Liquid Pipeline Stress Corrosion Crackingproceedings.asmedigitalcollection.asme.org/data/...average crack depth greater than 30 to 35% wall, and with a length greater than 10 inches,

L I Q U I D P I P E L I N E S T R E S S C O R R O S I O N C R A C K I N G

Ravi M. Krishnamurthy Barry Martens Pipeline Integrity International Rainbow Pipe Line Company, Ltd.

David Feser Peter Marreck Reg MacDonald Rainbow Pipe Line Company, Ltd. Rainbow Pipe Line Company, Ltd. Mobil Oil Canada

ABSTRACT The integrity management of a pipeline with stress

corrosion cracking was accomplished in two distinct phases. The initial phase, from 1993 to 1996, consisted of excavations that quantified damage (stress corrosion cracking & corrosion), fracture mechanics modeling and hydrostatic testing, with a short-term objective of restoring Maximum Operating Pressure (MOP). Limited testing was conducted to evaluate the hydrostatic line on the 610 mm (24") diameter line. The second phase, from 1996 until present, included running a shear wave ultrasonic tool, a zero degree ultrasonic tool, fracture mechanics modeling and rehabilitation digs. The extensive data collection during rehabilitation was utilized to evaluate the relationships between cracking susceptibility and degree of Stress Corrosion Cracking (SCC) with parameters such as soil type, drainage, topography and magnitude of pressure fluctuations. Corrosion products predominantly consisted of iron carbonate, very much characteristic of the low pH SCC mechanism. Following the shear wave ultrasonic tool, a zero-degree compression wave ultrasonic tool was utilized to characterize the long axial corrosion locations with potential shallow cracking. A re-inspection plan was developed using crack growth rates, hydraulic simulations of pressure fluctuations and excavation data. The reliability of the pipeline was increased and the overall integrity management costs were reduced. Presently, hydrotesting is not being used to manage integrity of Rainbow's system.

INTRODUCTION The Rainbow Pipe Line Company, Ltd. (Rainbow) operates 740 km (460 miles) crude oil pipeline, which runs from Zama Lake in Northwestern Alberta, to Edmonton in central Alberta. Figure 1 is a map of the pipeline system. The pipeline

transports 33,000 m3/d (210,000 bbl/d) of liquids. Light crude, heavy crude and condensates are batched separately, and the pipeline is controlled with a SCADA system that is located in Sherwood Park, near Edmonton. The northern section of the mainline consists of a 508 mm (20") diameter segment with Maximum Operating Pressure (MOP) of 7,250 kPa (1,050 psi) from Zama station to the Utikuma Pump Station. The remainder of the mainline is a 610 mm (24") diameter section from Utikuma Station to Edmonton with an MOP of 5,380 kPa (780 psi).

The pipeline was constructed in 1966. The 610 mm (24") section utilized Grade 359 (X52) ERW and SAW steel pipe with 6.35 mm (0.250") wall thickness. The pipe was double-wrapped with polyethylene tape. Regular internal pipeline inspection was conducted every 5 years beginning in 1979 with a low resolution Magnetic Flux Leakage (MFL) tool to check for corrosion. No significant problems had been detected and no major pipeline leaks had occurred during the first 27 years of operation.

In February of 1993, the 610mm (24") line ruptured downstream of the Utikuma station. The ruptured pipe was analyzed, and cause of the rupture was determined to be Stress Corrosion Cracking (SCC) in combination with long, axial corrosion. Subsequent to this failure, Rainbow voluntarily reduced the MOP. The planned internal inspection survey utilized a high resolution MFL tool and was conducted in June of 1993. In July of 1993 a second rupture occurred, and again the cause was determined to be SCC in combination with long, axial corrosion. At this point, Rainbow further reduced the MOP voluntarily. The results of the high resolution MFL tool were analyzed, and although many anomalies were detected,

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nothing significant was found at the site where the second rupture later occurred.

The cause of these failures was attributed to near neutral pH SCC. The fracture surface was characterized by transgranular quasi-cleavage. At the failure locations crack lengths ranged from 250 to 500 mm, and the crack depths ranged from 40% to 90% wall thickness. The SCC appeared to occur predominantly with long, axial corrosion, especially at the two failures sites. The depth of corrosion for the two failures was 0 - 45% and 0 - 66% respectively.

