The temperature drop of waxy crude oil after a shutdown is the basic premise for restarting relative mechanical calculation. However, computational accuracy has been paid much more attention excessively in the relevant techniques proposed in the previous researches for this calculation but ignoring the practicability of the calculation results. In this paper a new mathematical model is established for a buried hot crude oil pipeline during shutdown with the simplified complex physical process of oil cooling process reasonably, in which the heat transfer mode of crude oil is divided into pure convection heat transfer and pure heat conduction with stagnation point temperature neglecting the difference of radial temperature. The quasi periodic property theory of soil temperature field is referenced to be as the boundary condition for the thermal influence region. A numerical solution with a structured grid and an analytical solution under polar coordinate are respectively applied for the soil region and other regions including pipe wall, wax layer and insulation layer. The finite volume method is adopted to discretize the heat transfer control equation at the same time the boundary conditions are treated by the additional source term method. The simulation results of the new model are verified by a temperature field tested experiment, especially analyzing the temperature deviation between the simulation and the equivalent mean value of actual oil temperature. At last the effect of buried depth of pipeline on the temperature profiles during normal operation and the temperature drop process of crude oil were investigated based on the simplified model.

An intensive effort was undertaken to understand the fracture behavior in a recent TCPL pipe burst test. The 48-inch diameter X80 pipe was buried in soil at the Spadeadam Test Site, but since it was desired to have the gas and pipe cooled to the minimum service conditions of −5°C, a 50-mm thick polyurethane foam (PUF) insulation was sprayed on the entire pipe test section. This was a reasonable precaution since freezing of a high water content soil around a large-diameter pipe burst test can require significant cooling capacity or a much longer duration to get to the burst test conditions. In this burst test, the crack propagated much farther than anticipated by traditional predictive approaches such as using Charpy energy to predict the minimum ductile fracture arrest toughness, assuming that soil backfill conditions existed. To explore this burst test behavior, two aspects were examined. The first was an assessment of the properties of the PUF insulation relative to the soil properties, and the second was the toughness evaluated by instrumented DWTT testing. The 50-mm thickness of the PUF insulation corresponded to about 8.3% of the pipe radius. In past loose-fitting steel sleeve crack arrestor burst tests, if the radial clearance was greater than 5.5% of the pipe, then a ductile fracture propagated under the arrestor regardless of its length with no change in speed. Hence if the PUF could be easily compressed, then the pipe in this burst test would behave as if it was in a non-backfilled condition. Non-backfilled pipe requires much higher toughness to arrest a ductile fracture. So perhaps the pipe in this burst test condition acted somewhere between non-backfilled and backfilled conditions — an aspect that might need a much more comprehensive computational model to better assess. Additionally to assess how material toughness played a role in this burst test, detailed instrumented toughness testing was conducted on material taken from several of the pipe lengths in the burst test. The evaluations of the Charpy energy to the DWTT energy suggested that one of the pipe materials may have behaved more like an X100 steel than an X80 steel. Correction factors on the predicted arrest toughness are well known to be needed for the Battelle Two Curve method (BTCM) when applied to X80 and X100 pipes. However, even with these corrections on the Charpy energy, arrest was predicted with soil backfill in several cases where in the actual test, the crack propagated through the pipes. Hence toughness corrections by themselves did not explain the test results. Additional calculations were then done assuming a non-backfilled condition (as suggested from the PUF property evaluation) along with the appropriate grade effect correction from the DWTT testing, and propagation was properly predicted in each case consistently with the burst test. So the fracture behavior in this burst test was somewhere between those of backfilled and non-backfilled pipe. As a result of this investigation it appears that the PUF insulation played an important role in crack arrest behavior, and because of its presence may have required much higher toughness than was actually needed for the actual service conditions of pipe buried in actual soil backfill.

