bluuebunny/crossref_metadata_2025 huggingface dataset:
A Process Using Risk Analysis to Select Construction Methods for Pipeline Crossings of Major Rivers
Authors: Covlin Terri J. , O’Neil Gregg D. , Rizkalla Moness , Morrison Russell
Published: October 2016

Pipeline river crossings pose a significant challenge for pipeline owners and environmental regulators to balance the associated costs and risks, particularly where environmental impacts may occur. For years, NOVA Gas Transmission Ltd. (NGTL) has managed the regulatory approval process using a well-established process. However, regulatory expectations are increasingly neutral to the cost of crossing installations and are demanding a more thorough assessment of a wider variety of river crossing options, particularly trenchless technologies. As a result, NGTL has recently enhanced the internal process by incorporating a structured decision tool. This tool is able to quantitatively assess technical risks as well as ‘soft’ influences such as “Regulatory Relationship” and “Delay in Approval”. The result is a clear decision with the necessary buy-in, where all risks were identified quantitatively and well understood by decision makers.
Suspended Sediment and Turbidity Restrictions Associated With Instream Construction Activities in the United States: An Assessment of Biological Relevance
Authors: Reid Scott M. , Anderson Paul G.
Published: October 2016

Sediment released during pipeline water crossings has the potential to negatively affect downstream aquatic resources. Regulation of pipeline water crossings has been directed through the application of allowable construction methods, timing constraints and numerical turbidity restrictions on construction permits. Past applications of turbidity restrictions are criticized for the following reasons: duration of exposure or sediment deposition effects are not considered; some applied restrictions are for the protection of primary productivity in lakes; and, defined mixing zones do not appear to incorporate expected levels of sediment generation, or sediment transport principles. Alternate approaches to defining permit restriction are proposed.
Improvements to a Centrifugal Compressor Surge Control System
Authors: Martin Blair J. , Patrick James P.
Published: October 2016

A surge control system for a natural gas centrifugal compressor station has been modified in order to reduce shutdowns caused by high discharge temperature and provide a more robust and stable operation. The process consists of a compressor driven by a 14 MW gas turbine and recycle piping, a 16” recycle valve, a PLC based surge control algorithm, a flow measurement element, and a compressor differential pressure transmitter. The control objective is to manipulate the recycle valve to maintain flow through the compressor to a setpoint determined from the differential pressure across the compressor. Field tests were conducted to measure the open loop process dynamics of the valve, piping, compressor and transmitters. From the test data, the relevant process dynamics were determined enabling the development of a first order plus dead time model of the system. The process dynamics are complex due to the gas dynamic effects of the station piping and tend to exhibit inverse and time delayed behavior. Large variations in process gain also create problems with obtaining a consistent flow response under different operating conditions. A stability analysis was completed and the control system was redesigned with several enhancements including derivative control, flow signal filtering, process linearization, and improved controller programming techniques. The results of the modifications are the compressor does not shut down when subjected to transients from other units, the compressor can be started against high head conditions, and the closed loop response time is ten times faster than the previous system. The new system has been in operation since May 1997.
Analysis of Thermal Shock on Nuclear Power Station Pump
Authors: Qing Cao , Yimin Wu , Zhimin Zhang
Published: October 2016

In this paper, a heat conduction equation and a dynamic thermoelastic equation are briefly deduced and established based on Continuum Mechanics.

First, an qualitative discussion is emphatically centered around the couple term and the dynamic term of the equation by means of the dimensional analysis and by considering the combination of the characteristics of the materials and of the thermal load effected on the nuclear power station pump under study.

Second, formulations of the FEM for non-coupled heated equations and quasi-static thermoelastic equations are derived in this paper.

Third, a half space thermal shock problem is used as a computational example in the highlighted research on the varying behavior of the dynamic thermal stress on the temperature slope. The conclusion of the paper provides reliable justification for applying the numerical method.

