pipelines , Risk
Commentary by Dr. Valentin Fuster

Codes, Standards and Regulations: International Standards and Regulations

2000;():V001T01A005. doi:10.1115/IPC2000-104.
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The proper use of risk assessment / risk management principles and tools can help the pipeline operator maintain the flow of pipeline integrity data and the analysis of this data by responsible parties. By the use of an algorithm (series of relationships) the rules for performing a mathematical expression of risk can be established and the attributes identified. These measures may aid in the rational, prioritization of resources and identification of improvement opportunities. Operating companies do a good job of maintaining their pipelines, but the decision as to where to allot resources in some cases may be generally a reactive measure. Advances in Pipeline Risk Management Software and Pipeline Inspection tools now allow a proactive approach to Pipeline Integrity Maintenance. This paper explains some of the risk management tools available to pipeline companies.

Commentary by Dr. Valentin Fuster
2000;():V001T01A006. doi:10.1115/IPC2000-105.
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On 1 August 1999 a revised version of the National Energy Board’s (NEB) Onshore Pipeline Regulations came into effect. The NEB undertook the development of the Onshore Pipeline Regulations, 1999 (OPR-99) [1] with the view that regulations should be less prescriptive and more goal-oriented. The shift to goal-oriented regulations gives companies more discretion in the selection of the methods employed to meet NEB requirements. The onus is on each company to demonstrate the adequacy and effectiveness of the methods used.

This paper describes the changes to the NEB’s approach to regulation and reports on the issues identified since OPR-99 came into force.

Commentary by Dr. Valentin Fuster
2000;():V001T01A007. doi:10.1115/IPC2000-106.
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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 21st 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.

Topics: Pipelines
Commentary by Dr. Valentin Fuster

Codes, Standards and Regulations: Risk-Based Standards and Regulations

2000;():V001T01A008. doi:10.1115/IPC2000-107.
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The gas industry has an excellent safety record in operating high pressure transmission pipelines. Nevertheless, it is important that pipeline operators have an understanding of the possible consequences of an accidental gas release, which may ignite, in order to help manage the risks involved. This paper describes two full scale experiments, conducted as part of a research programme into the consequences of pipeline failures, undertaken by an international collaboration of gas companies. The experiments involved the deliberate rupture of a 76km length of 914mm diameter natural gas pipeline operating at a pressure of 60 bar, with the released gas ignited immediately following the failure. Instrumentation was deployed to take detailed measurements, which included the weather conditions, the gas outflow, the size and shape of the resulting fire, and the thermal radiation levels. The results provide important data for the validation of mathematical models, used in developing risk assessment methodologies, and in establishing those standards and design codes for gas pipelines that are risk based.

Commentary by Dr. Valentin Fuster
2000;():V001T01A009. doi:10.1115/IPC2000-108.
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The gas industry has an excellent safety record in operating high-pressure transmission pipelines. Nevertheless, it is important that pipeline operators have an understanding of the consequences of possible accidental gas releases, in order to help manage the risks involved. This paper presents a programme of full scale experiments, undertaken by an international collaboration of gas companies, to study the consequences of both unignited and ignited releases of natural gas from simulated punctures and rips in a 900mm diameter above-ground transmission pipeline. Experimental parameters varied during the programme included release orifice size and shape, release pressure, release height, release direction, wind speed and wind direction. Instrumentation was deployed to obtain detailed data on the dispersion of gas, the ignitability of the gas cloud produced, the levels of incident thermal radiation and the resulting fire size and shape, following ignition. The results provide important data for the validation of mathematical models, used in developing risk assessment methodologies for gas pipelines, and in establishing those standards and design codes that are risk based.

Commentary by Dr. Valentin Fuster
2000;():V001T01A010. doi:10.1115/IPC2000-109.
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After completing an extensive risk assessment stage, PGPB’s Risk Management Team was ready to move towards Risk Management philosophy. Comparing PEMEX’s algorithm with the typical values of the industry enabled the risk assessment approach adopted in PGPB. As a result of a comprehensive study that gathered several of the users of the same analysis tool, an optimised and normalised algorithm was obtained to support the risk assessment programme and comply with the company’s policies.

The risk assessment stage included more than 1,700 kilometres of LPG pipelines and 3,500 kilometres of natural gas. This stage was granted as final until consistent risk values were achieved in every segment section. To move into the Risk Management stage a comprehensive study was performed to define tolerable risk criteria for PGPB pipeline network.

Topics: Pipelines , Risk
Commentary by Dr. Valentin Fuster
2000;():V001T01A011. doi:10.1115/IPC2000-110.
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In the past, a significant amount of investigation into the development of critical buckling strain limit state criteria for pipelines has been conducted and a number of critical strain criteria have been proposed. However, the availability of comparative experimental data that have been collected under representative pipeline operating conditions has been somewhat limited.

Over the past eight years, more than 50 full-scale pipeline tests under representative field conditions have been conducted at the University of Alberta (U of A) in Edmonton, Alberta, Canada. Experimental parameters have included the diameter-to-thickness (D/t) ratio, the internal pressure to yield pressure ratio (p/py), and the presence or absence of a circumferential girth-weld at the mid-height of the specimen. Critical strain values were determined for the majority of these test specimens and were then compiled in an attempt to assess current limit state design criteria for governing critical buckling strains.

This paper summarizes the critical buckling strain values from a total of 38 tests that have been conducted at U of A at the present time. The experimental results are then used to assess a number of previously developed critical strain criteria.

Topics: Buckling
Commentary by Dr. Valentin Fuster

Design and Constructions: General (Design and Construction)

2000;():V001T02A001. doi:10.1115/IPC2000-111.
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Purging of a gas pipeline is the process of displacing the air/nitrogen by natural gas in an accepted constant practice in the natural gas pipeline industry. It is done when pipelines are put into service. Gas Pipelines are also purged out of service. In this case they are filled with air or other neutral gases.

Traditionally, “purging” a newly constructed pipeline system is carried out by introducing high pressure gas into one end of the pipeline section to force air out of the pipeline through the outlet until 100% gas is detected at the outlet end. While this technique will achieve the purpose of purging air out of the pipeline, it gives little or no consideration to minimizing the emission of methane gas into the atmosphere.

With the advances of the pipeline simulation technology, it is possible through simulation to develop a process to minimize the gas to air interface and thereby minimize the emission of methane gas. In addition, simulation can also be used to predict the timing of purging and loading of the pipeline. Therefore, scheduling of manpower and other activities can be more accurately interfaced.

In this paper a brief background to purging together with a summary of current industry practices are provided. A simplified purging calculation method is described and a simulation technique using commercially available software is provided for planning purging and loading operations of gas pipeline systems. An Example is provided of a recently constructed pipeline (Mayakan Gas Pipeline System) in Mexico to demonstrate how the planning process was developed and carried out through the use of this simulation technique. Simulation results are compared with field data collected during the actual purging and loading of the Mayakan Pipeline.

Commentary by Dr. Valentin Fuster
2000;():V001T02A002. doi:10.1115/IPC2000-112.
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An 800-mile natural gas pipeline is being considered as part of an Alaskan liquefied natural gas (LNG) project. Concepts to maximize the pipeline’s value and minimize its cost are considered. The pipeline’s operating pressure has been synchronized with the LNG plant’s inlet pressure to achieve system efficiencies. Line pipe steels are optimized to address pressure, fracture and geotechnical issues. An advanced approach to designing and operating a gas pipeline in discontinuous permafrost is evaluated. Construction methods and strategies have been developed in areas such as trenching and winter construction. Finally, future work to further develop these concepts is identified.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T02A003. doi:10.1115/IPC2000-113.
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The GasPacífico Project involved the construction of 543 kilometres of NPS 20 and NPS 24 high pressure gas pipeline to connect the natural gas reserves in the Province of Neuquen, Argentina to the industrial and domestic demand in and near the city of Concepción, Chile. The pipeline crossed the Pampas of Argentina, the imposing Andes mountain range, the Coastal mountain range and the highly populated agricultural terrain of the Central Valley (740 individual landowners in total) leading to the west coast of Chile.

TransCanada International Ltd. was responsible for the overall project management of the GasPacifico Project which included design, construction and contract administration. In March 1998, the Project Team began the procedure to pre-qualify bidders, to prepare contract documents and to call for bids in preparation for the selection of construction contractors for the project. Contracts were awarded on July 30, 1998.

The proper selection of the Contractors was considered of paramount importance in the project because of the high degree of difficulty of the project, the budget constraints, and the very limited time available for construction.

The details of the process established for the selection of the Contractors for the GasPacífico Project as presented in this paper include:

• the criteria for the pre-qualification of the bidders;

• the technical evaluation format;

• the commercial evaluation format;

• sensitivity studies for unit rate items and extra work;

• the application of the technical/commercial evaluations to the final selection.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T02A004. doi:10.1115/IPC2000-114.
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In 1997 Alyeska Pipeline Service Company (Alyeska), operator of the Trans Alaska Pipeline System (TAPS), identified two mainline valves that required repair. The remote location, size and scale of these valves combined with the hydraulic profile of the pipeline presented significant challenges for the repair of the valves. Both valves were located such that the pipeline could not be simply drained to allow for repair or replacement. To drain the locations would have required facilities to drain, store, and re-inject or transport 108,000 bbls of oil. Isolation of these valves utilizing STOPPLES® reduced the volume of oil that needed to be handled but required repairs to be conducted by personnel working in a confined space behind the STOPPLES®.

The conceptual repair plan for each of these valves was evaluated through a Peer Review/Risk Assessment to validate or revise the isolation and repair concepts. This process provided the communication and evaluation methods that were necessary to gain acceptance of the use of STOPPLES® for isolation by the organizations performing the work, state and federal agencies monitoring the work, and TAPS stakeholders.

The work on Remote Gate Valve 80 (RGV 80) and Check Valve 122 (CKV 122) was completed during a single 28 hour pipeline shutdown in September of 1998. Both valves were isolated with STOPPLES® to minimize the crude handling requirements. This paper describes the repair of these valves from the conceptual design through the completion of the work.