The integrity program for the 610 mm (24") line from Utikuma to Edmonton was initiated in 1993, and has continuously evolved to increase pipeline reliability. The program can be divided into two distinct phases. The first phase of integrity management required excavation supported with fracture modeling and regular hydrostatic testing (1). The first phase focussed on learning more about the extent of SCC on the 610mm (24") OD section and led to the restoration of MOP to 5,380 kPa (780 psi). Inline inspection, rehabilitation and fracture modeling guided the second phase of integrity management. The focus of this second phase was the long term integrity and maintenance of the pipeline.

INITIAL APPROACH: 1993-96

Excavation, Damage Modeling, Hydrotesting: 1993-94

Following the reduction of MOP from 5,380 to 3,000 kPa (780 to 435 psi), an extensive excavation program was undertaken. The corrosion data from a high-resolution MFL tool was utilized to identify most excavation locations. The 275 excavations completed in 1993 and 1994, amply demonstrated the prevalence of SCC. Nearly 117 joints exhibited some degree of SCC, however, only nine joints exhibited crack depths greater than 15%. Despite shallower SCC, the severity of significant SCC was unclear. The deeper and longer cracks predominantly occurred in the regions where there was localized corrosion. There were only seven locations where the estimated crack depths were greater than 20% of the wall, and these existed in the areas with localized corrosion. Cracks typically had depths less than 5 to 7% in the absence of corrosion. Additionally, the crack length was always less than 10 mm in the absence of corrosion, but lengths up to 90 mm were noted in localized corrosion. In contrast to the rupture site, where the crack length was around 250 to 500 mm, the maximum individual crack length found during the excavation was 90 mm. The presence of SCC was readily identified, however the extent of significant SCC was unclear. The damage to the pipeline was modeled using the level 2 failure assessment diagram as described by the British standard PD6493 (2). The fracture propensity was described using the elastic-plastic parameter J-integral. J is a contour integral that

describes the crack tip stress and strain (3). The curvature effects were neglected because the diameter to thickness ratio is 96 for this pipeline, consequently the J was established by flat plate assumptions. Additionally, since the crack length has no impact on applied J, when length is greater than 100 mm, the modeling assumed an infinite length. The crack growth rate was modeled from literature rising J experiments (4). The detailed equations that were utilized have been described elsewhere (1). The time period to fracture susceptibility was described as a function of crack depth and applied pressure. For example, if the applied pressure at a location was 4,590 kPa (665 psi), and defect depth was 20% of the wall, the pipeline has a safe operating period of 6.2 years. Such data was generated for pressure range from 1,035 to 5,380 kPa (150 to 780 psi), and for initial crack depths ranging from 10 to 40% of wall.

The excavation data had indicated that the pipeline had defect regions with crack depths around 20% wall and corrosion depths around 20%. The damage modeling indicated that if the MOP was restored, the maximum pressure in the older section of the line would be around 3,792 kPa (550 psi). This implied a safe operating period of only around 9 months, if the defect depth was around 40% of the pipe wall. Consequently, a decision was made to hydrotest the line prior to restoration of MOP.

It was established that, if the hydrotest was conducted at a pressure of 90 to 95% SMYS, it would provide safe operating period of approximately 5 years, as shown in Table 2. Based on crack depth and loading levels, the net section of the pipe would yield; and following unloading after yielding the plastic strain would be retained at the Crack Tip (CT). This was defined as a blunted CT. The prediction of a limit load that results in net section yielding is utilized to predict blunted flaws. Re-testing requirements were defined based on cracks that weren't blunted, and it was assumed that these could potentially grow to failure.

In addition to load levels during hydrotest, the duration of loading is critical to cause rupture of locations with critical cracks. The issue of time dependent plasticity has been amply demonstrated by experiments with compact tension specimens using lower strength (283 & 441 MPa) pressure vessel steels (5-7). This study demonstrated that hold times until failure for predominant number of CT specimens ranged from 0.004 to 4.4 hours (5). This study conclusively demonstrated that when constant load is close to collapse load, non-inclusion of time-dependent material behavior would be non-conservative (5). Additionally, a faster loading rate will result in a shorter time to failure (5). Based on such literature data, the hydrotest was conducted at 90% SMYS for 4 hours, and rate of pressure increase was approximately 21 kPa/min (3 psi/min).