Finally, the distribution and variety of the temperature field, the thermal stress field and the thermal deformation field at various transient moments on the pump are given.
Proposed Design for Gas Turbine Ingestion of Dry Gas Seal Primary Vent Fugitive Methane
Authors: Parker Todd , Orsten Rod
Published: October 2016

Natural gas transmission systems have many sources of fugitive methane emissions that have been difficult to eliminate. This paper discusses an option for dealing with one such source for operations using turbo-compressor units fitted with dry gas seals. Dry seal leakage ultimately results in waste gas that is emitted to the atmosphere through the primary vent. A simple, cost effective, emission disposal mechanism for this application is to vent the seal leakage in to the gas turbine’s air intake. Explosion hazards are not created by the resultant ultra-lean fuel/air mixture, and once this mixture reaches the combustion chamber, where sufficient fuel is added to create a flammable mixture, significant oxidation of the seal vent gas is realized. In principle, this system is easily implemented with simple modifications to the existing vent piping. However, the inherent safety of ultra-lean fuel/air mixture applies only when the gas turbine is operating with gas turbine airflow overwhelming the seal leakage flow. A potential design solution for managing this emission avoidance mechanism including safe operation during gas turbine shutdown periods is detailed.
The Evolution of Risk Management at Enbridge Pipelines
Authors: Chorney Terris , Hamsher Denise
Published: October 2016

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.
Challenges of Hot Tapping Into a Sour Gas Transmission Line
Authors: Goodfellow Ray , Belanger Rory
Published: October 2016

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.
The National Energy Board’s Revised Onshore Pipeline Regulations OPR-99
Authors: Dubois Nancy L.
Published: October 2016

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.
A Full Scale Experimental Study of Fires Following the Rupture of Natural Gas Transmission Pipelines
Authors: Acton Michael R. , Hankinson Geoff , Ashworth Blaine P. , Sanai Mohsen , Colton James D.
Published: October 2016

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.
Experimental Studies of Releases of High Pressure Natural Gas From Punctures and Rips in Above-Ground Pipework
Authors: Hankinson Geoff , Lowesmith Barbara J. , Genillon Philippe , Hamaide Gilbert
Published: October 2016

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.
Responding to a Northern Pipeline Challenge
Authors: Klatt Terry J.
Published: October 2016

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.
Use of Isolation STOPPLES® for Valve Replacement on Trans Alaska Pipeline
Authors: Pomeroy Glen W. , Norton J. David
Published: October 2016

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.
Multi-Pass Weld Hydrogen Management to Prevent Delayed Cracking
Authors: Dinovitzer A. , Graville B. , Glover A. , Pussegoda N.
Published: October 2016

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.
Effect of Orbital Automatic Welding on the Weld Metal Mechanical Properties in API 5L X65 Natural Gas Transmission Pipe
Authors: Baek Jong-hyun , Kim Young-pyo , Kim Woo-sik
Published: October 2016

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.
High Strength Linepipe: Current and Future Production
Authors: Collins Laurie E. , Kostic Milos , Lawrence Tom , Mackenzie Robert , Townley Nathan
Published: October 2016

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.
Performance of Pipeline Steels in Sour Service
Authors: Elboujdaini M. , Revie R. W.
Published: October 2016

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.
Ductile Fracture Arrest Assessment in a Gas Transmission Pipeline Using CTOA
Authors: Mannucci G. , Buzzichelli G. , Salvini P. , Eiber Robert , Carlson Lorne
Published: October 2016

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.
Husky Moose Mountain Pipeline: A Case Study of Planning, Environmental Assessment and Construction
Authors: Engstrom Carol J. , Goulet Guy M.
Published: October 2016

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.
Case Study: Environmental Considerations of Horizontal Directional Drills
Authors: Slade Dana A.
Published: October 2016

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.
Remediation of a Pipeline Facility MTBE Spill
Authors: O’Rourke Dan J.
Published: October 2016