MV (Medium Voltage) controller lineup electrical protection is crucial in protecting the equipment from large scale damage upon the occurrence of an electrical fault, reducing the time to restore power, thereby minimizing the impact to liquids pipelines operation. The paper discusses typical electrical failure modes that may occur in MV controller lineups, and demonstrates practical relaying engineering techniques that enable fast and effective fault clearing. Electrical faults in the MV controller lineup are often arcing type, commonly involve ground. Mitigating arc hazards in MV Class E2 controller lineups has traditionally been challenging without sacrificing the protection selectivity. As the paper demonstrates, a relaying scheme with the combined use of high-speed light-sensing and overcurrent detection will effectively mitigate the incident energy, while maintaining the protection selectivity for non-arcing overcurrent events. For new MV controller lineups, in addition to the “high-speed light detection and fault interruption”, zone-selective interlocking (ZSI) can also be a practical solution in improving relay protection speed, thus reduce the chance of severe arc flash occurrences. ZSI is particularly effective for fault occurrences on the line side of the phase CTs, busways or main incoming circuits. The ZSI scheme can be implemented on both Class E2 and circuit breaker (VCB) type MV controller lineups, however, with slightly different trip logic due to the limited fault clearing capability of the contactor. Although there are multiple contributing factors, the direct causes of electrical failures in MV controller lineup are commonly related to improper power cable installation and handling, potentially leading to premature insulation breakdown due mainly to the proximity effect and/or partial discharge. Inadequate cable separation and prolonged fault trip delay can increase the possibility of arcing fault occurrence. This can usually be mitigated through appropriate cable spacing, adequate conductor insulation, and optimized fault detection schemes. The paper provides overviews of the mechanisms of proximity effect and partial discharge propagation, and the modern relaying approaches for accurate fault type discrimination and facilitating fast fault interruption. Two case studies are provided in the paper as an aid in understanding the electrical fault mechanism originated from cable insulation failure, demonstrating the incident energy reduction before and after the implementation of high-speed light detection and fault interruption solutions on an existing MV controller lineup.

Multiphase transportation is widely used as the oilfield development moving into deepwater. Temperatures will have a drop when multiphase flow from normal region to cold region in the subsea pipelines or experience Joule-Thomson cooling in choke valves. The unexpected temperature drop can lead to viscosity increase and ice suspensions formation, and even ice blockage. In this study, viscosity variation of ice suspensions formed from water-in-oil emulsions was measured. Viscosity started to increase when ice suspension was forming. The experimental results showed that viscosity increased firstly until a maximum value upon ice formation and then decrease to a stable value in the process of ice suspension formed from w/o emulsion. So the critical viscosity included a maximum value and a stable value. The effects of temperature (subcooling) and shear rates on viscosity variation were investigated. Experimental results indicated that ice suspension viscosity increased faster with lower temperature (larger subcooling) and stronger shear disturbance. Heat transfer was a principle factor that determined viscosity increase in the process of ice suspensions formation. Therefore, good insulation of subsea pipelines is required to avoid ice blockage when emulsion flow from normal region to cold region.

Dielectric elastomer sensors (DESs) are a new class of mechanical strain and vibration sensors and can be used to fabricate unique intelligent elastomeric products with tailor made properties. Here, a new sensing method was developed to measure strain and vibration of pipelines using a combination of highly flexible DESs and novel polyurea coatings (intelligent coating). The structural health monitoring system described here is suitable to improve safety and maintainability of critical pipeline sections. Such system can be applied to both steel and to polymeric or composite pipes. Basically, the investigated DESs are compliant capacitors consisting of an elastomeric polyurethane film, highly flexible electrodes and surrounding polyurethane insulation. Due to the building block chemistry of polyurethane elastomers, the mechanical, electrical, thermal and chemical properties of DESs can be adapted to specific application scenarios. The versatility of the sensor concept allows the design of DESs with variable hardness (Shore A: 30 to 95), active surface (1–1500 cm 2 ), thickness (200 μm – 1 cm) and sensitivity. Applied electrodes consist of conductive particles which are integrated in an elastomeric matrix. The capacitance of a DES is proportional to the area of overlapping electrodes (active sensor area) and it is inversely proportional to the elastomeric film thickness. In case of deformation due to tensile or pressure loading, the active sensor area expands while the thickness of the elastomeric film decreases. Both effects result in a measurable, linear increase in capacitance. When installed along the axial direction on the exterior of a pipe, the DES is sensitive to strain changes parallel to the pipe axis and allows to detect displacement or deformation that may cause the pipeline to fail. The strain sensitivity of the system depends upon the precision of the capacitance measurement. A typical setup allows a measuring accuracy of at least 0.1 % strain.