Topics: Pipelines , Valves
Commentary by Dr. Valentin Fuster
2000;():V001T02A005. doi:10.1115/IPC2000-115.
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An overview of recent developments of tuned vibration absorbers (TVAs) for vibration suppression is presented. The paper summarizes some popular theory for analysis and optimal tuning of these devices, discusses various design configurations, and reviews the recent application of TVAs to control wind-induced oscillations of pipelines above the Arctic Circle. Although the wind-induced pipeline vibrations are relatively small, the accumulation of vibration cycles can cause fatigue at pipeline joints. The TVAs used in this application have reduced the RMS displacements of the pipeline by as much as a factor of seven. Additionally, the paper introduces a new overhead TVA installation on the pipeline for accommodating environmental considerations.

Commentary by Dr. Valentin Fuster
2000;():V001T02A006. doi:10.1115/IPC2000-116.
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The start of the new millennium will see companies in the oil and gas industry faced with a dual challenge. Not only will they have to undertake exploration in more demanding terrain and environments, but they also face far more competition in what they previously regarded as their traditional marketplace. The goal of meeting both shareholder and customer needs, while simultaneously attempting to increase market share by becoming more competitive, will be paramount if this success is to be achieved. While a number of strategies have been developed over the last decade in an attempt to achieve and balance these financial goals, the control and reduction of costs play a significant part in all such ‘cost effective’ programs.

Past approaches have targeted the organisational structure, internal processes and strategic advantage through acquisitions, mergers and downsizing. However, any gains realised by such programs must be continuously improved upon by implementing innovative approaches to future reductions and controlling costs. Some companies have shifted the focus from internal cost scrutiny to influencing and ultimately controlling external factors of cost. The supply chain offers a tremendous opportunity to drive out costs, one such approach being to partner with the best suppliers of key components to shorten delivery times while minimizing life cycle costs. It is therefore paramount that one distinguishes between those who are simply suppliers and that smaller group who are the best suppliers, all the while fostering a win-win relationship by sharing growth and profitability.

This paper will introduce the concepts of the Supplier Performance Measurement Process (SPMP), which NOVA / TransCanada introduced in late 1997 to measure and manage its suppliers’ performance in the provision of a few strategically critical commodities. To provide context for this paper two such commodities, high pressure line pipe and high integrity pipe coatings are addressed in some detail. The application of the process to these commodities alone yielded a capital cost reduction of 6%. The paper explains in practical terms, the steps involved in the implementation of SPMP, and provides a simple process for eliciting feedback on the efficacy of the procurement process.

Commentary by Dr. Valentin Fuster
2000;():V001T02A007. doi:10.1115/IPC2000-117.
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The floating-roof tank has been the most widely used method of storage of volatile petroleum products since the first demonstration b Chicago Bridge & Iron Company (CB&I) in 1923. There have been many changes and design improvements to that first pan-style-floating roof.

A floating roof is a complex structure. It must be designed to remain buoyant even when exposed to combined loads from varying process, weather and product conditions. There is a continued demand for improved floating-roof tanks to store a wide range of petroleum and petrochemical products in compliance with state and federal environmental regulations. Floating roofs are used in open top tanks (EFRT), inside tanks with fixed roofs (IFRT), or in tanks that are totally closed where no product evaporative losses are permitted for release to the atmosphere. This very special type of installation is referred to as a zero emission storage tank (ZEST). Products that might have been stored in basic fixed roof tanks must now utilize a floating roof to limit evaporative emissions to the atmosphere. High vapor pressure condensate service and blended heavy crude oils also present new design challenges to the floating roof tank industry.

This paper will review the most prominent styles of floating roofs from 1923 to the present. Design and operating limits for current da floating-roof structures are presented. New trends in environmental regulations and the potential impact on the design and operation of floating-roof tanks will be presented. Current maintenance practices and the effect on Life Cycle Cost Management of the storage syste are also reviewed.

Commentary by Dr. Valentin Fuster

Design and Constructions: Geotechnical

2000;():V001T02A008. doi:10.1115/IPC2000-118.
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This paper outlines some of the recent design developments and construction support efforts of the authors and their colleagues that reduce the capital cost and enhance the design integrity and environmental performance of pipelines buried in permafrost.

These new design concepts can significantly reduce the expected cost of a major northern gas pipeline relative to historical conceptual costs.

Recent North Slope of Alaska oil developments have successfully utilized new design concepts for warm buried crossings of major rivers to achieve certain environmental and economic objectives. The fully buried oil pipeline from Normal Wells, NWT, originally designed as a cold pipeline, has successfully operated in recent years as an ambient temperature system. These developments widen the application and improve the potential cost advantage of buried oil pipelines over above grade pipelines in permafrost.

Commentary by Dr. Valentin Fuster
2000;():V001T02A009. doi:10.1115/IPC2000-119.
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The Norman Wells pipeline is an 869 km long, small diameter, buried, ambient temperature, oil pipeline operated by Enbridge Pipeline (NW) Inc. in the discontinuous permafrost zone of northwestern Canada. Since operation began in 1985, average oil temperatures entering the line have been maintained slightly below 0°C, initially through constant chilling year round and since 1993 through a seasonal cycling of temperatures through a range from −4 to +9°C. At one location, 5 km from the inlet at Norman Wells, on level terrain in an area of widespread permafrost, uplift of a 20 m segment of line was observed in the early 1990s. The uplift gradually increased and by 1997 the pipe was exposed 0.5 m above the ground surface.

Detailed studies at the site have included field investigations of terrain and thermal conditions, repeated pipe and ground surface elevation surveys, and annual Geopig surveys. The field work has revealed that the section of line was buried in low density soils, thawed to depths of 4 m on-right-of-way, and not subjected to complete refreezing in winter. The thaw depths are related to surface or near-surface flows from a nearby natural spring, as well as to the development of a thaw bulb around the pipe in the cleared right-of-way. Icings indicative of perennial water flow occur commonly at this location in the winter.

The pipe experienced annual cycles of heave and settlement (on the order of 0.5 m) due to seasonal freezing and thawing within the surrounding low density soils. The pipe reached its highest elevation at the end of each winter freezing season, and its lowest elevation at the end of the summer thaw period. Superimposed on this heave/settlement cycle was an additional step-like cycle of increasing pipe strain related to thermal expansion and contraction of the pipe. A remedial program was initiated in the winter of 1997–98 in order to curtail the cumulative uplift of the pipe, reduce the increasing maximum annual pipe strain and ensure pipe safety. A 0.5 m cover of sandbags and coarse rock was placed over the exposed pipe segment. Continued pipe elevation monitoring and annual Geopig surveys have indicated that both seasonal heave/settlement and strains have been reduced subsequent to the remedial loading. Introduction of a gravel berm has also altered both the surrounding hydrologic and ground thermal regimes.

Topics: Wells , Pipelines , Pipes , Soil , Permafrost
Commentary by Dr. Valentin Fuster
2000;():V001T02A010. doi:10.1115/IPC2000-120.
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In today’s competitive environment, oil and gas pipeline companies must search for materials and construction methods that reduce project capital costs while maintaining the quality and integrity of the pipeline. Pipeline buoyancy control can be a major cost of large diameter pipelines, particularly for routes that cross wet terrain.

In 1999, Enbridge Pipelines (Athabasca) Inc. constructed the 541 km NPS 30 Athabasca Pipeline from Fort McMurray to Hardisty, Alberta. Because of the substantial areas of muskeg that the pipeline route traversed, Enbridge selected a pipeline anchor system as the primary means of buoyancy control for the project. This new technology saved greater than an estimated $12 million CDN when compared with the cost of concrete set-on weights, which is the traditional method of controlling buoyancy of pipelines in North America.

This paper describes the design of the anchor system selected for this project, details the calculations performed to determine anchor spacing, documents the challenges which were overcome during installation, and analyses the cost savings which were achieved by the use of this technology.

Topics: Buoyancy , Screws , Pipelines
Commentary by Dr. Valentin Fuster

Design and Constructions: Materials

2000;():V001T02A011. doi:10.1115/IPC2000-121.
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The potential for weld hydrogen cracking, that can also manifest itself as delayed cracking due to formation well after weld deposition, is controlled by three factors: the presence of hydrogen, the susceptibility of the weldment microstructure and tensile stresses. The tensile stresses promoting hydrogen cracking may result from either welding residual stresses or construction or operations based stresses, while the susceptibility of a microstructure is a function of its carbon equivalent and cooling rate. Since all arc welding processes introduce hydrogen into welds to some extent, and in general, base material selection and weld stress levels are not controllable in welding procedure development, the prevention of hydrogen cracking must be accomplished through hydrogen management. This paper describes a means of considering the roles of welding procedure parameters (heat input, preheat, post-heat, inter-pass temperature and time, etc.) in the management of hydrogen in multi-pass welds to preclude delayed cracking. Some results obtained using a multi-pass weld hydrogen and thermal diffusion model are presented to demonstrate the models utility in understanding the effects of welding procedure parameter effects on the risk of delayed cracking.

Commentary by Dr. Valentin Fuster
2000;():V001T02A012. doi:10.1115/IPC2000-122.
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Reliability evaluation of welded structures by mechanical testing of weld heat-affected zones (HAZs) has become general practice throughout the world. HAZs of steel welded joints show a gradient of microstructure from the fusion line to the unaffected base metal. This study is concerned with a correlation between the microstructural change and the fracture characteristics in HAZs of both seam and girth welds of API 5L X65 pipeline steel, which is generally used for natural gas transmission pipelines in Korea. The focus in present study was the investigation of macroscopic fracture behavior of the various regions within HAZ. Changes in microstructure and impact toughness were observed using synthetic HAZ specimens as well as actual HAZ specimens. To evaluate the macroscopic toughness of actual HAZ, Charpy V-notch impact test was performed.

Commentary by Dr. Valentin Fuster
2000;():V001T02A013. doi:10.1115/IPC2000-123.
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API 5L X65 steel pipes with a 17.5mm wall thickness and 762mm in outer diameter were welded using an orbital automatic welding process. Flux Cored Arc Welding (FCAW) and Gas Tungsten Arc Welding (GTAW) consumables were utilized to evaluate automatic the welding process. Manual welds were deposited using GTAW with ER70S-G filler metal for the root pass and Shielded Metal Arc Welding (SMAW) with low hydrogen E9016-G electrode for the remaining passes. Charpy impact test, CTOD (Crack Tip Opening Test) test and micro-hardness test on the weld metal were carried out and the effects of weld metal composition and microstructure on the weld metal toughness were investigated. The filler metals that have superior fracture toughness were E80T1-K2 and E71T-1 of FCAW process and ER80S-G of GTAW process. The filler metals that have proper hardness were E80T1-K2 and E71T-1 of FCAW process.

