bluuebunny/crossref_metadata_2025_split huggingface dataset:
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.
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.
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.
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.
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.
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.
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.