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Conference Program
Tuesday, February 13
5.00 - 7.00pm Cocktail Reception, Exhibition
Wednesday, February 14
9.00
Opening remarks
9.15
Determining the velocity required to keep solids moving in liquid pipelines
Dr John Smart, John Smart Consulting Engineers, Houston, TX, USA
It is important to know the velocity required to entrain solids in pipelines during cleaning in order to avoid a build-up of these solids, which can cause pigs to become stuck. This paper presents a method for calculating the required entrainment velocity for pipeline sediment and debris such as iron sulfide, iron carbonate, black powder, and sand. Data presented for various solids can be used to estimate when progressive pigging, jetting devices or gel pigs are required to allow safe passage of pigs through a pipeline carrying oil or water.
9.55
Chemically cleaning pipelines
George Carlisle, Baker Hughes Pipeline Management Group, Houston, TX, USA
Pipeline cleaning is necessary for many reasons, including preparation for ILI, hydrotesting, loss of operating efficiency, and high corrosion rates due to deposits. There are many components to a successful pipeline cleaning project using chemicals, and a systems approach is required to design an effective program. This paper will review these components, with particular emphasis on deposit analysis, which is critical to the choice of a proper chemical cleaner based upon performance requirements.
10.35 Coffee, Exhibition
11.10
Inspection of non-piggable pipelines using ultrasonic Piglet technology
Hans Gruitroij, A. Hak Industrial Services, Geldermalsen, Netherlands
This paper will focus on the inspection of non-piggable pipelines using ultrasonic Piglet technology. The paper will discuss development of the tool; in-line inspection information; development of new data algorithms and their application in enhanced analysis of ultrasonic data to obtain more accurate inspection results; examples of reporting software, including semi-automatic detection and sizing of defects; and a review of recent projects using the technology in the inspection of tank farm lines, an off-plot pipeline, and offshore water injection lines.
11.50
Method for establishing hydrostatic re-test intervals
for pipelines with
stress-corrosion cracking
Dr Ray Fessler, Biztek Consulting, Evanston, IL, USA, and Steve Rapp, Duke Energy Transmission, Houston, TX, USA
Hydrostatic testing is one way to demonstrate the integrity of a pipeline that may contain stress-corrosion cracks. In order to establish appropriate intervals for such tests, it is necessary to make a reasonable assumption about the probable maximum growth rate of cracks that might exist in the pipeline.
Although growth rates have been measured in laboratory experiments, those rates are not meaningful for a buried pipeline, because the growth rate depends upon many unknown factors, such as the condition of the coating, the composition of any liquid in contact with the pipe, the susceptibility of the steel, and the temperature. However, it is possible to infer what a probable maximum growth rate is, from the hydrostatic-test history of a portion of a pipeline
This paper describes a method for establishing hydrostatic-test intervals based upon the assumption that cracks that already led to a service failure or hydrostatic-test failure had a higher growth rate than surviving cracks. That assumption is reasonable, because the cracking conditions at the failed cracks must have been more severe than the conditions around any surviving or future crack. The method does not require any knowledge about the nature of the chemical environment at the surface of the pipe, the susceptibility of the steel, or whether the cracks are high-pH stress-corrosion cracks or near-neutral-pH stress-corrosion cracks. The only data that are required are probable maximum values for the actual yield strength and the actual ultimate tensile strength, which usually can be determined from mill records.
Using this method, it can be shown that the interval lengths are strongly affected by the test pressure. It also can be shown that uniform test intervals are less effective than graduated intervals. In fact, subsequent intervals may be longer than previous ones, even if hydrotest failures occurred in the previous tests. The validity of this method was demonstrated by applying it, in principle, to actual historical data from over a dozen valve sections that have been subjected to multiple hydrostatic tests and showing that, if this method had been used, more failures would have been prevented with fewer tests.
12.30 Lunch
1.50
Development of a predictive model to detect the location of
susceptible SCC areas
Jorge Bonetto, Transportadora de Gas del Sur SA (TGS), Buenos Aires, Argentina
This paper will describe the efforts of Transportadora de Gas del Sur (TGS) to develop a susceptibility model to detect SCC, considering the effects of soils, coatings, operating parameters, and cathodic protection. Based on field research and laboratory tests, TGS were able to obtain cracks similar to those found in their pipeline system, and this allowed assessment of the physical and chemical agents involved in this process. The resulting model contains new features which are not included in the other known models. TGS will use this information to define a new methodology to detect sites where SCC cracks could be present.
