Sunlight exposure is known to cause degradation in polymer coatings. However, quantitative data relating exposure to mechanical and corrosion properties is missing. Thus, it is very difficult for pipeline operators to make fair assessment of the impact of stockpiling coated pipe on project economics and pipeline integrity. As a result, a study was undertaken to quantify the effects of sunlight exposure on Fusion Bonded Epoxy (FBE) coating on stockpiled pipe. Sections of production pipe stockpiled in the southern Alberta area for the Alliance Pipeline project was selected, and a plan to evaluate the coating properties at periodic exposure intervals, to a total duration of approximately 2 years was implemented. The coating was tested at both full sunlight exposure condition (12 o’clock position) and with minimal exposure condition (6 o’clock position). The properties evaluated include residual coating thickness, cathodic disbondment, adhesion, flexibility, and impact. These tests were carried out following procedures in CSA Z245.20–98 standard. Results after 15–21 months of aging indicate that the coating with full sunlight exposure, had a reduction in thickness, flexibility and loss of gloss with chalking due to degradation of the FBE coating by the UV radiation. However, there were no significant differences for cathodic disbondment, adhesion, and impact properties compared to the 6 o’clock position.

A corrosion growth modelling procedure using repeated inline inspection data has been employed as part of the maintenance program planning for a pipeline in the Alberta portion of the TransCanada system. The methodology of matching corrosion features between the different in-line inspections, and estimating their severity at a future date, is shown to be an excellent proactive cost saving methodology. Throughout this paper estimated 80% confidence intervals for tool measurement error, total prediction error and growth methodology error are given. In this abstract the values have been rounded. For maximum penetration, for the features reported on three inspections, the confidence interval for total prediction error varies from ±12% to ±17%, and for the growth methodology from ±8% to ±10% of the wall thickness (for the 1998 and 1999 dig programs respectively). For features reported on two inspections the confidence interval varies from ±19% to ±22% for total prediction error (1998 and 1999 digs respectively), and is about ±17% for the growth methodology (for both dig programs). The estimated confidence interval for prediction error in failure pressure is about ±560 kPa for the 1998 dig program. For the 1999 dig program a good estimate of the confidence interval for total prediction error could not be obtained. Assuming the failure pressure data obtained from field measurements were perfect, the estimate of the maximum confidence interval was ±850 kPa. For the laser profile measurement field tool, compared to an ultrasonic pencil probe, the confidence interval for penetration is less than ±2% of the wall thickness. The true confidence interval values in some cases are expected to be smaller than reported above for several reasons discussed in this paper.

Three components are required for stress corrosion cracking: stress, an environment and a susceptible alloy. The environment that causes near-neutral-pH SCC has been established as a dilute bicarbonate environment and the effect of stress on this type of SCC has received a considerable amount of research; however, the third component, the susceptible alloy, has received little research. The effect of microstructure on near-neutral-pH SCC was investigated using the slow strain rate test. The effect of the microstructure on the corrosion properties is also investigated using polarization resistance tests, potentiodynamic scans and electrochemical impedance spectroscopy. The results indicate that the microstructure influences both the SCC and corrosion behaviour.

Ultrasonic testing of metal welds has been in use for many years. Scanning methods using both contact and immersion methods are often used at the time of manufacture and also during periodic in-service inspection programs. But because of a variety of component configurations and potential flaw geometries it is often necessary to perform several inspections, each with a different probe configuration to assure adequate defect delegability. It is possible that a properly designed phased array probe can perform several different inspections without changing hardware thereby reducing inspection times. This presentation reviews the design and operation of ultrasonic phased array transducers and the necessary features to achieve the desired performance. Situations in which these probes have already been implemented effectively are also discussed.

The evaluation and development of the current corrosion defect assessment procedures for pipelines has been based on experimental burst tests of line pipe. In these tests, external corrosion has often been simulated with machined defects of simple geometry. As a result, assessment procedures which model the corrosion defect geometry with only a few parameters, such as ASME B31G, show reasonable agreement with the experiments. However, the degree of conservatism in these assessment methods is undefined when they are applied to complex corrosion defects. The authors have burst over 40 pipes removed from service due to corrosion defects. All corrosion defects on each pipe were measured in detail and the material properties were determined from tensile tests. The currently accepted assessment procedures for corroded line pipe (B31G and RSTRENG) have been applied to the database. The degree of conservatism in these procedures is quantified and a statistical model for the failure predictions is proposed.