Commentary by Dr. Valentin Fuster
2000;():V001T02A014. doi:10.1115/IPC2000-124.
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Recent construction of pipelines in Canada has seen a trend towards higher operating pressures with greater wall thicknesses and/or higher strength pipe. At the same time, Grade 550 linepipe is becoming accepted as the standard for new construction. The production of high strength grades in wall thicknesses over 12.5 mm presents a new challenge. The increased wall thickness and higher strengths tax manufacturing equipment to the fullest. IPSCO has recently completed the production of 1150 km of 14.2 mm spiral-welded Grade 483 linepipe for the Alliance Pipeline. This paper will examine the technical issues associated with the production of this pipe at the Regina steel mill. Successful production trials at IPSCO’s new steel mill in Montpelier, Iowa, which incorporates new process technology, are also described. Production of linepipe with strength exceeding 550 MPa will also be examined.

Commentary by Dr. Valentin Fuster
2000;():V001T02A015. doi:10.1115/IPC2000-125.
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The aim of this study was to characterize the microstructure of microalloyed linepipe steels. The steels investigated were X70 (0.04 wt% C - 0.02 wt% Ti - 0.07 wt% Nb) and X80 (0.04 wt% C - 0.025 wt% Ti - 0.09 wt% Nb) steels, where the numbers refer to their specified minimum yield strength (SMYS) in ksi. This class of steels has the advantage of high strength and good toughness combined with minimal wall thickness (15.5 mm for X70 steel). These attributes result in considerable cost savings when installation of several hundreds of kilometers of pipeline is required for oil and natural gas recovery and transport.

The present study focused on phase identification and quantification, distribution of alloying elements and inclusions and segregation effects. Both steels were primarily composed of a mixed ferrite structure, i.e., polygonal ferrite and acicular ferrite/bainite, with characteristic low angle grain boundaries and high dislocation densities. The proportion of acicular grains was higher for the X80 steel. Pockets of retained austenite, exhibiting a Kurdjumov-Sachs orientation relationship (KS-OR) with the adjoining ferrite, were found in both steels.

Five general classes of precipitates were identified in both steels: 1) Very large (2–10 μm) cuboidal TiN particles nucleated on inclusions; 2) large (0.1–1.0 μm) cuboidal TiN particles; 3) medium sized (30–50nm), irregular shaped Nb-Ti carbonitrides; 4) fine (<20nm), rounded precipitates of Nb carbonitrides with traces of Mo; 5) very fine dispersed precipitates (<5 nm in size). For X80 steels many of the large TiN precipitates were observed with Nb-rich carbonitrides precipitated epitaxially on them.

Inclusion content and morphology were analyzed in both steels. The inclusions in X70 steels were found to be primarily CaS with significant amounts of Al, O, Ti, Fe and Mn. They were essentially spherical in shape with small elliptical distortions along the rolling direction and across the width of the plate. The morphology of the inclusions in the X80 steel was very similar, however, they showed higher Mn levels.

Topics: Steel
Commentary by Dr. Valentin Fuster
2000;():V001T02A016. doi:10.1115/IPC2000-126.
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In the conditions of sub-Arctic winter it is not unusual for the ambient temperatures to drop as low as −40°C. Insulated pipes overcoated with extruded polyethylene may fail, sometimes drastically due to mechanical impact which can rupture the outer polyethylene layer and damage the polyurethane foam.

A systematic investigation into the main reasons for this failure mode was conducted, resulting in specific recommendations to permanently solve this problem.

Commentary by Dr. Valentin Fuster
2000;():V001T02A017. doi:10.1115/IPC2000-127.
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The demand for steel for the production of pipelines to transport gas and oil containing hydrogen sulphide prompted the development of steel that is resistant to hydrogen induced cracking (HIC).

During the past two decades, combined research efforts in the areas of product and process metallurgy have made it possible to satisfy most of the main requirements for grades X-42 and X-60 microalloyed steel for mildly acidic (pH = 5) H2S environments. Building on the experience acquired in the area of microalloyed steel for a mildly acidic (pH ∼ 5) H2S environment, the industry launched a program to develop steel that would satisfy new requirements for H2S-resistant pipelines under NACE conditions (TM0177, pH∼3). In order to develop these steels, it was necessary to define qualitatively and quantitatively the specific effects on H2S resistance of the multiple intrinsic parameters of the product itself as well as those resulting from the process.

In this paper, data will be presented that have made it possible to relate the HIC performance of steels to chemical content, inclusion levels and thermomechanical treatment parameters.

Topics: Steel , Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T02A018. doi:10.1115/IPC2000-128.
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Engineering ceramics have a growing application potential for the wear- and corrosion protection of piping systems and for manufacturing of working parts of rotating equipment in mining and -mineral industries, including oil, gas, coal, ores, and others. The alumina, zirconia, alumina-zirconia, and silicon carbide-based engineering ceramics developed and manufactured by Ceramic Protection Corporation used for extraction, processing, conveying, and dust collection equipment are reviewed. These ceramics have high hardness (greater than the majority of processed materials) and mechanical strength, moderate fracture toughness (fracture toughness of zirconia ceramics is close to metal fracture toughness), excellent wear- and corrosion resistance, ability to withstand high temperatures (greater than 1000°C) and thermal shocks. These ceramics successfully withstand various solid and liquid abrasive media transported at high velocity and turbulence, under high pressure and cavitation. In terms of wear- and corrosion resistance ceramics are significantly stronger than hard steels widely used in the piping systems, and may successfully replace hard metals such as tungsten carbide. The features of the compositions, microstructure, and properties of these ceramics are considered. The wear test results are discussed; the factors effected wear resistance are emphasized. In dependence on the working conditions and the product design, a ceramic material may be chosen or developed in each particular case.

The manufacturing processes of the considered ceramics and the installation technique are described. These ceramics are produced on the large-scale basis, and the parts may be manufactured in accordance with the customer design and requirements. The ceramic components may be manufactured as monolithic bodies, including bodies with the complicated shapes, or as tiles; in both cases they are easily installed into equipment. The main features of the ceramic product design are discussed. Pipe lining, including elbows, T- and Y-sections, cyclones and reducers, nozzles, pump parts, seals, valves, and others made from these ceramics are successfully used in the most important sections of piping systems and rotating equipment. The use of the ceramics reduces the wear- and corrosion problems, increases the life cycle of equipment without damage and shutdowns.

Commentary by Dr. Valentin Fuster
2000;():V001T02A019. doi:10.1115/IPC2000-129.
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Many models and formulae have been put forward, over the years, for the determination of the toughness necessary for the arrest of propagating ductile fracture in gas pipelines. One of the first, and most prominent, was that developed by Battelle Columbus Laboratories for the Pipeline Research Committee of the American Gas Association. As originally embodied, the model involved the comparison of curves expressing the variation of fracture velocity and of decompression wave velocity with pressure (the “two-curve model” — TCM). To aid in analysis, at a time long before a computer was available on every desk, a “short formula” (SF) was developed that provided a good fit to the results of the TCM for a substantial matrix of conditions. This SF has subsequently been adopted by several standards bodies and used widely in the analysis of the results of full-scale burst tests. Since the original description of the derivation of the SF is to be found only in a report to the PRC dating back to the Seventies, many in the pipeline industry today are left without a full appreciation of its range of validity. The present paper briefly discusses the original intent of the SF as a substitute for the TCM, and presents the results of extensive calculations comparing the results of the two. It can be concluded that the SF provides an excellent estimate of the results of the TCM over a very wide range of design and operating parameters, within the limitations inherent in the method.

Commentary by Dr. Valentin Fuster
2000;():V001T02A020. doi:10.1115/IPC2000-130.
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The ductile fracture toughness of steel is used to assess the ability of a pipeline to resist long running ductile fractures in a burst event. In modern low carbon clean steels with high toughness, conventional measures of ductile fracture toughness (standard Charpy and DWTT energy) are under review, and alternatives are being studied. The major factor causing concern is the inability of these tests to isolate the energy associated with crack propagation from the total energy absorbed during the specimen fracture. This is significant in modern high toughness steels because their initiation toughness is extremely high.

To resolve crack propagation energy, a novel modification was evaluated for both Charpy and DWTT specimens by employing a back-slot including a snug fitting shim to replace the removed material. In most cases, this modification was effective in curtailing the load-displacement trace when the propagating crack interacted with the slot on the backside of the specimen, without affecting the initial portion of the trace; this allowed crack propagation energies to be resolved. The propagation energy determined by this method is compared with the total energy and conventional test parameters. The crack propagation energy values inferred based on this should be validated, in future burst test.

Commentary by Dr. Valentin Fuster
2000;():V001T02A021. doi:10.1115/IPC2000-131.
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The ductile fracture toughness of steel is used to assess the ability of a pipeline to resist long running ductile fractures in a burst event. With the introduction of modern low carbon clean steels with ultra high toughness, conventional measures of ductile fracture toughness (standard Charpy and DWTT energy) are under review, and alternatives are being studied. The crack tip opening angle (CTOA) was investigated to evaluate its appropriateness as a measure of modern pipeline steel ductile fracture toughness. At first, fracture mechanics tests at quasi-static rate were analyzed to examine the constancy of CTOA with crack growth. The results of this initial review are based on four pipeline steels with a range of ductile fracture toughness. The CTOA values are also compared with appropriate parameters from conventional tests to examine potential relationships that may be used to indicate the relative resistance of pipeline steels to ductile fracture propagation. The final objective is to compare CTOA values determined by the simple two specimen method and those developed through a formal fracture mechanics based technique.