A comprehensive and integrated suite of computer software routines has been developed to simulate the flow of liquids in pipelines. The fluid properties module accommodates Newtonian and non-Newtonian liquids or mixtures including corrections for changes in properties with temperature and pressure. The hydraulic model calculates pressure drop in single or looped pipelines based on the diameter, route (length) and profile data provided. For multi-product pipelines the hydraulics module estimates energy loss for any sequence of batches given the size and fluid properties of each batch, and the velocity in the pipeline. When the characteristics of existing or proposed pipeline pumps are included, location and size of pumps can be optimized. The effect of heat loss on pressure drop is predicted by invoking the module which calculates the fluid temperature profile based on operating conditions, fluid properties, pipe and insulation conductivity and soil heat transfer data. Modules, created to simulate heater or cooler operations, can be incorporated to compensate for changes in temperature. Input data and calculated results can be presented in a format customized by the user. The simulation software has been successfully applied to multi-product, fuel oil, and non-Newtonian emulsion pipelines. The simulation and operation of a refinery products pipeline for the transportation of propane, butane, gasoline, jet and diesel batches will be discussed. The impact of high vapour pressure batches (i.e., propane and butane) on the operation of the pipeline and on the upstream and downstream facilities will be examined in detail.

Sulphur is extracted from sour gas at Shell’s Caroline Gas Plant in the foothills of the Rocky Mountains in Alberta, Canada. A buried pipeline carries the liquid sulphur 41 km cross-country to a railhead at Shantz. Sulphur is difficult to handle by pipeline because it remains solid at temperatures up to 118.9°C. Challenges posed by high operating temperatures necessitated many innovations during design and construction. The liquid sulphur pipeline is built from two coaxial pipes. The inner pipe carries liquid sulphur while the annular space carries circulating hot water under pressure. The inner pipe has a diameter of 219.1 mm (NPS 8) and the outer pipe has a diameter of 323.9 mm (NPS 12) with 80 mm of high density urethane foam insulation. A hot water return line with a diameter of 168.3 mm (NPS 6) and 50 mm of insulation completes the loop for the continuous circulation of hot water. Two hot water heaters are installed, one at each end of the line. The system can carry between 0 and 5,100 tonnes of liquid sulphur per day on a continuous basis, and can be easily expanded to 8,000 tonnes per day by adding extra pumps. Construction of this unique pipeline required skilled workers operating under sometimes difficult climatic conditions. The route winds through hilly terrain in the foothills of the Rocky Mountains and crosses under three major rivers. Careful planning led to the successful completion of the world’s longest liquid sulphur pipeline on time and under budget. The pipeline has now been operated successfully for more than three years.

Flowline thermal insulation is essential for deepwater field development when long distance subsea tieback is required. Proper flowline insulation design can prevent hydrate and wax formation during production, as well as provide sufficient time, in the event of an unplanned well shut-in, for resuming production before the product temperature drops below the critical temperatures. Although many insulated flowline configurations, (i.e., insulated pipe-in-pipe and insulated multi-flowline bundle) have been installed, insulation designs are usually based on insulation material technical data obtained at standard conditions. Few publications are available on the effects of insulation material aging, operation temperature, and environmental pressure (in the case of a pressurized annulus of pipe-in-pipe or bundle) on the flowline insulation performance. In this paper, such effects on the thermal insulation properties of an insulated flowline, in both steady state and cool down conditions, are discussed. Insulation material thermal conductivity test data are presented at various pressures, temperatures, and aging effects (duration between manufacture and test). The test data are applied to typical flowline insulation designs and comparisons made with cases when these effects are neglected. Based on the test and analysis results, recommendations are made for insulated flowline designs.