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.
Testing of In Situ and Ex Situ Bioremediation Approaches for an Oil-Contaminated Peat Bog Following a Pipeline Break
Authors: Wilson J. Jeffrey , Lee Douglas W. , Yeske Brett M. , Kuipers Fred
Published: October 2016

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.
Development and Remote Access of an In-Line Inspection and Corrosion Growth Database
Authors: Desjardins Guy , Bhatia Arti , Morrison Tom
Published: October 2016

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.
Multi-Pipeline Geographical Information System Based on High Accuracy Inertial Surveys
Authors: Czyz Jaroslaw A. , Pettigrew Chris , Pino Hector , Gomez Ruben
Published: October 2016

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.
An Emerging Methodology of Slope Hazard Assessment for Natural Gas Pipelines
Authors: Zhou Z. Joe , Liu Bill , O’Neil Gregg , Rizkalla Moness
Published: October 2016

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.
Challenges in the Development of Market-Based Pipeline Investments
Authors: von Bassenheim Guillermo , Mohitpour Mo , Klaudt Darcy , Jenkins Andy
Published: October 2016

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.
High Pressure Gas Pipelines: Trends for the New Millennium
Authors: Mohitpour M. , van Egmond Trent , Wright W. L.
Published: October 2016

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.
PRODUT: A Pipeline Technological Program to Face the Challenges in Brazil
Authors: Mosqueira Gomes Marcelino G. F. , Baptista Renan Martins
Published: October 2016

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.
Physical Forces on Buried Pipeline Coatings
Authors: King Graeme
Published: October 2016

Physical forces activated when buried pipelines move relative to the soil can damage coatings. The problem is most common near bends and areas with poor backfill compaction. Most solutions are best implemented early in the design work when pipeline routes, alignments, and operating conditions are being selected. Solutions, in addition to the obvious one of increasing toughness and adhesion of coatings, include increasing radius of bends, avoiding unstable slopes, improving backfill operations, stabilizing operating conditions, and reducing operating pressures and temperatures.
The Resistance of Advanced Pipeline Coatings to Penetration and Abrasion by Hard Rock
Authors: Williamson A. I. (Sandy) , Hancock James R. , Singh P.
Published: October 2016

The resistance to rock penetration and abrasion damage of four advanced pipeline anti-corrosion coatings on buried steel linepipe was quantified by means of controlled pipe burial tests. Production-coated steel linepipes were buried in three different gradations of crushed hard rock, and a Caterpillar 966D wheel loader was driven directly over the buried pipes twice daily for 12 consecutive days. Subsequent excavation and inspection of the pipes showed that the coatings experienced progressively more damage (quantified by the number of holidays) with increase in rock size and progressively less damage with increase in coating thickness. A quantitative relationship between coating damage and coating thickness was defined for the two larger rock sizes.
Crack Detection Program on the Cromer to Gretna, Manitoba Section of Enbridge Pipelines Inc. Line 3
Authors: Carroll L. Blair , Madi Moe S.
Published: October 2016

Enbridge Pipelines Inc. Line 3 is an 860mm (34 inch), API 5LX Grade X52 pipeline with nominal wall thickness ranging from 7.14 mm to 12.5 mm. The Canadian portion of the Line runs from Edmonton, Alberta to Gretna, Manitoba. It was constructed between 1963 and 1969 in a series of loops designed to increase the capacity of the Enbridge system. Until 1999 the pipeline operated in a looped configuration with neighboring 24 inch and 48 inch pipelines. Line 3 downstream of Kerrobert, Saskatchewan began operating in straight 34 inch configuration in 1999 following completion of the first phase expansion project known as Terrace Expansion Project that connects the (48 inch) loops with a new (36 inch) pipeline.

In 1997, the Pipetronix (now PII) Ultrascan CD in-line inspection tool was run for 283 km from Cromer to Gretna, Manitoba, to identify long seam cracking and pipe body stress corrosion cracking. This section of the line is comprised primarily of pipe manufactured with a double submerged arc welded long seam with short sections of pipe having electric resistance welded long seams.