Commentary by Dr. Valentin Fuster
2000;():V001T02A022. doi:10.1115/IPC2000-132.
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To investigate the failure mechanism of pipelines subjected to mechanical damage, Charpy impact, crack-tip-opening displacement (CTOD) and fatigue-crack growth tests were carried out for six series of line pipe steels with uniaxial plastic prestrain, εpr. The Charpy absorbed energy and critical CTOD (δc) decreased with increasing |εpr|; ln δc = α εpr + β. The derivative, dδc/dεpr, was dependent on the ductile-to-brittle transition temperature of the steels. In the CTOD tests, the prestrain caused ductile-to-brittle transition for the steels with a higher transition temperature. The effects of the compressive εpr on both the reduction of δc and ductile-to-brittle transition were larger than those of the tensile εpr. The compressive εpr accelerated both the fatigue-crack initiation and growth.

Commentary by Dr. Valentin Fuster
2000;():V001T02A023. doi:10.1115/IPC2000-133.
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This paper reviews the fracture control plan for the Alliance Pipeline, which is planned for operation in 2000. This natural-gas pipeline is 2627 km (1858 miles) long, running from British Columbia, Canada to Illinois, USA.

Interest in the fracture control for this pipeline results from its design, which is based on transporting a rich natural gas (up to 15% ethane, 3% propane) at a relatively high pressure 12,000 kPa (1740 psi). This break from traditional pressures and lean gases, which frequently are constrained by incremental expansion, is more efficient and more economical than previous natural gas pipelines. Use of higher pressures and rich gas requires adequate fracture control for the line pipe, fittings, and valves. This fracture control has been achieved for the Alliance Pipeline by specifying high-toughness steels, in terms of both fracture-initiation and fracture-propagation resistance for the line pipe, fittings and heavy wall components.

While beneficial from an economics viewpoint, the need for higher toughnesses raised concern over the validity of the fracture control plan, which was based on existing and new technology. The concern focused on fracture arrest using high toughness steels. The concern was associated with characterizing fracture arrest resistance using Charpy V-notch impact toughness, the most commonly used method to measure fracture arrest resistance. Developments were undertaken to address problems associated with the use of higher-toughness steel and these were validated with full-scale pipe burst tests to demonstrate the viability of the fracture control plan.

The solution involved extending existing methods to address much higher toughness steels, which provided a significantly improved correlation between fracture arrest predictions and experimental results. In the burst tests, data was collected to validate the Alliance design and also to extend the database of fracture arrest data to assist future pipelines. Data such as the pressure between the pipe and soil as the gas escapes from the pipe, the sound levels in the atmosphere, the movement and strains in the pipe ahead of the running fracture were instrumented in the test and the available results are presented.

Commentary by Dr. Valentin Fuster
2000;():V001T02A024. doi:10.1115/IPC2000-134.
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A finite-element method computer simulation was constructed in order to assist in determining what material properties affect the resistance to dynamic ductile failure in pipelines. Such failure is caused by stable axial tearing that involves a substantial amount of plastic deformation, and is driven by the kinetic energy of the expanding gas. Various semi-empirical relationships exist in the literature to predict the toughness required for resistance to the propagation of a dynamic ductile failure, but these tend to be ineffective when applied to higher strength grades of steel. The present finite-element model is composed of two main sub-models. The gas decompression algorithm is based on analytical expressions and calculates the gas pressure throughout the pipe as the ductile fracture propagates. The material-response algorithm determines the behaviour of the material under the changing loading conditions. It simulates the material response, including rate-dependent yield as well as anisotropy of yield and work hardening. The model is validated by using comparisons with published data from the literature.

This paper focuses on a description of the different components of the model and their interaction. In addition some observations from the various simulations are discussed.

Commentary by Dr. Valentin Fuster
2000;():V001T02A025. doi:10.1115/IPC2000-135.
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The work deals with the development of a finite element code, named PICPRO (PIpe Crack PROpagation), for the analysis of ductile fracture propagation in buried gas pipelines. Driving force estimate is given in terms of CTOA and computed during simulations; its value is then compared with the material parameter CTOAc, inferred by small specimen tests, to evaluate the toughness of a given line pipe. Some relevant aspects are considered in the modelling with the aim to simulate the real phenomenon, namely ductile fracture mechanism, gas decompression behaviour and soil backfill constraint. The gas decompression law is calculated outside the finite element code by means of experimental data from full-scale burst tests coupled with classical shock tube solution. The validation is performed on the basis of full-scale propagation experiments, carried out on typical pipeline layouts, and includes verification of global plastic displacements and strains, CTOA values and soil-pipe interaction pressures.

Commentary by Dr. Valentin Fuster
2000;():V001T02A026. doi:10.1115/IPC2000-136.
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The consequences of a dynamic fracture in a gas-transmission pipeline require that they be designed to avoid such incidents with great certainty. Because of the complexity of this fracture process, the only certain approach to determine fracture-arrest conditions involved full-scale experiments. As time passed empirically calibrated balance equations between the crack-driving conditions and the line-pipe steels crack-arrest capabilities were developed. Such models worked well until the introduction of high-toughness line pipe, for which to full-scale test predictions were non-conservative, and increasingly so as toughness increased. Problems with early CVN-based models led to development of alternative schemes.

This paper presents results of experiments done to evaluate plausible alternatives to the CVN practice, which rely on an impact test identical to or adapted from the drop-weight tear-test (DWTT). As this practice is comparable to that of the CVN practice save for using an up-scale specimen geometry, results are presented and contrasted for these test methods, for pipe grades from B to X70, and toughness from less than 10 J in excess of 300 J. Data are analyzed to reveal trends not typically reported for such testing. It is shown that there is no essential difference between data developed from the CVN and DWTT practices, provided the results are compared at similar levels of impact-machine excess-energy capacity. Further, it is shown that non-conservative predictions of full-scale test behavior for higher-toughness steels can be traced to using the early CVN-based models at toughness levels well outside the range of their empirical calibration.

Commentary by Dr. Valentin Fuster
2000;():V001T02A027. doi:10.1115/IPC2000-137.
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Through 1999, Camrose Pipe Company manufactured ∼152 km (∼45 000 tonnes) of 1067 × 11.4mm pipe for Alliance Pipeline Partnership Ltd. This section of Alliance’s pipeline was manufactured to a design whose pipe fracture toughness requirements was significantly beyond those historically manufactured in Canada and initiated a major leap in plate/pipe manufacturing toughness capability. The development of line pipe toughness in Canada culminating in this order will be profiled.

Further, this high toughness design is at the far reaches of the traditional fracture arrest models. Besides the traditional Charpy energy measure, and to confirm Alliance’s confidence in their fracture arrest design, another two sets of fracture assessment tests were used on a trial and production basis: the API chevron notch drop weight tear test (CN DWTT) energy and the energy of a similar test using an Alliance notch modification. The results of these tests will be reviewed and compared.

Commentary by Dr. Valentin Fuster
2000;():V001T02A028. doi:10.1115/IPC2000-138.
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An analysis of the ductile fracture arrest in the first Alliance burst test has been conducted to examine the arrest of a ductile fracture in the presence of a rich gas, high stress level (80% SMYS), and high pressure (1740 psig, 12 MPa). The analysis used a three dimensional finite element analysis of a ductile fracture propagating in a buried gas transmission pipe to determine the crack tip opening angle (CTOA). The CTOA was calculated as a function of the fracture speed.

The critical CTOA was determined from Charpy V-notch and Drop Weight Tear Test specimens. The results indicate that in this instance the CTOA accurately assessed the fracture behavior observed in the burst test.

Commentary by Dr. Valentin Fuster

Environmental: General (Environmental)

2000;():V001T03A001. doi:10.1115/IPC2000-139.
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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.

Commentary by Dr. Valentin Fuster
2000;():V001T03A002. doi:10.1115/IPC2000-140.
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In 1998, Husky Oil Operations Limited and its partner formerly Rigel Oil, (purchased by Talisman Energy in 1999), constructed a 26.2 km pipeline in Kananaskis Country to transport sour oil, solution gas and produced water from Pad #3 on Cox Hill to the Shell Oil Jumping Pound Gas Plant for processing. Kananaskis Country is a 4160 km2 “Planning Area” that has both Prime Protection and Multiple Use designations. Situated just west of Calgary, Alberta, Canada it has considerable recreational and environmental value, including significant wildlife habitat.

The original exploration and subsequent pipeline construction applications required separate Alberta Energy & Utilities Board (AEUB) public hearings with both involving significant public consultation. Prior to drilling on the lands that had been purchased more than a decade ago, Husky adopted several governing principles to reduce environmental impact, mitigate damage and foster open and honest communication with other industrial users, regulators, local interest groups and local aboriginal communities. During planning and construction, careful attention was paid to using existing linear disturbances (seismic lines, roads and cutblocks). A variety of environmental studies, that incorporated ecologically-integrated landscape classification and included the use of indicator species such as the Grizzly Bear, were conducted prior to and during the early stages of development. The results of these studies, along with the information gathered from the public consultation, historical and cultural studies and engineering specifications formed the basis for the route selection.

Watercourses presented particular challenges during pipeline construction. The pipeline right-of-way (RoW) intercepted 26 small water runs and 19 creeks. Fishery and water quality issues were identified as important issues in the lower Coxhill Creek and Jumpingpound Creeks. As a result, Jumpingpound Creek was directionally drilled at two locations and all other watercourses were open-cut using low-impact techniques. To minimize new RoW clearing, substantial portions of the pipeline were placed in the ditch of the existing road. Husky attributes the success of this project to planning, broad community input and the co-operation and buy-in by the project management team and construction companies.

Commentary by Dr. Valentin Fuster
2000;():V001T03A003. doi:10.1115/IPC2000-141.
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Novia Scotia, a province of about one million people, is located on the east coast of Canada. With the discovery of large natural gas reserves off the Scotian Shelf, offshore production platforms, undersea and onshore pipelines have been constructed to link the find with major markets in Boston by the end of 1999. The onshore pipeline through the province will allow a distribution system to be developed. This natural gas system will be the largest Greenfield development seen in North America for many years.

A billion-dollar expenditure is proposed to establish a local distribution company, which would construct and maintain around 8,000 kilometres of distribution and lateral pipelines in the province. An integral part of this program involves the provision of local benefits through hiring and purchasing of goods and services.

This paper describes aspects of the construction program and benefits plan proposed during the regulatory hearings in order to illustrate the methods used to ensure that the objectives of accessing the majority of Nova Scotians in a seven year planning horizon will be met. The varied landscapes to be crossed and specialized construction techniques to meet those challenges are discussed. The mechanisms in place to ensure maximum benefit for Nova Scotians are also discussed.