A pipe-in-pipe (PiP) technology was selected to transport hot fluids through muskeg and multiple obstacles dealt with Horizontal Directional Drillings (HDDs) in Northern Alberta. The system offers both integrity and construction advantages. • The outer pipe provides an obvious secondary barrier to any leak. It also provides the basis for a surveillance system with a sensitivity more than 1000 times the sensitivity provided by the standard mass-balance. • The system is pre-constrained: the inner pipe is pre-heated using electrical heat tracing at a temperature such that the system, once installed, has thermal stresses reduced by half and thus permits the installation of the high-temperature pipeline in non-competent soils with no expansion loop and no external anchor. • The insulation system between the two pipes reduces the heat loss to only 0.3 W/(m 2 .K), leading to a very long cool down time. Finally, the pipe-in-pipe can be a simple solution to high-risk and/or high scrutiny areas such as HDDs, sensitive wetlands, unstable soils, etc.

Enbridge safely operates thousands of miles of piggable pipelines throughout North America. Within stations and terminals however, much of this piping has been uninspectable using conventional free-swimming in-line inspection technologies due to design and/or operating conditions. As a result, other direct assessment inspection techniques have been used to determine the condition of these assets. Seeing the need for smarter and more effective inspection and screening technologies for unpiggable pipes, many inspection tool vendors have developed new tools that can inspect these lines, although these often require pipe modifications. The Enbridge’ Facilities Integrity group manages the integrity of all unpiggable piping and associated piping components associated with approximately 25 tank farms and over 150 pump stations. Inspections are planned based on a systematic analysis of integrity threats and consequence based risk factors. Inspection techniques are selected on a case-by-case basis to best manage the integrity of the asset based on the defined threats. Successful execution of these inspections is dependent on support from many functional areas. The effectiveness of the procedures for the planning, resources, inspection, repair/remediation, and incorporation of the findings is critical to the success of the program. Enbridge is constantly looking for proven technology that will improve the integrity management of these assets. Enbridge is also actively supporting the development of new technologies that, once proven, will change the way we think about integrity management. Tethered inspection tools, bi-directional free swimming tools and tools that can navigate tight fittings and short radius bends are just a few of the new and innovative in-line inspection technologies Enbridge has been investigating over the past few years. In addition, Enbridge is currently involved in trials and validation of several inspection tools for the purposes of initial screening including guided wave technology, above ground screening methods, and tools that can detect corrosion under insulation. This paper will discuss Enbridge’s experience with these new inspection technologies, highlighting the planning and preparation required to successfully complete these inspections, the benefits and challenges associated with these technologies, and the ongoing work being done to improve the application of these technologies in the future.

Coatings are used on pipelines throughout the oil and gas industry for a variety of applications including corrosion protection, temperature maintenance, and weight control. These coatings also present a barrier to inspections for damage and typically need to be removed prior to inspection with nondestructive evaluation (NDE) methods. This has led to the development of improved NDE methods for detection and characterization of damage without removing the coatings or insulation. This paper describes adaptations of JENTEK’s Meandering Winding Magnetometer (MWM ® )-Array technology for improved NDE in pipelines, including rapid and reliable imaging of damage, such as external corrosion, external mechanical damage, and stress corrosion cracking (SCC). The MWM-Array technology uses magnetic field-based sensor arrays and model-based inverse methods to determine electromagnetic and geometric properties of the pipeline material, which are then related to specific damage conditions of interest. This technology has been successfully applied in the aerospace and manufacturing industries and provides substantially improved performance for imaging surface and buried damage through coatings and for curved surfaces compared to conventional NDE methods. Several representative applications are described. These include: 1) imaging of near surface material loss through moderate thickness coatings (less than 1.5-in. (38 mm)); 2) imaging of mechanical damage through thin (less than 0.25-in. (6.35 mm)) coatings; 3) imaging of SCC through very thin (less than 0.030-in. (0.76 mm)) and thin (less than 0.25-in. (6.35 mm)) coatings. For SCC, digital imaging of damage regions and automated analysis tools for assessing individual cracks has the potential to be a replacement for magnetic particle inspection (MPI). Initial work has demonstrated these capabilities in a laboratory environment with some field testing and ongoing work is transitioning this technology into field environments.