The actual test was carried out with no ruptures, which according to Table 2 implied the absence of critical defects. The prediction was that at 90 to 95% SMYS, defects with an average crack depth greater than 30 to 35% wall, and with a length greater than 10 inches, could fail. The excavations to date have been consistent with this prediction.

Excavation, Rehabilitation, Hydrotest Evaluation: 1995-96:

Excavations continued following the hydrotest, in an effort to characterize SCC south of Flatbush Pump Station. The locations of excavation sites were identified using absolute operating pressure and corrosion data. Sites that exhibited linear corrosion over lengths extending beyond 120 to 250 mm (4.7 to 10") were chosen for excavations. The success in locating sites with SCC in depth greater than 10 to 15% increased in 1995 and 1996 as compared to the earlier programs, as shown in Table 1. All such sites with cracks were sleeved. This process utilized epoxy to cover the defect area, heat to expand the sleeves, hydraulical force to squeeze the sleeve to pipe, and the longitudinally weld in place. This sleeve installation resulted in a 50% hoop stress reduction on the pipeline.

An experiment to simulate the actual hydrotest was conducted, using samples from the pipeline with extensive SCC in combination with long, axial corrosion. Two samples were utilized for the test, one of the samples with extensive SCC had a welded sleeve, and another sample had extensive SCC with no sleeve. The sleeved section of the pipeline was tested at 100% SMYS for 8 hours, whereas the unsleeved sample was tested to 90% SMYS for 4 hours. It is important to note that no failure was noted in the laboratory samples, and this result is consistent with the predictions in Table 2. In the sample with no sleeve, the maximum depth of the largest defect was 35% wall, whereas the average depth was around 23% wall, and the length was less than 64 mm (2.5").

The crack depths of blunted samples ranged from 14 to 37% of the wall, with individual crack lengths ranging from 0.88 to 2.25 mm (0.034 to 0.089"). There was one crack, which was about 23% in depth and around 1.5 mm long, which exhibited no blunting. This blunting behavior demonstrates a more conservative result compared to the predictions. The blunting was established with a metaliographic section as shown in Figure 2, and was verified using a scanning electron microscope as shown in Figure 3. The plasticity ahead of a crack, as shown in Figure 3, is considered to indicate blunting. In contrast a crack that exhibited no blunting, also had no signs of plasticity ahead of the crack, as shown in Figure 4. The predicted depths and the associated safe period prior to re-hydrotesting were as summarized in Table 1. There were one or two cracks that exhibited tearing as shown in Figure 5, and

the cause for this is presently unclear. No such tearing was noted in any of the cracks from the welded sleeves. The predicted dimensions for a hydrotest failure were an average crack depth of 29% wall with a length in excess of 254 mm (10"). All the cracks in the sample that experienced the simulated hydrotest had length and depth smaller than that predicted to fail a hydrotest. The hydrotest predictions are considered adequate, albeit conservative.

The above discussion supports the argument that hydrostatic testing, as mitigation against SCC is a viable option. An inline non-destructive inspection tool could, however, potentially provide critical information regarding the subcritical cracking on the pipeline. A series of pull tests were conducted to evaluate the reproducibility and repeatability of the shear wave Crack Detection ultrasonic inspection tool (CD tool). These tests confirmed the ability of the CD tool to identify SCC and demonstrated that discrimination was also possible. Consequently, this CD tool was utilized to characterize the cracking on the 610 mm (24") pipeline. The results from that inspection and excavation are discussed here, and have formed the basis of integrity management since November 1996.

APPROACH: 1996-PRESENT

Crack Detection; Excavation; 1997-98

The CD tool utilizes shear wave ultrasonic to characterize cracks greater than 1 mm (0.04") in depth and lengths greater than 30 mm (1.2") (8). When the distance between cracks is less than 1 mm (0.04"), they are characterized as a single crack. The cracks were discriminated under different categories of depths; ranges include <12.5%, 12.5 to 25%, 25-40% and greater than 40%. A steady tool velocity just under Im/sec (3.3 ft/sec) was achieved during the inspection CD tool run. Following the CD tool run in late 1996, an extensive excavation plan was undertaken to rehabilitate and validate the predictions from this tool.