Up-to-date information will be presented to demonstrate how the benefits plan is being implemented. The successes of the benefits plan for the distribution utility and the other local megaproject in the province (Sable Offshore Energy) are compared. Conclusions will be drawn regarding successful strategies for implementing benefits plans related to large energy projects.

Commentary by Dr. Valentin Fuster

Environmental: Geotechnical Issues

2000;():V001T03A004. doi:10.1115/IPC2000-142.
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The 22″ Alberta Oilsands Pipeline transports synthetic crude oil from Syncrude Canada Limited in Fort McMurray to Edmonton, Alberta. The pipeline crosses the House River approximately 100 kilometers south of Fort McMurray.

The slope has been monitored since 1991 by three slope indicators. A finite element stress analysis indicated that total ground movement since installation in 1977 could correspond to pipeline compressive strains in excess of 0.32%, a level of risk unacceptable to the pipeline owner.

A probability-based model was developed to determine cost and benefit of risk mitigation options. Parameters such as soil movement and pipe strain were input as probability distributions. The mitigation options included: reduce slope instability; reduce pipe stress; reduce pipe-to-soil interaction; implement long term monitoring; determine current pipe strain level (to decrease data uncertainty); do nothing.

A Monte Carlo simulation was used to establish probability of failure and probable cost distributions for each option. The results were presented as a combined cost of failure and mitigation over 10 years.

The analysis indicated that the optimum solution was to remove the existing soil traction loading on the pipe and mitigate long-term slope movement. The decision was made to relieve the pipe strain by excavating. Current pipe strain was measured in situ using residual strain measurement. Long term strain gauges were installed. Slope mitigation was deferred until the strain gauges indicate total pipeline strain levels approaching 0.32%.

Commentary by Dr. Valentin Fuster
2000;():V001T03A005. doi:10.1115/IPC2000-143.
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This paper analyzes a pipeline construction project in which the horizontal directional drill (HDD) technique for pipe installation was heavily utilized. The paper focuses on the benefits and risks of using directional drills, versus open cut installation, from an environmental perspective. The paper also contains recommendations, in a lessons-learned format, that might be useful in planning a pipeline construction project that includes the use of HDD techniques, especially under wetland areas.

Topics: Drills (Tools)
Commentary by Dr. Valentin Fuster
2000;():V001T03A006. doi:10.1115/IPC2000-144.
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In 1997, a research project was initiated by Southern California Gas Company, Pacific Gas and Electric Company, with support from Tokyo Gas, Osaka Gas, and Toho Gas, to investigate the cause of natural gas pipeline damage during the 1994 Northridge earthquake. As part of this research activity, extensive field and laboratory investigations were performed on a 1925 gas pipeline that suffered several girth weld failures in Potrero Canyon, a remote and unpopulated area just north of the Santa Susana Mountains. The pipeline is operated by the Southern California Gas Company, one of the principle sponsors of the gas utility research project.

The investigations into the performance of the pipeline were largely prompted by questions regarding the cause of pipeline damage. Although ground cracking and sand boils were observed in Potrero Canyon following the Northridge earthquake, there were no clear signs of permanent ground deformation near the locations of pipeline damage. Pipeline damage, consisting predominantly of girth weld tensile failure and two instances of buckling of the pipe wall, indicated that significant relative pipe-soil deformation might have occurred. Field investigations were unable to identify surface evidence of permanent ground deformation near the locations of pipeline damage and attention focused on the possibility that the damage could have been caused by wave propagation. This focus was based on the assertions of past researchers that pipelines with poor-quality oxyacetylene girth welds are susceptible to damage from wave propagation. The detailed investigation of The pipeline has concluded that wave propagation was not a significant factor in the pipeline damage and raises questions regarding wave propagation effects as a causative mechanism for pipeline damage in past earthquakes.

A simple analytical model of the transient ground deformation that may have occurred in the vicinity of the pipeline damage was found to provide insight into the cause of the ground cracking observed at the margins of Potrero Canyon, approximate magnitudes of differential ground displacements that may have occurred during the earthquake, and the reasons for the spatial distribution of pipeline damage. This model is proposed as the basis for identifying locations where similar earthquake effects can be identified in future hazard assessment studies.

Commentary by Dr. Valentin Fuster

Environmental: Remediation and Reclamation

2000;():V001T03A007. doi:10.1115/IPC2000-145.
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The Trans Mountain Pipe Line Company Ltd. (ATrans Mountain≅) Jasper station underwent a major upgrade in the mid 1990’s. In the five years preceding the upgrade two minor petroleum releases and one larger release involving Methyl Tertiary Butyl Ether (MTBE) occurred at the facility.

The assessment and remediation of the impacted water table at Jasper station was complicated by several factors. The released petroleum and MTBE reached the water table which was at a depth of approximately 20 metres. The stratigraphy included cobbles and boulders in some areas and the deeper wells encountered heaving sands which made well installation to the desired depth quite difficult. In addition to the subsurface conditions which made recovery efforts difficult, a treatment facility was required which would remove dissolved petroleum and MTBE from the groundwater throughout year long operations. Temperatures at the facility range from minus forty degrees Celsius in the winter to plus forty in the summer.

Removal of MTBE from groundwater offers its own challenges. MTBE reacts differently in the subsurface environment when spilled and is much more difficult to treat than conventional petroleum compounds.

This paper presents information with regard to the remediation program at Jasper station. In particular, it describes the design, construction and operation of the groundwater recovery and treatment facilities used to capture and remediate the dissolved MTBE plume.

Topics: MTBE , Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T03A008. doi:10.1115/IPC2000-146.
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A biotreatability test was performed on oil-contaminated sphagnum peat moss from a 1985 pipeline spill of light Pembina Cardium crude oil at a bog near Violet Grove in central Alberta. Four tests were designed to simulate several field treatment approaches and to collect critical data on toxicity and leachability of this material. These tests included a bioslurry test, a soil microcosm test, an aerated water saturated peat column test, and a standard toxicity characteristic leachate potential (TCLP) test.

In the saturated peat column tests, two nutrient amendment rates and a surfactant were tested to quantify biostimulation effects from an in-situ treatment design. An innovative aeration technology called the GLR (Gas-Liquid Reactor) was used to create a constant supply of hyperoxygenated water prior to column injection. The GLR continuously produces air bubbles of less than 50 microns in diameter, thereby maximizing air surface area and thereby increasing gas transfer rates. Crude oil biodegradation was quantified by the reduction in both extractable hydrocarbons and toxicity of the peat solids.

The results confirmed that bioremediation of the residual crude oil to non-toxic levels in the peat bog at Violet Grove will be successful. All three tests — bioslurry, soil microcosm, and soil columns — gave similar results of at least 74% biodegradation of the residual crude oil on the peat solids.

In situ bioremediation using the GLR aerated water injection system or an ex situ landfarming or biopile approach should achieve the 1000 mg/kg total petroleum hydrocarbon criteria. Neither fertilizer nor surfactant amendments were necessary to enhance oil biodegradation in the in situ column tests. The TCLP test indicated that ex situ treatment would require an impermeable liner for leachate collection.

The time required to achieve the final remediation goals will depend on climatic variable such as temperature and rainfall during active summer season bioremediation. It is anticipated that an in situ approach using recirculated aerated water would achieve the cleanup up criteria within one full field treatment season.

Topics: Pipelines , Testing
Commentary by Dr. Valentin Fuster

Environmental: Stream Crossings

2000;():V001T03A009. doi:10.1115/IPC2000-147.
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There are strict regulatory requirements for pipeline construction at river and stream crossings. The requirements for monitoring, surveillance and maintenance of existing crossings on the other hand are limited to a few lines in Section 10 of CSA Z662-99.

Systematic procedures for assessing stream channel stability are not readily available to the operators of pipelines. As a consequence, many monitoring and inspection programs focus more on detecting exposures than on preventing them.

In this paper, the AEC Pipelines Ltd. approach to monitoring river and stream crossings is reviewed and discussed. The program involves application of basic geomorphic concepts and use of aerial photographs to define channel characteristics at crossing sites and to determine which crossings may be subject to future channel instability or erosion problems. From these in-house evaluations, decisions are made to either proceed with more in-depth assessments by river engineering specialists or continue with routine aerial and ground surveillance. As part of the overall program, procedures for completing routine channel surveys and a checklist of data to be gathered during regular reconnaissance trips have been developed.

Topics: Pipelines , Rivers
Commentary by Dr. Valentin Fuster
2000;():V001T03A010. doi:10.1115/IPC2000-148.
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This paper describes the history of channel changes and associated pipeline exposure problems at five river and stream crossings in Alberta. Each case history reviews the various hydrologic and geomorphic factors that contributed to the erosion problem and describes the corrective action that was taken. A number of the examples illustrate the inherent difficulties in identifying potential erosion problems at the project design stage. Others show that with systematic monitoring and inspection procedures in place, remedial action can be planned and implemented well before pipeline integrity has been compromised.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T03A011. doi:10.1115/IPC2000-149.
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This project is of interest to those involved in construction, siting and repair of pipeline crossings of rivers, streams and estuaries. In early 1999, Mainline Pipelines Limited discovered that their pipeline crossing of the River Wye had been exposed by river scour. Originally laid in 1972, the line provides petroleum products main supply from the port at Milford Haven to the Midlands, England, and operates at a high pressure. A break in or temporary shutdown of the pipeline would have had serious implications. Remedial protection options were needed rapidly, to ensure the integrity of the pipeline. A review of historical air photographs and maps, dating back to 1888, showed that the meandering channel of the River Wye has shifted to the north at an average rate of 0.65m per year. Thus, the remedial works would have to account for ongoing vertical and lateral scour. It was recognized that river training works would be required at the site to ensure continued protection of the pipeline in the long-term. The recommended design and remedial construction techniques allowed for safety issues, the potential impact on the river ecology, recreational river users, the river hydrology and restricted access to the steep northern riverbank. The design comprised filling of the eroded riverbed and bank with rock aggregate and placing a protective layer of graded rock riprap. Grout filled fabric formwork bags were placed beneath the pipeline to minimise deflection and the development of unacceptable stresses in the exposed length during rock placement. Rock filled wire mattresses were placed immediately on top of the pipeline to protect it from point loading of the angular riprap. A satellite guided positioning system was used to control material placement, and environmental monitoring of river water quality was carried out continuously during construction.