Physical forces activated when buried pipelines move relative to the soil can damage coatings. The problem is most common near bends and areas with poor backfill compaction. Most solutions are best implemented early in the design work when pipeline routes, alignments, and operating conditions are being selected. Solutions, in addition to the obvious one of increasing toughness and adhesion of coatings, include increasing radius of bends, avoiding unstable slopes, improving backfill operations, stabilizing operating conditions, and reducing operating pressures and temperatures.

Based on the literature database and information from pipeline companies, the methodologies used to select inhibitors were critically reviewed. Round robin tests were carried out in three laboratories to assess reproducibility of the wheel test. In total, twelve (12) laboratory methodologies were evaluated. Field monitoring was carried out in Alberta at three fields — oily gas, gassy oil and oil transmitting — to support the laboratory evaluation, and to define the conditions under which specific laboratory methodologies can be used with the confidence that the laboratory data will predict field performance. Based on a quantitative comparison of field and laboratory general corrosion rates, pitting rates, and percentage inhibition (calculated from general corrosion rates and pitting rates) under three (3) different field conditions using four (4) continuous and two (2) batch inhibitors, the rotating cage , was ranked as the top methodology. In addition, this methodology is inexpensive and relatively simple to carry out. The rotating cage is recommended as a methodology to be standardized for evaluating and qualifying inhibitors for sour service.

This paper reports the hydrogen permeation behavior of an X-70 pipeline steel in a synthetic near neutral pH field solution under both galvanostatic and potentiostatic conditions. The hydrogen flux through the steel exposed to the solution is influenced by the chemical reactions at the steel surface on the charging side. Results from tests done under potentiostatic and galvanostatic conditions were compared to predictions based on different boundary conditions assumed in solving Fick’s diffusion equations. Constant concentration boundary conditions gave the best fit. It was also found that the diffusible hydrogen generated in a near neutral pH soil environment is likely to be 3 to 10 times lower than the minimum hydrogen concentration required to initiate hydrogen blistering in pipeline steels.

Current methods for estimating the remaining strength of aging, corroded pipelines have been restricted to the capabilities of pressure based engineering models that rely on the definition of hoop stress in the pipe wall. Because in practice, pipelines are subjected to a variety of loading conditions (e.g.; axial bending from settlement and thermal stresses) that act in concert with those derived by internal pressure, a multi-year combined testing and analysis program was initiated by the Alyeska Pipeline Service Company aimed at developing computer tools for the prediction of rupture and wrinkling in corroded pipes. During the program, seventeen full-scale tests of mechanically corroded 48-inch diameter (1219-mm), X65 pipes subjected to internal pressure, axial bending, and axial compression were performed to provide data necessary for the verification of analytical models and failure prediction models. While all of the tests were designed to produce rupture, wrinkling, as defined by the occurrence of a limit moment during the application of bending loads, was produced in eleven of the tests either prior to or instead of rupture. Loading of the pipe was intended to simulate that which would be observed by a pipe in-service and included both load control and displacement control of the applied bending load, and in some tests, intended to define the amount of additional pressure required to cause burst after wrinkling was produced. Results of the tests showed that two different failure modes are produced depending on whether the bending moment is transmitted to the pipe as a fixed load or a fixed displacement, and consequently, the burst capacity of the corroded pipe may not be compromised by the presence of axial loads. This paper discusses the tests performed, including a description of the load schedule and corrosion geometries, and key results of the tests that were used in the development of a new strain-based burst prediction procedure for corroded pipes subjected to combined loads.

Of these various factors that influence the Magnetic Flux Leakage (MFL) signal, stress is the most complex and the least understood. Pipe wall operating stresses may exceed 70% of the yield strength, but much higher local stress levels are present around defects because of stress concentrations. Understanding how these stresses affect MFL signals is crucial to accurate defect depth predictions. We have conducted a number of studies that investigate the effects of bulk and local stresses on magnetic behaviour and MFL signals. Both single defects and interacting (2-hole) defects have been investigated. In addition to MFL studies, we have used a Magnetic Barkhausen Noise (MBN) measurement technique to characterize magnetic behaviour of the sample in response both to local and bulk stresses. In general we find that, for typical inspection geometry (axial magnetizing field and hoop stress) the MFL signal decreases as stress increases. At high flux densities stress effects diminish, but are still significant. Although the general trends described above are common to all defects, different types of defects (through wall hole, blind hole, interacting defects) all display uniquely different MFL stress responses. We attribute this to the difference in local stress distributions (stress concentrations) around these defects.

