Evaluation of Hydrogen Cracking Susceptibility in X120 Girth Welds

To reduce the cost of long distance gas transmission, high strength pipeline steels are being developed. Implementation of high strength pipeline materials requires the avoidance of hydrogen cracking during field girth welding. A study of hydrogen cracking in X120 girth welds has been conducted. Cracking resistance of both the weld metal and heat affected zone (HAZ) were investigated. The laboratory tests included the controlled thermal severity (CTS) test, the WIC test and the Y-groove test. In addition, multi-pass plate welds and full pipe welds were completed and examined for the presence of hydrogen cracks. The suitability of each test method for predicting cracking in X120 girth welds is determined. The morphology of hydrogen cracks in X120 girth welds is described, and the conditions necessary to prevent hydrogen cracking are identified. Following the laboratory studies, construction of X120 pipelines without cracking was demonstrated through a 1.6 km field trial.

Optimization of Pump Energy Consumption in Oil Pipelines

In the present work an optimization study was conducted with the objective of providing pipeline operators with a simple, spreadsheet-based computational tool to help decrease the electrical energy consumption associated with a particular transport operation. The methodology proposed encompasses the construction of a database of information on the pipeline regarding pumping power consumption, for all possible pumping arrangements and flow rate ranges considered viable for the pipeline. This database is fed to a spreadsheet programmed to calculate the minimum pumping cost for a particular operation. This calculation takes into account, the volume of product to be transported, start and finish times, fluid properties, and the possibility of the existence of a low and a high electricity tariff based on geographical location and time of the day. The methodology was applied to the ORBEL II pipeline in Brazil, and two case studies were conducted. Significant cost savings were obtained by the use of the methodology developed.

Design and Construction of Pipeline Integrated Oil Storage Caverns

In response to industry demand, Hardisty Caverns Limited Partnership (HCLP) has developed cost effective underground storage facilities with a capacity to store 480,000 m3 (3 million barrels) of crude oil. This project is unique through the integration of existing underground salt caverns into a significant North American crude oil transportation hub. Annually, 64 million cubic meters (400 million barrels) of oil move through this hub. This project utilizes existing caverns developed in the late 1960’s. Significant work was required to upgrade the cavern facilities and to construct new surface facilities to integrate the caverns into the crude oil transportation hub. Remote operation of the facility is performed from a control centre in Edmonton. In this paper, the key features of the design and construction of the Hardisty Cavern Storage Project will be presented. Of particular interest are the unique challenges presented due to hydraulic considerations related to cavern operation with multiple product characteristics and to provide crude oil movements exchanges between the cavern storage facilities and both low flow rate feeder pipelines and high flow rate transportation pipelines.

The Evaluation of Failure Pressure for Corrosion Defects Within Girth or Seam Weld in Transmission Pipelines

The failure assessment for corroded pipeline has been considered with the burst test and the finite element analysis. The burst tests were conducted on 762mm diameter, 17.5mm wall thickness and API 5L X65 pipe that contained specially manufactured rectangular corrosion defect. The failure pressures for corroded pipeline have been measured by burst testing and classified with respect to corrosion sizes and corroded regions — the body, the girth weld and the seam weld of pipe. Finite element analysis was carried out to derive failure criteria of corrosion defect within the body, the girth weld and the seam weld of the pipe. A series of finite element analyses were performed to obtain a limit load solution for corrosion defects on the basis of burst test. As a result, the criteria for failure assessment of corrosion defect within the body, the girth weld and the seam weld of API 5L X65 gas pipeline were proposed.

Quantitative Evaluation of Indirect Inspection Reliability and Pipeline Reliability Based on Statistical Methods

To support an External Corrosion Direct Assessment (ECDA), Indirect Inspections were performed on a 44 km section of NPS 6 extruded polyethylene coated natural gas pipeline. Based on previous investigations of the pipeline, external corrosion defects were known to have occurred at coating holidays. Such holidays can often be detected using current voltage gradient surveys and close interval surveys. Two successive ACVG surveys over the pipeline were preformed. In addition, Close Interval Survey data were considered in order to complete the Indirect Inspection dataset. Statistical analysis methods were developed and employed against the data generated from these surveys so that the following objectives could be met: 1. Assess the reliability of the Indirect Inspection technique in terms of its ability to locate coating holidays and hence, its ability to locate potential corrosion features; and, 2. Assess, in quantitative terms, the reliability of the pipeline in terms of its potential for failure, and quantitatively establish the impact that the Indirect Inspection and dig program had in improving that reliability. In completing the first objective, duplicate survey results were compared with Direct Examination results. The statistical analysis provided a means of estimating technique reliability, which was conservatively estimated at 96%. Subsequent evaluation of factors affecting technique reliability indicated that the density of indications and consistency of applying the Indirect Inspection technique had a bearing on the overall reliability. The second objective was completed by applying the results of the Indirect Inspection reliability study to a statistical analysis of corrosion incidence data and corrosion size distributions that were derived from the Direct Examination data. Pipeline reliability was quantitatively expressed as a function of year of operation and the reliability of the Indirect Inspection technique. For the case examined, the Indirect Inspection techniques that were applied were found to increase pipeline reliability by approximately an order of magnitude.