Topics: Pipelines , Rivers
Commentary by Dr. Valentin Fuster

GIS/Database Development: General (GIS/Database Development)

2000;():V001T04A001. doi:10.1115/IPC2000-150.
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Today’s tools and technologies allow the pipeline industry to collect information and describe company pipeline assets in a productive way. Rooney Engineering, Inc. recently completed a 130-mile crude oil pipeline in the greater Los Angeles area of California with which wide ranges of technologies were utilized over an 8-year period. Review of all phases of this pipeline project offers a unique glimpse of managing and integrating traditional survey and Global Positioning System (GPS) techniques with a Geographic Information System (GIS). While the first portion of the project used traditional methods of photogrammetry and Computer Aided Drafting (CAD) to complete the conceptual design and construction drawings, the second portion utilized a combination of CAD, GIS and GPS technologies to assist the construction team during construction and as-built. Geographically organized data was later applied beyond the phases of pipeline construction; data was later used in one-call, contingency planning and emergency response.

This paper will give an overview of the project, including pre-construction drawing preparation, construction zones, terrain types, political jurisdictions, and original staff assignments for data collection. The paper will discuss data dictionary design and management of collected field data, equipment and personnel requirements, and accuracy trade-off. The paper will examine the verification of data for attribute integrity and assignment of positional accuracy tags, along with specific methods of GPS and traditional data collection, while also exploring data management of incoming field data from multiple sources over an extensive timeline. Additionally, the paper will focus on the use of GIS to support construction monitoring and cost reconciliation analysis. Finally, we will review preparation of final drawings, summarize lessons learned, and discuss what the future offers in enhancing pipeline-mapping productivity.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T04A002. doi:10.1115/IPC2000-151.
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A pipeline project normally not only covers a large geographic range, but also deals with a variety of data sources, such as geological, geographical, environmental, engineering and socioeconomic data. GIS has proven to be the effective approach to integrating, managing and analyzing these heterogeneous data sources. Due to the nature of pipeline applications, the third dimension of geospatial data is of considerable importance for pipeline planning, construction and maintenance. There is an increasing demand for the development of a 3-D GIS for pipeline applications. With the advent of Internet, distributed computing and computer graphics technologies, development of web-based 3-D GIS becomes technologically possible. The combination of 3-D GIS and web-based computing technologies opens a whole new avenue to the pipeline industry. In this paper, we will address the development of a web-based 3D GIS in terms of benefits and technical challenges. The detailed system architecture as well as the algorithms developed is also discussed. Finally, potential applications for the pipeline industry are introduced and a prototype system, GeoEye 3D, developed by the Department of Geomatics Engineering at the University of Calgary is described.

Commentary by Dr. Valentin Fuster
2000;():V001T04A003. doi:10.1115/IPC2000-152.
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In the past, high resolution satellite imagery was the domain of national security organizations. However, this has recently changed with the launch of Space Imaging’s IKONOS satellite. Launched on September 24, 1999 it is the world’s first commercial high resolution satellite, collecting data at 1-meter black/white and 4-meter multi-spectral.

2000 has the scheduled launch of at least two more commercial high resolution satellites. If these satellites are successfully launched, a buyer will be able to acquire imagery every day of the year (barring cloud cover). As an added convenience, an image user no longer has to buy a massive swath of imagery. For example, IKONOS scenes as narrow as 5km (3 miles) can be purchased. This development has opened the door for corridor applications and has been thoroughly and successfully implemented by TransCanada Pipelines in mapping over 1500km of their mainline.

Commentary by Dr. Valentin Fuster
2000;():V001T04A004. doi:10.1115/IPC2000-153.
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The majority of pipeline transportation facilities for natural gas, liquefied petroleum gas and basic petrochemical products were built in Mexico during the 60’ −70. The most recent construction occurred between the 80–90’s. These gas pipelines are located in 24 of the 32 Mexican States, crossing through private property, agricultural fields and sharing right of ways with other Pipeline Companies. The length is up than 11,000 km., beginning in Cactus, Chiapas and ending in Chihuahua. Import/export points are located in Reynosa, Laredo, Piedras Negras and Ciudad Juarez, crossing many populated areas, fresh and salty waters bodies, highways, bridges, areas of irregular topographical terrain. This situation makes operation, maintenance, safety and inspection activities difficult to realize. Therefore, Pemex Gas y Petroquimica Basica established a technical information system, to have integrated digitized pipeline trajectory, on several geographic maps, and technical databases associated related maintenance, operation and safety. Technical consultation is the main project goal, either in headquarters or “in situ” if it were necessary, to aid in decision-making processes, or to take right choices in case of any incident.

Commentary by Dr. Valentin Fuster

GIS/Database Development: GIS Systems and Pipeline Integrity

2000;():V001T04A005. doi:10.1115/IPC2000-154.
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This paper outlines the development of the Goliath database and its access through the Internet. Goliath is the corrosion and corrosion-rate database developed by Morrison Scientific Inc. (“MSI”) in 1998 and 1999, for Enbridge Pipelines Inc. (“Enbridge”). Its original design and implementation were for the management of corrosion data from in-line inspections and the corrosion-rate analysis results. In addition, Goliath also contains other related data such as pipe parameters, inspection dates, and vendor-company information.

Commentary by Dr. Valentin Fuster
2000;():V001T04A006. doi:10.1115/IPC2000-155.
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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.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T04A007. doi:10.1115/IPC2000-156.
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Geographical Information Systems, Data trending, and Risk Assessment Software are now available to help pipeline operators execute safe, cost effective maintenance programs. However, to use these analytical tools effectively, large amounts of data pertaining to the integrity of the pipeline system and its environment are required. For this reason, pipeline rehabilitation programs have evolved into complex data collecting procedures, the success of which depends on the ability to efficiently obtain reliable, consistent and accurate information.

This article will describe new software technology and Quality Control programs, relating to inspection personnel, which have been developed to increase the efficiency and reliability of the information collected during a pipeline excavation.

The pertinent functions of software programs discussed will involve compatibility between databases, on site data validation, code calculations, communications and CAD drawings for a comparison with In Line Inspection results.

As well, the need for quality control or training programs will be discussed addressing both the theoretical and practical applications of pipeline integrity and it’s relevance to quality data collection. Previous projects using these approaches will be presented showing their effectiveness in significantly increasing the efficiency and accuracy of the information collected while reducing overall inspection time and cost.

Commentary by Dr. Valentin Fuster
2000;():V001T04A008. doi:10.1115/IPC2000-157.
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Geographical Information Systems (GIS) have been in use in some industries for over two decades. Some large scale database or GIS implementations have failed to deliver their full benefits because their scope has often been too wide. Such systems are generally multimillion dollar projects which in turn need ongoing support to maintain the database and administer the system. Where the general needs of a pipeline company are given precedence the specific needs of the integrity department can often be overlooked. As a result the company wide GIS is often of little value for the analysis and management of pipeline integrity data. Recent advances in computing power, software, communications and database design aided by new sources of geographical image data mean that the time is now right for a pipeline integrity specific Geographical Information System.

GIS allows the condition of a pipeline to be viewed in a geographical context and maximises the value of existing data sets. Specific pipeline anomalies can be related to geographical or environmental data such as soil conditions, hydrology, land slip or subsidence. A GIS system used in this way provides a valuable tool to help understand, explain, predict and avoid degradation of a pipeline asset.

New sources of geographical image data such as sub meter, multi spectral optical satellite imagery, synthetic aperture radar data from satellites and thermal data from aircraft systems, can be used to identify ground characteristics or leakage and provide frequent updates to enable change detection and surveillance to be performed. The GIS can be used as a risk assessment and data management tool, which will enable the full benefit to be extracted from each individual data source, ranging from ILI data to CP and corrosion growth data. This new source of information will be an essential aid to pipeline integrity in the new century.

Once implemented the system can be used to perform spatial queries to provide rapid access to the analysis results, confirm code compliance and prioritise corrective action and maximise the efficient use of the resources available.

Commentary by Dr. Valentin Fuster

Innovative Projects and Emerging Issues: Emerging Issues

2000;():V001T05A001. doi:10.1115/IPC2000-158.
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As the pipeline system of TransCanada Pipelines Ltd. (TransCanada) ages, cover at water crossings is continuously being adjusted to dynamic changes in weather patterns and local water crossing hydraulic characteristics. In an increased asset base of over 37 000 km of pipeline, this creates challenges to find and remediate crossings with high risks while maintaining the integrity of the whole system. A methodology has been developed to address the increasing demands of fiscal responsibility and pipeline integrity. The Scour Hazard Database Model (SHDM) provides the necessary tool to provide solutions to both of these challenges. The SHDM provides a stand alone prioritisation tool that is updateable and transparent. It can alert TransCanada to both immediate and potential pipeline exposures, in order that reactive and proactive solutions can be initiated. The SHDM contains descriptive pipeline information, local hydrologic data, channel hydraulic information, and scour hazard logic for over 2350 river and creek crossings throughout Canada. This information is used to produce a final rating value for comparing the potential for vertical and lateral pipeline exposures at each crossing. The vertical scour logic considers age of the crossing, modelled scour, natural degradation and any remedial work to determine the rating value. The lateral erosion logic uses channel form, location, lateral cover distances between the thalweg and pipeline, stream power, age of the crossing, and any remedial work to develop the lateral scour rating value. Furthermore, the exposed pipes are evaluated based on the potential failure mechanisms to determine failure probability. Included in the failure analysis are lateral stability, impact of debris, and fatigue. The failure probability and the consequence of the failure are used to rank the crossings and identify the requirement for maintenance activities.

Commentary by Dr. Valentin Fuster
2000;():V001T05A002. doi:10.1115/IPC2000-159.
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TransCanada Pipelines Ltd. (TransCanada) operates approximately 37,000 km of natural gas gathering and transmission pipelines. Within the Alberta portion of this system there are almost 1100 locations where the pipeline(s) traverse slopes, primarily as the line approaches and exits stream crossings. In the past, the approach to managing the impact of slope movements on pipeline integrity has been reactive; site investigations and/or monitoring programs would only be initiated once the slope movements were sufficiently large so as to easily observe cracking or scarp development. In some cases these movements could lead to a pipeline rupture.