The resistance to rock penetration and abrasion damage of four advanced pipeline anti-corrosion coatings on buried steel linepipe was quantified by means of controlled pipe burial tests. Production-coated steel linepipes were buried in three different gradations of crushed hard rock, and a Caterpillar 966D wheel loader was driven directly over the buried pipes twice daily for 12 consecutive days. Subsequent excavation and inspection of the pipes showed that the coatings experienced progressively more damage (quantified by the number of holidays) with increase in rock size and progressively less damage with increase in coating thickness. A quantitative relationship between coating damage and coating thickness was defined for the two larger rock sizes.

Over the past several years, investigations have been carried out into the rate of crack growth in pipeline steels in simulated, near-neutral pH, groundwater environment ( NS4 solution). Pre-cracked specimens were subject to constant amplitude loading under various frequencies, maximum loads and R -ratios (minimum/maximum load). Test times varied from about 20 to 400 days. Transgranular crack features, similar to those found in service, have been observed. The extent of crack growth was monitored using either electrical potential drop or detailed metallographic examinations at two laboratories. The resulting crack growth rates from both labs are consistent with a superposition model based on a summation of fatigue (Paris Law) and static (SCC) crack growth rates. Differences between the results at the two laboratories are discussed.

Buried pipelines are subjected to fluid pressure (oil/gas/water), axial loads, moments, and complex load combination histories. As a result, they may develop large compressive strains and curvatures leading to formation of localized buckles or wrinkles in the pipe shell. Recently, full-scale tests on 12.75″ diameter (NPS12) energy pipes have been carried out at the University of Alberta to study the behavior of wrinkle development and the ultimate limiting strains at the wrinkle locations. Different internal pressures, and axial loads were applied to produce a wrinkle, followed by load variations intended to produce fracture that could develop in buried pipelines in the field. Three different axially loaded tests are reported. Two different internal pressures were applied, namely, (i) 0.8py and (ii) 0.4p y , where p y is the required internal pressure to cause the yield stress of the pipe material to be developed in the circumferential direction. Also, two different specimen lengths were adopted. They are: (i) 406 mm (16 inch) and (ii) 736 mm (29 inch). All specimens were loaded axially until the wrinkle formed. It was observed that the pipes are highly ductile and very large compressive strains can be developed without fracture or leakage in the pipe wall. Because the pipe specimens of the first two tests did not fail (i.e. fracture) under monotonically increasing displacements and strains, the third wrinkled specimen was subjected to load histories involving strain reversals. This load history resulted in a low cycle failure after a very few cycles. The paper addresses test procedures, buckling and post-buckling behavior of NPS12 energy pipelines and relates them to three different types of strain measures, namely, material strain, wrinkle strain and overall strain as observed from these tests.

This paper presents the development of a new, simplified criterion, known as PCORRC, for prediction of the remaining strength of corrosion defects in moderate- to high-toughness pipeline steels that fail by plastic collapse. Comparisons against an experimental database indicate that, when toughness is sufficient, the PCORRC criterion reliably predicts the remaining strength of blunt defects using only the maximum depth and maximum length of the defects with less excess conservatism than existing criteria. The value of PCORRC is demonstrated in comparisons that show it capable of reducing excess conservatism significantly in the class of defects that fail by plastic collapse, potentially resulting in significant reductions in pipeline maintenance and repair costs. This new criterion was developed at Battelle under sponsorship of the Line Pipe Research Supervisory Committee of PRC international. The new simplified criterion was developed from a finite-element software analysis model. The analysis software was applied in a parametric investigation to evaluate the influence of geometry and material characteristics on the remaining strength of corrosion defects in moderate- to high-toughness steels that fail by plastic collapse. The model development and parametric investigations demonstrated that: • The failure of this class of defects is controlled by the ultimate tensile strength rather than yield strength or flow stress; • Defect depth and length are the most critical defect geometry variables; • Defect width and material strain hardening are of lesser importance.

Two sections of a 914mm OD (36 in.) TransCanada (TCPL) gas transmission pipeline (predominantly with 9.14 mm wall thickness) were inspected using an ultrasonic liquid coupled crack detection In-Line Inspection (ILI) tool. One of the objectives of the inspection was to establish the condition of the pipeline sections with a known history of stress-corrosion cracking (SCC). Under test was the practicability of inspecting a gas line using a liquid coupled ILI tool, specifically its ability to detect and size defects deeper than 1 mm and distinguish cracks and crack-like defects from other types of anomalies, such as inclusions and laminations. In order to assess the confidence level of the tool, both sections were inspected in two independent runs and the repeatability of inspection was assessed. Cracks and crack-like defects with depths greater than 12.5% of the wall thickness from both runs were compared and correlation was established to assess repeatability. The accuracy of tool predictions was verified in excavations in both sections. 40 reported features, varying in depths up to over 40% were examined with respect to location, type, and size. Examples of defect patterns are shown to demonstrate the accuracy of the inspection method.