2.30
Legal issues in pipeline integrity programs
Chris A Paul, Joyce, Paul & McDaniel,
Tulsa, OK, USA
As a result of recent regulations requiring system risk assessments and internal inspections, along with technical advances - such as improved ILI - that have led to massive volumes of data from these assessments, operators are now confronted with data integration and records retention requirements that can result in increased exposure, including the potential for misinterpretation and misuse of data. Increased knowledge of the data from assessments and the obligation to understand what it means or implies can be imputed to management. This represents a significant shift in liability, potentially changing charges of negligence to allegations of willful misconduct with the possibility of criminal liability. Information needs to be managed, so that it cannot be taken out of context and used to imply deficiencies in programs or be used to create liabilities and exposures. This paper will discuss legal issues with respect to the US pipeline IMP rule. In addition, it will provide potential solutions on integrating legal concerns into the execution of effective pipeline integrity programs.
3.10 Coffee, Exhibition
3.40
Sustaining and Improving the Viability of the Pipeline Infrastructure
Thomas O. Miesner, Miesner LLC, Houston, TX, USA
4.20
Camisea pipeline ruptures, audit,
and next steps
Bill Powers and Carlos Salazar, E-Tech International, Santa Fe, NM, USA
E-Tech conducted an independent evaluation of the Camisea (Peru) natural gas liquids pipeline ruptures and published its initial report “Evaluation of Camisea Pipeline Ruptures and Long-Term Solutions” in February 2006. The pipeline began operation in August 2004 and registered five ruptures and four spills between November 2004 and March 2006. The Peruvian government committed to an independent audit of pipeline deficiencies in March 2006. E-Tech prepared a supplementary report in August 2006 to provide supporting evidence of irregularities in the construction of the pipelines and the independent auditor selection process. The technical audit of Camisea pipeline deficiencies is scheduled to be completed in mid-2007.
5.00pm Cocktail Reception, Exhibition
Thursday, February 15
9.00
An update on the Camisea pipeline (provisional title)
Luis Sotelo and José Luis
Lanziani, Transportadora de Gas del Perú SA, Lima, Peru
9.40
Operator assessment of ILI defects
Kevin W. Ferguson, Panhandle Eastern Pipe Line Co, Houston, TX, USA
With the age of the original Panhandle Eastern Pipe Line (PEPL) Company pipelines, it’s not a matter of if anomalies will be found when an ILI tool is run, it’s a matter of how many and how severe. When a final report is received from an ILI vendor, burst pressures are typically calculated using Modified B31G, 0.85dL. The results can seem unmanageable, but success has been had doing further assessments on some anomalies without excavating them all. This assessment has been developed and performed by PEPL on three sets of Tuboscope ILI data and one set of Baker Hughes CPIG data. The method to be discussed was first employed in 2002. It provides a more accurate characterization of the defect and provides the company the ability to more effectively allocate resources. Efforts have been made to review the color scan of a vendor’s raw High Resolution Magnetic Flux Leakage (HRMFL) data, and perform an assessment using Effective Area Analysis without excavating hundreds of anomalies that prove no threat to the pipeline. This assessment is done by hand on the computer and in many cases returns a burst pressure higher than that calculated using Modified B31G, 0.85dL. The following is a case study that shows how multiple defects have been assessed prior to excavation in an attempt to more accurately characterize the defect, and allow for a better allocation of resources. Digs have been performed to validate the process, and the results will be discussed.
10.20 Coffee, Exhibition
11.00
Response to API 1163 and its impact on pipeline integrity management
Munendra S Tomar and Martin Fingerhut, Applus RTD, Houston, TX, USA
Knowing the accuracy and reliability of ILI measurements is important for determining the scope of any integrity-rehabilitation project, the re-inspection intervals, and the risk associated with the pipeline section examined. The recent introduction of API RP1163 highlights the importance of these metrics. Qualifying these metrics requires verification measurements with accuracies a level of magnitude higher than in-line-inspection. This paper will discuss a laser-based process which uses in-the-ditch measurements that have an order of magnitude greater accuracy than the original ILI-MFL measurements, and which therefore are well suited to qualifying and potentially improving ILI results.
11.40
Leak detection system demonstration at
Equitable Midstream
Dr Scott McLaren, Apogee Scientific, Englewood, CO, USA, and Robert Cooper, Equitable Midstream, Charleston, WV, USA
An innovative leak detection system capable of real-time indication of pipeline leaks was tested on Equitable Midstream lines in March 2006. The infrared-based method was able to detect and discriminate leaks of methane, pipeline gas, hydrocarbon gases and liquids, as well as combustion products in a heavily forested and steeply sloped region. The system was tested in a road vehicle, an all-terrain vehicle and in an aerial application using a helicopter. This presentation will detail the testing program elements, the test operations, and the results. In addition, the planned next steps for the leak detection technology will be discussed.
