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.

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.

Design, Development and Confirmation of a High Toughness Gas Line Pipe for Alliance Pipeline at Camrose Pipe Company

Through 1999, Camrose Pipe Company manufactured ∼152 km (∼45 000 tonnes) of 1067 × 11.4mm pipe for Alliance Pipeline Partnership Ltd. This section of Alliance’s pipeline was manufactured to a design whose pipe fracture toughness requirements was significantly beyond those historically manufactured in Canada and initiated a major leap in plate/pipe manufacturing toughness capability. The development of line pipe toughness in Canada culminating in this order will be profiled. Further, this high toughness design is at the far reaches of the traditional fracture arrest models. Besides the traditional Charpy energy measure, and to confirm Alliance’s confidence in their fracture arrest design, another two sets of fracture assessment tests were used on a trial and production basis: the API chevron notch drop weight tear test (CN DWTT) energy and the energy of a similar test using an Alliance notch modification. The results of these tests will be reviewed and compared.

High Pressure Gas Pipelines: Trends for the New Millennium

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.

Fracture Behaviour and Defect Evaluation of Large Diameter, HSLA Steels, Very High Pressure Linepipes

Actually, the increase in natural gas needs in the European market, foreseen for the beginning of the next century, compels to develop new solutions for the exploitation of gas fields in remote areas. For natural gas transportation over long distances the hypothesis of a large diameter high-pressure pipeline, up to 150 bar (doubling of the actual one) has been found economically attractive, resulting in significant reduction of the transportation cost of the hydrocarbon. In this contest the interest amongst gas companies in the possible applications of high-grade steels (up to API X100) is growing. A research program, partially financed by E.C.S.C. (European Community for Coal and Steel), by a joint co-operation among Centro Sviluppo Materiali (CSM), S.N.A.M. and Europipe in order to investigate the fracture behaviour of large diameter, API X100 grade pipes at very high pressure (up to 150 bar) has been carried out. This paper presents: the current status of technology of API X100 steel with respect to the combination of chemical composition, rolling variables and mechanical properties the results obtained from West Jefferson tests, in order to confirm the ductile-brittle transition behaviour stated from laboratory tests (DWTT), the results obtained concerning the control of long shear propagating fracture and in particular the results of a full scale crack propagation test on line operating at very high hoop stress (470 MPa). Besides, in order to investigate the defect tolerance behaviour of the pipe with respect to axial surface defect, burst tests with water as pressurising medium have been carried out and the relative results are presented and discussed.

Full-Scale Fracture Propagation Experiments: A Recent Application and Future Use for the Pipeline Industry

A full scale fracture propagation test facility has been developed to validate the design, in terms of the ability of the material to avert a propagating fracture, of a major new pipeline to transport gas 1800 miles from British Columbia in Canada to Chicago in the USA. The pipeline, being built by Alliance Pipeline Ltd, will transport rich natural gas, i.e. gas with a higher than normal proportion of heavier hydrocarbons, at a maximum operating pressure of 12,000 kPa. This gas mixture and pressure combination imposes a more severe requirement on the pipe steel toughness than the traditional operating conditions of North American pipelines. As these conditions were outside the validated range of models, two full-scale experiments were conducted to prove the design. This paper will provide details of the construction of the 367m long experimental facility at the BG Technology Spadeadam test site along with the key data obtained from the experiments. Evaluation of this data showed that the test program had validated Alliance’s fracture control design. The decompression data obtained in the experiments will be compared against predictions from a new decompression model developed by BG Technology. The use of the experimental facility and the model to support future developments in the pipeline industry, particularly in relation to the use of high strength steels, will also be discussed.

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.