Enbridge Pipelines Inc. (“Enbridge”), together with U.S. affiliate Lakehead Pipe Line, operates the world’s longest crude oil and petroleum products pipeline system. These companies transport liquid hydrocarbons from their point of supply to refining markets in the Midwestern United States and Eastern Canada.

Initiation and early growth of stress-corrosion cracking of X-65 linepipe steel in near-neutral pH environment were studied in NS-4 solution saturated with N 2 /5%CO 2 . The occurrence of SCC is discussed in terms of: 1. Generation of an environment that causes cracks to initiate; 2. Initiation and early growth of cracks; and 3. Effect of the mechanical loading spectrum. SEM observations of cracks at specimen surfaces showed that stress-corrosion cracks were initiated at bottoms of corrosion pits. Pits that lead to initiation of SCC can develop from surface discontinuities, which can be geometrical, such as surface roughness, or metallurgical, such as inclusions, second phase particles, etc. The formation of large cracks resulting from coalescence of micro-cracks was studied.

PETROBRAS is conducting a research project with the purpose of investigating the behavior of pipeline with long corrosion defects. In the first phase of this project, burst tests of 9 tubular specimens containing a single external simulated corrosion defect were carried out. These specimens were cut from longitudinal welded tubes made of API 5L X60 steel with an outside diameter of 323.9 mm and a wall thickness of 9.53 mm. All corrosion defects were smooth rectangular defects fabricated using spark erosion. Tensile specimens were tested to determine material properties. Each corroded specimen was instrumented with 10 post-yield strain gages rosettes, one displacement transducer and three pressure transducers. This paper describes the tubular specimens tested and the instrumentation used. The measured burst pressures are compared with those predicted by the ASME B31G, the RSTRENG 085dL , the RSTRENG Effective Area and the DNV RP-F101 (Part B) methods.

Enbridge Pipelines (NW) Inc. (formerly Interprovincial Pipe Line (NW) Ltd.) owns and operates a buried 323mm diameter crude oil pipeline from Norman Wells, NWT to Zama, AB. The pipeline is approximately 869 km in length, with the route following a portion of the Mackenzie River Valley in the Northwest Territories. The pipeline routing is through discontinuous permafrost that has the potential to interact with the pipeline through frost heave, slope movement and thaw settlement that can produce extreme structural stresses in the pipe wall. Given the proper conditions, these stresses may localize and the pipeline will deform plastically, causing pipe wall wrinkling. This paper reviews the general structural design and discusses the inspection and monitoring of the structural integrity of the pipeline, as well as the intervention criteria used to determine when structural mitigation is required. This case study will discuss the discovery of a wrinkle from internal inspection pig data, field dig verification, installation and monitoring of field instrumentation and the pipeline repair technique that was utilized.

Enbridge operates the world’s longest hydrocarbon transmission system. The pipeline infrastructure has experienced additions over its 50 years of operation. The expansions were implemented as successively larger pipe sections upstream from pumping stations. After completing three lines (20″, 24″ and 34″) in parallel configuration, 48″ sections were installed upstream from pumping stations in 1972 and 1973. In order to accommodate future throughput requirements, part of the Enbridge’s 1998 Terrace Expansion Project was designed to connect the 48″ pipe sections into a continuous line with 36″ pipe sections. The first Terrace Expansion design included sending and receiving traps for both the 36″ and the 48″ sections. An intricate network of crossover piping and mainline valves would allow in-line tools to be both launched and received at the diameter transition point without impacting flow. Since the transition points occur anywhere from 10 to 40 kilometers upstream from pumping stations, more aboveground facility locations would be added. Enbridge approached vendors of the different in-line inspection technologies to conduct feasibility studies for building 36″ by 48″ dual diameter tools for pipeline cleaning, geometry and metal loss inspection applications in January 1998. Enduro Pipeline Services, Williamson Industries (TD Williamson) and Pipeline Integrity International (PII) were selected to assemble the working tools based on the viability of their technical presentations and cost estimates. The development of 36″ by 48″ dual diameter cleaning and inspection tools would save Enbridge time and money by eliminating the need to install traps and associated valving at the transition areas. As a result, the accelerated schedule and targeted project completion for inspection in Enbridge’s Terrace Expansion line within a twelve-month time frame was accepted by all parties. This paper discusses the phases of the project from the technical feasibility studies, original and progression of design concepts, test loop execution and actual field use and validation of the tool performance and information.