12.20 Lunch
1.40
ILI performance verification and assessment
Guy Desjardins, Desjardins Integrity Ltd, Calgary, AB, Canada, and Randy Nickle and Mike Read, Alliance Pipeline, Calgary, AB, USA
API 1163 recommends that operators verify the accuracy of ILI measurements following an inspection by comparing the results to excavation results. However, the number of excavations required for this verification is left open to interpretation. This paper presents a method of determining the optimal number of excavations to both verify ILI accuracy and to maintain pipeline integrity. The optimization procedure discussed in this paper balances the number of excavations required to verify ILI accuracy with the increased proven accuracy from increased number of excavations. This optimal number of excavations enables the operator to demonstrate an accuracy of the ILI tool to a level necessary to ensure the continued integrity of the pipeline.
2.20
Predicting corrosion rates for onshore oil and gas pipelines
Dr Julia M. Race, University of Newcastle-upon-Tyne, Newcastle, UK, and Jane Dawson, Leanne Stanley, and Dr Shahani Kariyawasam, PII Pipeline Solutions Business of GE Oil & Gas, Cramlington, UK, and Calgary, AB, Canada
One of the requirements of a comprehensive pipeline Integrity Management Plan (IMP) is the establishment of safe and cost effective re-assessment intervals for the chosen assessment method, either Direct Assessment (DA), In-Line Inspection (ILI) or hydrotesting. For pipelines where the major threat is external or internal corrosion, the determination of an appropriate re-inspection interval requires the estimation of realistic corrosion growth rates.
The Office of Pipeline Safety (OPS 2005) estimate that the ability to accurately estimate corrosion rates may save pipeline companies more than $100M/year through reduced maintenance and accident avoidance costs. Unlike internal corrosion, which occurs in a closed system, the rate of the external corrosion reaction is influenced by a number of factors including the water content of the soil, the soluble salts present, the pH of the corrosion environment and the degree of oxygenation. Therefore the prediction of external rates is complex and there is currently no method for estimating corrosion rates using either empirical or mechanistic equations
This paper describes a scoring model that has been developed to estimate external corrosion growth rates for pipelines where rates cannot be estimated using more conventional methods; i.e., from repeat in-line inspection data. The model considers the effect of the different variables that contribute to external corrosion and ranks them according to their effect on corrosion growth rate to produce a corrosion rate score. The resulting score is then linked to a corrosion rate database to obtain an estimated corrosion rate.
The methodology has been validated by linking the calculated corrosion rate scores to known corrosion rate distributions that have been measured by comparison of the results from multiple in-line inspection runs. The paper goes on to illustrate how the estimated corrosion rates can be used for the establishment of reassessment intervals for DA, ILI and hydrotesting, comparing the benefits of this approach with current industry recommended practice and guidance.
3.00 Coffee
3.10
Combined metal loss and crack inspection of a gas pipeline utilizing ultrasound technology
Roger Vogel and Dr Michael Beller, NDT Systems & Services AG, Stutensee, Germany, Reinhard Dyck and Gerard Lalonde, Transcanada Pipeline, Calgary, AB, Canada, Lee Pollard, Tuboscope Pipeline Services, AB, Canada, and Ray Yates, Tuboscope Pipeline Services, Houston, TX, USA
This paper introduces a new ILI tool, based on the modular LineExplorer range of intelligent pigs. The configuration enables a pipeline section to be inspected for metal loss and cracks in a single run, incorporating true quantitative wall thickness measurement. Major advantages are increased efficiency in terms of pipeline preparation and cleaning, as well as optimizing operations during the inspection run. The paper provides a case study of the inspection of a gas pipeline in Canada using this tool. As ultrasound requires a liquid couplant it was necessary to run the inspection in a suitable liquid batch. The paper will introduce and describe the related operational procedures. Finally the paper will discuss the advantages of using combined inspection technologies and provide a forecast of further developments.
3.50
Remote-Field Eddy Current Inspection System For Small-Diameter Unpiggable Pipelines
Gary Burkhardt and Alfred Crouch, Southwest Research Institute,
San Antonio, Tx, USA
Inspection of natural gas pipelines, particularly for detection of wall loss due to corrosion, must be accomplished periodically to ensure their integrity. Many of these lines have internal restrictions or low pressure/flow rates and will not accommodate inspection pigs using conventional (typically MFL) inspection technology. An inspection tool has been developed, based on remote-field eddy current (RFEC) inspection technology, that is self-powered and can expand to perform an inspection in unrestricted areas, but retract to a smaller diameter to pass through obstructions. This system will have the capability for inspecting 6- to 8-in diameter pipelines containing tight bends and can be launched and retrieved with the pipeline in service.
4.30 End of conference
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