This paper describes a 3 rd party review of geometry pig inertial surveys of the ConocoPhillips Alaska, Inc.-operated Alpine 14-inch diameter oil and 12-inch diameter water pipelines at the horizontal directionally drilled (HDD) Colville River crossing. The geometry of these pipelines is periodically surveyed to monitor for potential thaw-induced differential settlement between thaw-stable and thaw-susceptible soils along the HDD profile under the river. Preliminary reviews of the elevation profiles from multiple surveys showed significant run-to-run variations within the HDD. However, considering the long distances between the reference elevation tie points, the observed elevation differences appeared to be within the position accuracy of the inertial survey specifications. As a follow up to the initial review, a more detailed 3 rd party review of the data was performed. This paper describes how the elevation, pitch and bending strain data from four different inertial surveys performed for each pipeline over a five year period was processed to look for monotonic trends and/or locations of significant pipe deformation. It was determined that the bending strains for both pipelines were small compared to the allowable strains and that the most critical locations for both pipelines occurred in the vicinity of the end of the below grade casing and the adjacent aboveground pipe support. At each end of the HDD, the pig data signatures indicate the presence of a sagbend curvature lobe at/near the end of the casing and an overbend curvature lobe at/near the adjacent pipe support which is clearly indicative of relative movement between the below grade section of the pipe and the pipe support. The response at the pipe support was confirmed by visual inspection of the pipe where minor buckling damage to the external sheet metal insulation jacket at the ends of the saddle was observed. The results from this review were used to develop a recommended forward-looking geometry monitoring schedule.

A new type pipeline integrity and risk management system based on 4D-GIS ( 4 D imensional G eographic I nformation S ystem) is proposed in this paper. 4D-GIS is a unique GIS platform which can manage 3D plus time change data and processes spatial-temporal pipeline integrity data effectively. The utilization purposes of the developed system are: 1) To understand the current/future physical status of pipeline, 2) To detect anomalies of pipelines and to propose solutions for replacing or repair, 3) To transport natural gas safely and stably. For 1), the methods for spatial-temporal data integration and data input are proposed. The developed system integrates a variety of pipeline integrity data sets such as pipeline maps, construction specification, documents, corrosion data, and cathodic protection voltage data. For 2), two new type diagnosis functions, which process integrated data, are proposed. One is the pipe safety diagnosis based on corrosion spreading prediction. The other one is insulation health diagnosis. For 3), stress distribution on corrosion and HCA ( H igh C onsequence A reas) is calculated. Thus, the system can be utilized for the decision making for pipeline-specific- problem solving by both pipeline operators and field pipeline managers. The processing results for realized functions are shown. Furthermore, the architecture of pipeline integrity and risk management system is described.

Many gas transmission facilities utilizing centrifugal compressors and large diameter piping experience high amplitude high-frequency noise and vibration. In addition to being a nuisance noise problem, failures of thermowells, instrumentation, and attached small-bore piping can result. Such problems can also occur in the piping itself when high flow velocities and internal obstructions are present. Many times, high frequency noise problems are treated with acoustical insulation (lagging) on the pipe. However, with an understanding of the underlying physics of two- and three-dimensional acoustics it is often possible to modify the piping design to reduce or eliminate the high frequency energy. Two high-frequency energy generation mechanisms predominate in most industrial processes; flow induced (Vortex shedding) and pulsation at multiples of running speed (blade-pass frequency). Once this energy is generated, amplification may occur from acoustical and/or structural resonances, resulting in high amplitude vibration and noise. Many tools exist for analysis of structural resonances and one-dimensional acoustical resonances. Analysis of high-order acoustics can be accomplished using sophisticated numerical methods (FEA, or BEA); however, a simplificaiton of the three dimensional wave equation which has been reduced to a function of zeroes of the 1st order Bessel function, the speed of sound, and internal pipe dimension can also be used successfully. Several references provide lists of the zeroes of the Bessel function; however, most of these references only provide solutions up to m,n = 6. Field tests have identified cross-wall modes up to m = 30. Therefore, a table is provided for zeros for m = 0–32 and n = 0–8.