There were two primary objectives set forth in this inspection project. The first was to assess the integrity of this section of Line 3 and identify anomalies, which might affect the future operation of the pipeline. The second objective was to evaluate the performance of the Ultrascan CD tool and determine its potential role in the Enbridge integrity program.

A series of excavations have been conducted based upon the analysis of this data and none of the indications identified were considered to be an immediate concern to the integrity of the pipeline. Notably, two of the excavations resulted in the detection of the first two “significant” SCC colonies (based upon the CEPA definition of significant) [1] found on the Enbridge system.

This paper will focus on the tool performance requirements established by Enbridge prior to the inspection run which include specific defect type and size and defects at a maximum sensitivity of the tool. In addition, the information obtained as a result of the excavation program and onsite inspection and assessments. The information gathered, from this program were useful in better understanding the tool tolerance in detecting such defects and to better differentiate between them.
Burst Tests on Pipeline With Long External Corrosion
Authors: Benjamin Adilson C. , Vieira Ronaldo D. , Freire Jose Luiz F. , de Castro Jaime T. P.
Published: October 2016

PETROBRAS is conducting a research project with the purpose of investigating the behavior of pipeline with long corrosion defects. In the first phase of this project, burst tests of 9 tubular specimens containing a single external simulated corrosion defect were carried out. These specimens were cut from longitudinal welded tubes made of API 5L X60 steel with an outside diameter of 323.9 mm and a wall thickness of 9.53 mm. All corrosion defects were smooth rectangular defects fabricated using spark erosion. Tensile specimens were tested to determine material properties. Each corroded specimen was instrumented with 10 post-yield strain gages rosettes, one displacement transducer and three pressure transducers. This paper describes the tubular specimens tested and the instrumentation used. The measured burst pressures are compared with those predicted by the ASME B31G, the RSTRENG 085dL, the RSTRENG Effective Area and the DNV RP-F101 (Part B) methods.
Comparison of Multi-Probe and Phased Array Girth Weld Inspection Systems
Authors: Sjerve Eric M. , Stewart David C. , Bryant George F.
Published: October 2016

This paper presents the results of ultrasonic phased array field trials that were performed on the Maritimes and North East Pipeline 30 inch pipeline project during the summer of 1999 in order to demonstrate the feasibility of using this new technology for inspection of pipeline girth welds. The direct comparison between the two systems showed that the phased array system had equal, or better sensitivity to the multi-probe system in determining the length and vertical extent of the indications. The phased array system detected all of the same indications as the multi-probe system, was inherently more reliable due to less moving parts, and demonstrated much faster switch over times for different configurations.
Using MFL Corrosion Signals to Determine Biaxial Stress in Operating Pipelines
Authors: Crouch Alfred E.
Published: October 2016

Previous work has shown that a corrosion assessment more accurate than B31.G or RSTRENG can be made if pipeline stresses are considered. A shell analysis can be carried out if both the corrosion profile and local pipe wall stresses are known. The corrosion profile can be approximated from analysis of magnetic flux leakage (MFL) signals acquired by an inline inspection tool (smart pig), but a measure of pipe wall stress has not been available. Approximations have been made based on pipe curvature, but a more direct measurement is desirable.

Recent work has produced data that show a correlation between multi-level MFL signals from metal-loss defects and the stress in the pipe wall at the defect location. This paper presents the results of MFL scans of simulated corrosion defects in pipe specimens subjected to simultaneous internal pressure and four-point bending. MFL data were acquired at two different magnetic excitations using an internal scanner. The scanner’s sensor array measured axial, radial and circumferential magnetic flux components on the inner pipe surface adjacent to the defect. Comparison of the signals at high and low magnetization yields an estimate of the difference between axial and hoop stresses. If internal pressure is known, the hoop component can be determined, leaving data proportional to axial stress.