Telluric Compensation for Pipeline Test Station Survey on the Alliance Pipeline System

Geomagnetically induced currents (GIC’s), or telluric currents, can have a profound effect on pipe-to-soil measurements during close interval and test station surveys. Previous studies have investigated how to improve close interval survey data with excellent results. This paper discusses a study on improving test station survey data collected on the Alliance pipeline system and the limitations of the methods used.

TAP Project

International gas market development is towards very long transportation distances (3000–6000 km); the only suitable onshore technology to conjugate economics, large amount of gas conveyed and possibility to exploit remote gas fields appears to be the Very High Pressure (P > 14 MPa), Very High Strength Steel (Steel grade X100 API 5L [1] equivalent) option. Eni Group is going to sponsor a 3 years long project, called TAP (Trasporto gas Alta Pressione) [High Pressure gas Transportation] aimed to demonstrate: • economic evaluation; • technology reliability; • real possibility to build Very High Pressure Pipeline. The project itself is framed into five logical areas: • Evaluation of the applicability of alternative technological solution in extreme enterprise; • Technological innovation, mainly within Eni Group; • FEED (Front End Engineering Development) for strategic route gas pipeline and comparison with LNG option; • Demonstrative construction of a High Strength Steel (X80) pipeline section on Snam Rete Gas Network in Italy; • Demonstrative construction of a Very High Strength Steel (X100 API equivalent) provisioning pilot section pipeline. To achieve this object Eni has involved: • Eni Gas & Power Division as Business Developer; • Snamprogetti as Technology Developer; • Aquater, Enidata, Enitecnologie, Saipem, Snam Rete Gas as specific item expertises; • CSM and Universita` di Bergamo as high qualified partners for lab and full scale testing; • Pipe steel makers and coating producers as fundamental partners to develop new solutions. TAP, within Eni Group, is the final step of a long development research and innovation activity started 8 years ago with two explorative “Long distance pipeline High Grade Steel” projects on Very High Strength Steel performances (strength, toughness, weldability) carried out mainly with the support of Snam, Snamprogetti and Saipem. TAP final goal is to collect, transfer, develop all the possible technological solutions to be ready for building “The pipeline network for Very High Pressure Transportation”.

Modified Equation to Predict Leak/Rupture Criteria for Axially Through-Wall Notched X80 and X100 Linepipes Having Higher Charpy Energy

A method of predicting the leak/rupture criteria for API 5L X80 and X100 linepipes was evaluated, based on the results of hydrostatic full-scale tests for X60, X65, X80 and X100 linepipes with an axially through-wall (TW) notch. The TW notch test results clarified the leak/rupture criteria, that is, the relationship between the initial notch lengths and the maximum hoop stresses during the TW notch tests. The obtained leak/rupture criteria were then compared to the prediction of the Charpy V-notch (CVN) absorbed energy-based equation, which has been proposed by Kiefner et al. The comparison revealed that the CVN-based equation was not applicable to the pipes having a CVN energy (Cv) greater than 130 J and flow stress greater than X65. In order to predict the leak/rupture criteria for these linepipes, the static absorbed energy for ductile cracking, (Cvs)i, was introduced as representing the fracture toughness of a pipe material. The (Cvs)i value was determined from the microscopic observation of the cut and buffed Charpy V-notch specimens after static 3-point bending tests. The CVN energy in the original CVN-based equation was replaced by an equivalent CVN energy, (Cv)eq’ which was defined as follows: (Cv)eq = 4.5 (Cvs)i. The leak/rupture criteria for the X80 and X100 linepipes with higher CVN energies were reasonably predicted by the modified equation using the (Cvs)i value.

Defective Pipeline Fatigue-Life Prediction Using Failure Assessment Diagram Technique

The life prediction, whose results can be used to define the inspection, repair or replacement cycle of in-service pipeline, is a main component of safety assessment of gas and oil pipeline. At present, failure Assessment Diagram (FAD) technique has been widely used in quantitative engineering safety evaluation system of pipeline that contains crack-like flaws. In past work, the authors developed a very useful model to predict the fatigue life of defective pipeline and established a computer calculating method. Based on FAD technique, toughness ratio and load ratio are calculated repeatedly with every crack increment in the model. With the self-developed full-scale test system, the full-scale pipe fatigue test was collected to verify the applicability of this method.

Estimating the Influence of Natural Hazards on Pipeline Risk and System Reliability

Natural hazards (also known as ground movement or geohazards) can cause pipeline failures, with consequences ranging from injury/death, environmental impact, and property damage, to lengthy service disruption and a failure to achieve delivery targets. In North America and western Europe, pipeline failure resulting from natural hazards are typically rare (but costly) events. However, where difficult ground conditions have not been properly accounted for in pipeline design, construction, and operation, natural hazards may have an overriding influence on pipeline risk and reliability. These issues are discussed, and a framework for estimating the influence of natural hazards on pipeline risk and system reliability is introduced.