Continued development of the oilsands in the Fort McMurray area of Alberta lead to a need for the MacKay River Pipeline. This heavy oil pipeline provides long-term, cost-effective transportation for production from the MacKay River area. The pipeline is designed to transport bitumen with little or no dilution (dry bitumen). In order to operate without diluent, the bitumen must be heated. Heat must be retained using a continuous layer of insulation, which ensures that viscosity remains low. The high operating temperature and the environment, through which the pipeline passes, were major challenges encountered during the design and construction phases. This paper focuses on the design, selection criteria, and testing of the coating system and discusses the important aspects of construction.

Underground heated oil transportation within the processes of Petrobras/Transpetro is a critical issue because of the need to maintain the temperature of the oil in the pipeline network from the point of origin to destination with as little heat loss as possible. Insulated pipelines using polyurethane rigid foams as insulation have been used for many years for this transportation process. However, instrumentation inspections have shown a severe external corrosion process in some insulated pipelines after a number of years in operation. Due to the extent of the insulated pipeline network in Brazil, this kind of problem was possible to identify only after some leakage emergencies. After a deeper investigation in the field it was verified that the pipe protection and insulation system was not adequate for avoiding the corrosion process. In order to prevent and avoid any greater damage to the environment and mainly to the communities living around these underground pipeline zones, a quick review of the entire methodology was necessary. The focus of this article is to describe the identification of this corrosion problem by field experiences and the solution found by adapting the EN 253 norm for pre-insulated bonded pipe systems for underground hot water networks.

The superficial electromagnetic methods are widely applied for non-destructive control of pipeline technical condition. For this purpose we have developed the theory and field technology for the pipeline inspection that allows: 1) determining the pipeline trajectory (plane position and depth), 2) delimitation of pipeline intervals with an insulation coating damage, and 3) estimating the condition of a cathodic protection system. The proposed method is based on the approximation of a metallic pipeline by a heterogeneous transmission line with variable distributed parameters: resistance and inductance along a tube (tube wall thickness) and leakage conductance. The field operations consist in measurements of magnetic field above a pipeline and voltage only on the control posts. The interpretation process includes the iterative inversion of the magnetic component in order to determine the pipeline depth and current distribution along pipeline. The current difference corresponds to leakage current and allow estimate the leakage resistance. We illustrate the practical application of this method using the obtained results for pipeline inspections in Mexico. Based on the voltage and current simulations for the infralow-frequency band (0–1kHz) we have evaluated the feasibility of the time lapse measurements of the magnetic field in some fixed points for the early prediction of an insulation damaging process.

The Norman Wells pipeline has operated for over 20 years, transporting crude oil from Norman Wells, Northwest Territories to Zama, Alberta. The pipeline route traverses 869 km of discontinuous permafrost. The stability of the slopes along the route required that rapid thawing of ice-rich permafrost be avoided, lest the high porewater pressures that develop on thawing would cause instability. To reduce the thawing rate, a layer of wood chips was used as surface insulation. Approximately one-half of the insulated slopes were instrumented with thermistors and piezometers to monitor the thawing and the development of porewater pressures. This paper compares the actual performance of the insulated and non-insulated slopes to the original design predictions. Thaw depth is presented in terms of the square root of time. The likely original design intent of insulated sites was to restore a level of surface insulation that would represent a “cleared but otherwise undisturbed surface condition”. The actual performance of most of these sites was more dramatic than this. Factors that may have contributed to the greater than expected thawing are examined, including site orientation, preclearing, and soil type.