To move to a proactive hazard management approach and to optimize the maintenance expenditure, TransCanada has developed a new slope assessment methodology. The objective of this methodology is to establish a risk-ranked list of slopes upon which maintenance decisions can be based. Using only internal and public information on site conditions as input to predictive models for rainfall-ground movement and pipe-soil interaction, a probability of pipeline failure can be generated for each slope. Estimates of risk using a consequence-matrix approach enabled the compilation of a risk-ranked list of hazardous slopes.

This paper describes this methodology, and its implementation at TransCanada, and presents some of the results.

Commentary by Dr. Valentin Fuster
2000;():V001T05A003. doi:10.1115/IPC2000-160.
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A full scale fracture propagation test facility has been developed to validate the design, in terms of the ability of the material to avert a propagating fracture, of a major new pipeline to transport gas 1800 miles from British Columbia in Canada to Chicago in the USA. The pipeline, being built by Alliance Pipeline Ltd, will transport rich natural gas, i.e. gas with a higher than normal proportion of heavier hydrocarbons, at a maximum operating pressure of 12,000 kPa. This gas mixture and pressure combination imposes a more severe requirement on the pipe steel toughness than the traditional operating conditions of North American pipelines. As these conditions were outside the validated range of models, two full-scale experiments were conducted to prove the design. This paper will provide details of the construction of the 367m long experimental facility at the BG Technology Spadeadam test site along with the key data obtained from the experiments. Evaluation of this data showed that the test program had validated Alliance’s fracture control design. The decompression data obtained in the experiments will be compared against predictions from a new decompression model developed by BG Technology. The use of the experimental facility and the model to support future developments in the pipeline industry, particularly in relation to the use of high strength steels, will also be discussed.

Commentary by Dr. Valentin Fuster
2000;():V001T05A004. doi:10.1115/IPC2000-161.
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Fibre reinforced polymeric composites used in pressure retaining structures are seen as an attractive alternative to products made from conventional materials due to their corrosion resistance and high strength-to-weight ratio. The reluctance in adopting composite materials, however, is due to a limited understanding of the material behaviour under a variety of loading and environmental conditions, and lack of qualified design methodologies. It is the purpose of this paper to address fundamental and applied issues regarding their feasibility and current limitations in pipeline applications. A review of pertinent research results with respect to the local and global behaviour in composite pipes will be discussed.

Commentary by Dr. Valentin Fuster
2000;():V001T05A005. doi:10.1115/IPC2000-162.
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The paper presents case studies of pipeline risk assessments for special situations such as multiple pipelines in a common trench, pipelines adjacent to other hazardous facilities, and segments of special construction such as major water crossings. For such situations, the relatively straightforward risk assessment applicable to single pipelines in normal conditions is not applicable. Rather, one must generate a special analytical approach case by case to deal with those aspects of the risk assessment which vary from those of the normal situation. In this paper, following a brief introduction, a series of case studies for special problems in pipeline risk assessment based on real projects completed by the authors, is given, followed by conclusions and recommendations.

Commentary by Dr. Valentin Fuster
2000;():V001T05A006. doi:10.1115/IPC2000-163.
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Market-based pipeline projects are initiated by the pipeline-owning company and require focused attempts to secure a customer or develop a market for the product transportation.

The development of Market-based pipeline investments in the international arena has fundamental differences from projects sponsored by consumer or pipeline user needs, government endeavors or producers desiring to sell their product. Whereas these User-driven projects were the traditional way of developing projects in the past, current global political and economical trends are forcing private pipeline companies to develop new ways of creating business opportunities: the development of Market-based Pipeline Projects.

A proactive strategy for developing energy transmission businesses (i.e. market-based projects) involves finding sufficient energy users and linking them with pipeline infrastructure to viable supplies of natural gas. These Market-based business opportunities are uniquely developed and require strong corporate vision and support before it can be successfully implemented.

This paper will provide an insight to the challenges, risks and uncertainties to be faced when developing Market-based pipeline projects. The discussion focuses on the project development phase of the project, from the moment the business opportunity viability has been confirmed to the time when the decision is made to proceed with large capital commitments. The paper includes a description of the pipeline project development process and a review of the variables influencing important steps and decisions prior to commencement of project implementation and hence capital investments.

While the content of this paper is mostly applicable to all types of pipeline projects, the discussion will focus on natural gas transmission pipelines.

Topics: Pipelines
Commentary by Dr. Valentin Fuster

Innovative Projects and Emerging Issues: Emerging Technologies

2000;():V001T05A007. doi:10.1115/IPC2000-164.
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The end of the 20th century has seen some major developments to the business of pipelines worldwide. In North America and Europe the trend has been toward deregulation of the industry. In other markets the trend has been toward the use of fixed transport cost contracts between shippers and the pipeline company. The net effect of these changes is increased competition in the transport of energy with the resulting requirement to provide the lowest cost of transport. At the same time pipelines need to maintain the traditionally high levels of safety and reliability that customers, the public and regulators have been accustomed to.

The pipeline industry has responded to the challenge to reduce costs on a number of fronts. These include the areas of contracting, financing, planning, regulation, market development, and technical developments as well as many other areas. This paper will focus on technical developments that have allowed pipeline companies to reduce the cost of moving large volumes of natural gas at high pressures. Progress that the industry has made in the areas of capital cost reduction will be illustrated by an example of high pressure pipeline design. Capital costs will be compared for five system design pressures that all result in the same maximum flow rate. The optimum high-grade steel will be chosen for each pressure. This will also be compared to costs for using Composite Reinforced Line Pipe (CRLP) a new technology for the pipeline industry.

Commentary by Dr. Valentin Fuster
2000;():V001T05A008. doi:10.1115/IPC2000-165.
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In recent years new technologies, novel products, improved services and better contracting procedures are emerging and showing great potential for increased performance and safety. This is increasingly evident for applications in sectors like offshore, petrochemical and refining, ship and submarine building, nuclear power, hydropower, oil and gas transfer lines where failures are can lead to hazards to life. One such technology is a non-gasketed pipe connection and is recognised by the authors as representative of an ‘emerging technology’. It is based on several un-orthodox principles and does consist not only of a pair of welding neck flanges, but of an all-inclusive entire system, comprising bolts, washers, nuts, wrenches, procedures and training.

This paper is based on two years of experimental and finite element studies [Ref 1,2] of both standard/conventional ANSI (gasketed) and modern non-gasketed flanged joints. This has led to a deeper understanding of the requirements for a successful assembly and long term usage. ANSI and VCF joints have been subject to internal pressure, axial and lateral forces, with these loads having been applied both singly and in combinations. Mode of load acting in the joint i.e. static or dynamic has been studied for both kinds of joints. Experimental and analytical results have been compared.

Some practical considerations on the use of important emerging technology i.e. non-gasketed pipe joints in comparison to conventional gasketed systems are presented. Of fundamental importance is an insight into the mechanism of the bolted joint showing the effect from an external load on a preloaded bolt. It is found that it can be made near zero hence, in a properly built, non-gasketed bolted joint a static mode rules, and therefore the stamina of such a joint is unlimited.

Other practical issues of fabrication, handling, surface damage and assembly, have been examined in the lab and on site and a summary of results is presented. In addition a probability risk assessment has been undertaken and results compared with the standard (conventional) ANSI type joints. In addition this paper demonstrates that the novel system is an efficient and well -engineered alternative to traditionally designed joints.

Topics: Pipe joints
Commentary by Dr. Valentin Fuster
2000;():V001T05A009. doi:10.1115/IPC2000-166.
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The multidomain model, which has already been developed for the simulation of large networks, is being used to determine the surface roughness and heat transfer coefficient for two parts of the TransCanada system.

Commentary by Dr. Valentin Fuster
2000;():V001T05A010. doi:10.1115/IPC2000-167.
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An innovative technique for rapid and accurate collection of preliminary survey and mapping in pipeline route selection has been developed by Aerotech L.L.C. and implemented by Lakehead Pipe Line Company, Limited Partnership. The technique involves GPS referenced digital imagery and laser scanned topographical data collected on an aerial platform. Accuracy of laser scanned topographical features up to ± 10 cm absolute ± 2 cm relative can be easily achieved. The data is processed and formatted for AutoCAD and GIS applications such as ArcView.

Topics: Lasers , Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T05A011. doi:10.1115/IPC2000-168.
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Actually, the increase in natural gas needs in the European market, foreseen for the beginning of the next century, compels to develop new solutions for the exploitation of gas fields in remote areas. For natural gas transportation over long distances the hypothesis of a large diameter high-pressure pipeline, up to 150 bar (doubling of the actual one) has been found economically attractive, resulting in significant reduction of the transportation cost of the hydrocarbon. In this contest the interest amongst gas companies in the possible applications of high-grade steels (up to API X100) is growing. A research program, partially financed by E.C.S.C. (European Community for Coal and Steel), by a joint co-operation among Centro Sviluppo Materiali (CSM), S.N.A.M. and Europipe in order to investigate the fracture behaviour of large diameter, API X100 grade pipes at very high pressure (up to 150 bar) has been carried out.

This paper presents: the current status of technology of API X100 steel with respect to the combination of chemical composition, rolling variables and mechanical properties the results obtained from West Jefferson tests, in order to confirm the ductile-brittle transition behaviour stated from laboratory tests (DWTT), the results obtained concerning the control of long shear propagating fracture and in particular the results of a full scale crack propagation test on line operating at very high hoop stress (470 MPa). Besides, in order to investigate the defect tolerance behaviour of the pipe with respect to axial surface defect, burst tests with water as pressurising medium have been carried out and the relative results are presented and discussed.

Commentary by Dr. Valentin Fuster
2000;():V001T05A012. doi:10.1115/IPC2000-169.
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Prior to the introduction of plastic pipe many gas utilities used cast iron to build their gas distribution network. Currently, there is approximately forty thousand kilometres of cast iron pipe in service in North America and a further two hundred thousand kilometres in Europe. Mostly found in dense urban locations, the cost of replacing these systems can be significantly high, such that extending the life of these systems is now a common strategy. The main problem has been leakage from bell and spigot joints caused by road vibration, freeze/thaw cycles of the ground, and the swelling and drying of clay soils.

