An Emerging Methodology of Slope Hazard Assessment for Natural Gas Pipelines

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 of Hot Tapping Into a Sour Gas Transmission Line

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.

Field Observations of Cyclical Pipe-Soil Interactions in Permafrost Terrain, KP 5, Norman Wells Pipeline, Canada

The Norman Wells pipeline is an 869 km long, small diameter, buried, ambient temperature, oil pipeline operated by Enbridge Pipeline (NW) Inc. in the discontinuous permafrost zone of northwestern Canada. Since operation began in 1985, average oil temperatures entering the line have been maintained slightly below 0°C, initially through constant chilling year round and since 1993 through a seasonal cycling of temperatures through a range from −4 to +9°C. At one location, 5 km from the inlet at Norman Wells, on level terrain in an area of widespread permafrost, uplift of a 20 m segment of line was observed in the early 1990s. The uplift gradually increased and by 1997 the pipe was exposed 0.5 m above the ground surface. Detailed studies at the site have included field investigations of terrain and thermal conditions, repeated pipe and ground surface elevation surveys, and annual Geopig surveys. The field work has revealed that the section of line was buried in low density soils, thawed to depths of 4 m on-right-of-way, and not subjected to complete refreezing in winter. The thaw depths are related to surface or near-surface flows from a nearby natural spring, as well as to the development of a thaw bulb around the pipe in the cleared right-of-way. Icings indicative of perennial water flow occur commonly at this location in the winter. The pipe experienced annual cycles of heave and settlement (on the order of 0.5 m) due to seasonal freezing and thawing within the surrounding low density soils. The pipe reached its highest elevation at the end of each winter freezing season, and its lowest elevation at the end of the summer thaw period. Superimposed on this heave/settlement cycle was an additional step-like cycle of increasing pipe strain related to thermal expansion and contraction of the pipe. A remedial program was initiated in the winter of 1997–98 in order to curtail the cumulative uplift of the pipe, reduce the increasing maximum annual pipe strain and ensure pipe safety. A 0.5 m cover of sandbags and coarse rock was placed over the exposed pipe segment. Continued pipe elevation monitoring and annual Geopig surveys have indicated that both seasonal heave/settlement and strains have been reduced subsequent to the remedial loading. Introduction of a gravel berm has also altered both the surrounding hydrologic and ground thermal regimes.

Floating-Roof Tanks: Design and Operation in the Petroleum Industry

The floating-roof tank has been the most widely used method of storage of volatile petroleum products since the first demonstration b Chicago Bridge & Iron Company (CB&I) in 1923. There have been many changes and design improvements to that first pan-style-floating roof. A floating roof is a complex structure. It must be designed to remain buoyant even when exposed to combined loads from varying process, weather and product conditions. There is a continued demand for improved floating-roof tanks to store a wide range of petroleum and petrochemical products in compliance with state and federal environmental regulations. Floating roofs are used in open top tanks (EFRT), inside tanks with fixed roofs (IFRT), or in tanks that are totally closed where no product evaporative losses are permitted for release to the atmosphere. This very special type of installation is referred to as a zero emission storage tank (ZEST). Products that might have been stored in basic fixed roof tanks must now utilize a floating roof to limit evaporative emissions to the atmosphere. High vapor pressure condensate service and blended heavy crude oils also present new design challenges to the floating roof tank industry. This paper will review the most prominent styles of floating roofs from 1923 to the present. Design and operating limits for current da floating-roof structures are presented. New trends in environmental regulations and the potential impact on the design and operation of floating-roof tanks will be presented. Current maintenance practices and the effect on Life Cycle Cost Management of the storage syste are also reviewed.

Planning for Purging and Loading of a Newly Constructed Gas Pipeline System Using a Pipeline Simulator

Purging of a gas pipeline is the process of displacing the air/nitrogen by natural gas in an accepted constant practice in the natural gas pipeline industry. It is done when pipelines are put into service. Gas Pipelines are also purged out of service. In this case they are filled with air or other neutral gases. Traditionally, “purging” a newly constructed pipeline system is carried out by introducing high pressure gas into one end of the pipeline section to force air out of the pipeline through the outlet until 100% gas is detected at the outlet end. While this technique will achieve the purpose of purging air out of the pipeline, it gives little or no consideration to minimizing the emission of methane gas into the atmosphere. With the advances of the pipeline simulation technology, it is possible through simulation to develop a process to minimize the gas to air interface and thereby minimize the emission of methane gas. In addition, simulation can also be used to predict the timing of purging and loading of the pipeline. Therefore, scheduling of manpower and other activities can be more accurately interfaced. In this paper a brief background to purging together with a summary of current industry practices are provided. A simplified purging calculation method is described and a simulation technique using commercially available software is provided for planning purging and loading operations of gas pipeline systems. An Example is provided of a recently constructed pipeline (Mayakan Gas Pipeline System) in Mexico to demonstrate how the planning process was developed and carried out through the use of this simulation technique. Simulation results are compared with field data collected during the actual purging and loading of the Mayakan Pipeline.

Minimizing Risk and Improving Operational Availability in the Pipeline Industry

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

Wave Propagation Versus Transient Ground Displacement as a Credible Hazard to Buried Oil and Gas Pipelines

In 1997, a research project was initiated by Southern California Gas Company, Pacific Gas and Electric Company, with support from Tokyo Gas, Osaka Gas, and Toho Gas, to investigate the cause of natural gas pipeline damage during the 1994 Northridge earthquake. As part of this research activity, extensive field and laboratory investigations were performed on a 1925 gas pipeline that suffered several girth weld failures in Potrero Canyon, a remote and unpopulated area just north of the Santa Susana Mountains. The pipeline is operated by the Southern California Gas Company, one of the principle sponsors of the gas utility research project. The investigations into the performance of the pipeline were largely prompted by questions regarding the cause of pipeline damage. Although ground cracking and sand boils were observed in Potrero Canyon following the Northridge earthquake, there were no clear signs of permanent ground deformation near the locations of pipeline damage. Pipeline damage, consisting predominantly of girth weld tensile failure and two instances of buckling of the pipe wall, indicated that significant relative pipe-soil deformation might have occurred. Field investigations were unable to identify surface evidence of permanent ground deformation near the locations of pipeline damage and attention focused on the possibility that the damage could have been caused by wave propagation. This focus was based on the assertions of past researchers that pipelines with poor-quality oxyacetylene girth welds are susceptible to damage from wave propagation. The detailed investigation of The pipeline has concluded that wave propagation was not a significant factor in the pipeline damage and raises questions regarding wave propagation effects as a causative mechanism for pipeline damage in past earthquakes. A simple analytical model of the transient ground deformation that may have occurred in the vicinity of the pipeline damage was found to provide insight into the cause of the ground cracking observed at the margins of Potrero Canyon, approximate magnitudes of differential ground displacements that may have occurred during the earthquake, and the reasons for the spatial distribution of pipeline damage. This model is proposed as the basis for identifying locations where similar earthquake effects can be identified in future hazard assessment studies.

Computer Simulations of Low Concentrations Slurry Flows in Pipelines

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

The Effect of Microstructural Change on Fracture Behavior in Heat-Affected Zone of API 5L X65 Pipeline Steel

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

Formalizing Pipeline Integrity With Risk Assessment Methods and Tools

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