Repair technologies have evolved from mechanical joint clamps, to elastomeric seals, to shrink sleeves, to encapsulants and finally to anaerobics. The most advanced of these technologies involve the use of anaerobic sealants which are injected into the jute packing by drilling into the pipe bells. These sealants have been studied at Cornell University for longevity, and are predicted to withstand many years of service.

The use of anaerobics has been adapted to work with robotics that allows the injection to take place from the inside of the pipeline while the gas main is in operation. This technology allows 24 joints to be sealed from a single excavation. The robot is a tethered electro-mechanical device that allows visual location of the joint, internal drilling into the jute packing, and injection of the sealant. A semi-rigid umbilical cable contains the electrical, hydraulic, and communication lines, and a unique drive mechanism that allows for remote operation and positioning.

The development of this prototype technology was conducted by Engineering Services Inc. (ESI) of Toronto at the request of Enbridge Consumers Gas and was co-funded by Consolidated Edison of New York. Over 2000 joints have been successfully sealed in the last two years and the system is expected to be commercially available within the next year. Internal robotic repair of live mains is an industry first and has the potential to significantly reduce both costs and disruption of road excavations in urban areas.

Commentary by Dr. Valentin Fuster
2000;():V001T05A013. doi:10.1115/IPC2000-170.
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In 1996, ARCO Technology and Operations Support (ARCO TOS) began considering Highly Tensioned Suspended Pipelines (HTSPs) as a promising concept for above ground, cross-country pipelines in Arctic regions. HTSPs resemble high voltage, cross-country power lines. Similar construction methods and support towers are used. The primary differences are that the pipelines are larger in diameter and are supported against out-of-plane wind loads. Three years of development work are summarized in this paper. This work includes analytical modeling, pipeline code compliance, conceptual design of components, and construction studies. Fatigue resistance under North Slope Alaska wind conditions is estimated. HTSPs are judged to be technically feasible and a cost effective alternative to traditional elevated pipelines.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T05A014. doi:10.1115/IPC2000-171.
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SUNcast Polyurethanes Inc. has developed a proprietary process technology that makes it possible to rebuild worn Polyurethane (PU) discs, cups and solid cast pipeline pigs. The technology creates a completely secure bond between the virgin and cured cast elastomer PU enabling rebuilt parts to perform “as new”.

This paper addresses the mechanical characteristics of the bond possible with this technology and offers the results of a case study on a successful program to rebuild over fifty 24″ solid cast pigs for a crude oil pipeline.

Cast elastomer PU is an expensive thermoset polymer which has not been readily recyclable. SUNcast’s technology offers pipeline operators, contractors and inspection companies an opportunity to recycle what is now waste back into high performance pigging products at significant cost savings.

Commentary by Dr. Valentin Fuster
2000;():V001T05A015. doi:10.1115/IPC2000-172.
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Gulf Canada Resources Ltd operates oil processing and water re-injection facilities at Goose River, just South of Valleyview, Alberta. As the oil reservoir is drawn down, the water re-injection is a priority to keep oil production volumes up. The water re-injection pipelines & facilities are extensive & complex systems of headers & pumps at a production Battery, a fresh water Plant & two Satellites. All facilities & injection wells are interconnected by pipeline loops.

A study was undertaken to model the entire water injection system (pipelines & pumps), under a remote & Northern environment. The study included simulation of pipeline route information, flowrates, pressures & ground conditions at strategic locations such as wells & pump discharges. Based on existing conditions a model was configured & calibrated using actual field results. This model was then used to determine the best locations on the pipeline to install added pumping capacity to accommodate the new injection flow rates & pressures.

This paper describes the pipeline facilities and all the steps involved in optimizing the pipeline for water injection purposes. A full description of all facilities together with simulation & calibration techniques will be given in the paper.

Commentary by Dr. Valentin Fuster

Innovative Projects and Emerging Issues: Pipeline Research Projects

2000;():V001T05A016. doi:10.1115/IPC2000-173.
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This study describes the numerical solution and computational implementation of the isothermal transient flow of several different compressible liquids contained in a single elastic pipeline. The method of characteristics is used to integrate the equations of conservation of mass and momentum along the deforming Eulerian characteristic mesh. Integration along the deforming mesh, which is generated as integration proceeds in time, minimizes the need for interpolation so that problem variables are accurately determined at the computed mesh points. On the other hand, since calculated mesh points are not regularly spaced in the x-t plane, interpolations among the computed points become necessary to find the value of variables at a given fixed instant of time along the length of the pipeline. The computational implementation allows for the simulation of flow across locations where there may be changes in nominal pipe diameter, valves or pumps, as well as tracking the position of fluid interfaces as different batches of fluid move along the pipeline, and results are found to be numerically accurate and stable.

Commentary by Dr. Valentin Fuster
2000;():V001T05A017. doi:10.1115/IPC2000-174.
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In the paper a discrete system of particles carried by fluid is considered in a planar motion. The volumetric density of particles is taken between 1% and 2% so that they can be treated within the framework of a discrete dynamics model. The fluid is then considered as a carrier of particles. The Landau-Lifshitz concept of turbulence is used to describe the fluctuating part of fluid velocity. This approach is applied to simulate different regimes (laminar and turbulent) and various states of particle motion (moving bed, heterogeneous flow, and homogeneous flow) using only two parameters, which have to be determined experimentally. These two parameters, found for a particular pipe and for a particular velocity from a simple experiment, then have been used for simulations of flow for other pipe diameters and different velocities. The results agree favorably with experimental observations of the type of slurry flow and critical velocities identifying transitions from one type to another.

Commentary by Dr. Valentin Fuster
2000;():V001T05A018. doi:10.1115/IPC2000-175.
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Simulation of the dynamics of pigs moving through non-isothermal pipelines is presented. The differential mass, linear momentum and energy equations were numerically solved by a finite difference numerical scheme, for compressible flow through pipelines. The fluid flow equations were combined with an equation representing a force balance on the pig. Pressure forces developed due to flow through by-pass holes in the pig, pig acceleration and pig/pipe contact forces were considered. A stick/slip model was developed to account for the distinct friction regimes that prevail depending on whether the pig is stopped or in motion. An adaptive grid technique was employed to account for the moving pig. Heat losses to the ambient play an important role in the fluid temperature distribution. However, for the test cases conducted, the temperature variations caused virtually no effect on the pig dynamics.

Commentary by Dr. Valentin Fuster
2000;():V001T05A019. doi:10.1115/IPC2000-176.
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Parametric formulae derived for offshore structural tubular joints have been assessed for potential use for estimating stress intensification factors for pipe stress analysis. The background to these equations is given and comparisons made for a range of typical geometries. Despite the absence of a “plug” of material in a pipe joint, the tubular joint equations appear suitable for the estimation of stress intensification factors for fabricated tees subjected to moment loading of the branch. It is considered that this approach should be investigated further by code developers.

Commentary by Dr. Valentin Fuster

Innovative Projects and Emerging Issues: Pipelining in Other Countries

2000;():V001T05A020. doi:10.1115/IPC2000-177.
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This paper described the Chinese oil and gas pipeline industry, including its progress, current situation, existing problems and its prospects.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T05A021. doi:10.1115/IPC2000-178.
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The Gasoducto del Pacifico Pipeline Project (GasPacifico), a 543 Km. pipeline transporting gas from the Province of Neuquen in Argentina to major cities in Chile, was accomplished in record time and under budget. The project was executed in a time frame even shorter than a previous fast track project in the region, the GasAndes Pipeline Project which also crossed the imposing Andes mountain range. Relying on the experience of the GasAndes Project, the Project Management Team, achieved success through the innovative implementation of project management techniques tailored to the specific challenges of the GasPacifico Project which include:

- The fast track nature of the project;

- Contractual obligations imposed by the Project Management Agreement between TransCanada International (TCI) and the owner, GasPacifico;

- Environmental contraints (route traversed a national park in Chile and areas of high erosion and instability);

- Seasonal constraints (one summer of construction, heavy rains in winter);

- Two countries with two sets of laws and stringent regulatory regimes;

- Procurement and importation of major equipment, materials and pipe.

The project management techniques balanced the triumvirate of quality, schedule and cost while managing the Owner’s risks within the boundary constraints of:

- Schedule commitments;

- Budget;

- Right-of-way acquisition;

- Regulatory Permits;

- Design challenges;

- Procurement limitations;

- Environment requirements;

- Construction challenges.

This paper presents the project management techniques used to manage these challenges, placing them in a relevant context, with the intent that learnings can be applied to other international projects.

Commentary by Dr. Valentin Fuster
2000;():V001T05A022. doi:10.1115/IPC2000-179.
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The Amazon region has been demonstrating a great oil and gas potential in Brazil and in the neighboring countries, specially the field of Camisea in Peru. However, the development of feasible and economically justifiable transport systems, that can allow the flow of those resources to their potential markets, continues to be the great challenge. In this work, we present some options that can be transformed into competitive and commercial projects. We describe different gas pipeline options, discussing their technical, economic and commercial aspects.

Topics: Pipelines
Commentary by Dr. Valentin Fuster
2000;():V001T05A023. doi:10.1115/IPC2000-180.
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During the last decade, many pipeline companies have been investing time and financial resources in new technologies. There has been a special focus on: a) natural aging of facilities; b) problems with operational procedures; c) more demanding environment legislation; and, d) saving resources through pipeline rehabilitation. In Brazil, most of the Petrobras pipeline network, was constructed twenty or more years ago, and problems caused by aging are now becoming reality. In 1997, the monopoly that Petrobas enjoyed was ended. As a consequence, the enlargement, modernization and operational reliability enhancement of the pipeline network is quite important to ensure that Petrobras products remain highly competitive.

This paper will present the Pipeline Technological Program of Petrobras - PRODUT, and the Brazilian Network of Pipeline Technology (RBTD - Rede Brasileira de Tecnologia de Dutos). Both programs will be responsible for adapting and developing new technologies for pipelines to successfully meet new challenges and to profit from opportunities in the Brazilian strategic scenario.

Topics: Pipelines
Commentary by Dr. Valentin Fuster

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