Numerous new SCC sites were located in early 1997 on the pipeline following the inspection run of late 1996. The excavation program initially focussed on cracks with predicted depths greater than 25% wall. The state of the external and internal wrap for each site was carefully recorded. The corrosion product was analyzed using X-Ray Diffraction analyses (XRD) and Energy Depressive Spectroscopy (EDS). Following the detailed assessment of corrosion, the crack depths were locally recorded by grinding. The crack depths were recorded along the length of a colony. Consequently, the maximum crack depth and average crack depth were established at nearly every location. During the first year of excavation, nearly 85% of the selected locations exhibited SCC. The SCC with a variety of morphologies was located


based upon results of the CD tool. Figures 6-8 show photomicrographs of the various morphologies of SCC discriminated by the CD tool. It includes SCC with localized corrosion (Figure 6), SCC within deeper corrosion (Figure 7), and SCC that is off longitudinal along the disbanded spiraled tape-wrap coating (Figure 8). Additionally, Figure 9 shows a long sharp edged corrosion site that was identified as SCC by the CD tool. This tool was unable to discriminate certain sites that exhibited excessive corrosion. Many of these sites were identified as metal loss sites with shallow cracking by the CD tool inspection, but were actually just corrosion sites. Cracking occurring in a large cluster was also noted on the pipeline. The 15% inaccurately predicted sites included laminations or long valley corrosion with sharp edges.

The CD tool predictions were also compared to known SCC at previous excavations (1994-96), and it was concluded that all SCC defects that met the shear wave tool threshold requirements had been identified. This data included corrosion and SCC information from nearly 500 excavations, and certain sites were re-excavated to re-characterize the anomalies. It was determined that the CD tool reliably identified defects above its threshold. Consequently, it was established that all critical defects on the pipeline were identified, and hydrostatic testing was no longer required to mitigate SCC. The hydrostatic testing will identify cracks, which are critical in depth and length. All indications from the excavation data revealed that such defects did not exist in the system.

Continued Rehabilitation, Ultrasonic Compression Wall thickness: 1999-2000

The rehabilitation program was continued into the year 2000 to evaluate defects where the depths weren't discernible with the shear wave CD tool. Numerous sites described as metal loss were excavated to ensure the absence of cracking. Consequently, the proportion of SCC located dropped in the years 1999 to 2000. The rehabilitation data for the last three years have been summarized in Table 3. However, the indications identified by the CD tool have been 100% accurate in locating linear indications, whether they are SCC, laminations, corrosion, or a combination thereof.

The success in utilization of the CD tool is demonstrated when comparing the proportion of defects located that were greater than 10% wall thickness. During the years of 1993 to 1996, 400 joints were excavated as part of the rehabilitation program, and only 30 had defects greater than 10% wall. In contrast, following the inspection 150 joint excavations revealed 112 joints with defects greater than 10% wall. Consequently, a dramatic increase in detection and rehabilitation of subcritical cracking was achieved.

In order to facilitate integrity management of the pipeline a semi-quantitative assessment method is used, to estimate of failure probability and failure consequence for the pipeline. The failure probability is described as a function of number of defects, defect depth and operating pressure. The pipeline is divided into five-mile sections, and all sections are plotted on this matrix. The excavation programs are addressed to reduce the probability of failure of every five-mile section of this pipeline.

For every five-mile section, life predictions were made utilizing a previously developed model (1). The crack growth rate model utilized was based on cyclic data on this X52 pipeline. These experiments utilized cyclic loads at a variety of stress ratios and maximum J, and represent an accelerated description of cracking (9). This work was part of a joint industry program at Canmet Research Institute. These sections move across on the failure probability axis based on the elastic-plastic modeling. Additionally, the inspection frequency is also predicted for every five-mile section depending on the operating pressure, and it ranges from 4.2 to 22 years.

Despite the predominant portion of the pipeline demonstrating iron carbonate as a corrosion product, there were two five-mile sections that exhibited iron sulfide in the corrosion product. During every excavation, corrosion product was acquired. XRD quantified the distribution of the compounds, and the EDS verified existence of elements. This was conducted to ensure that sulfur was not present in any organic form in the corrosion product. Iron carbonate (siderite) was the predominant solid indicating carbon dioxide induced corrosion in nearly 98% of the samples. However, there were a few sites that exhibited iron sulfide around 5 to 30% concentrations. Nearly all of the iron sulfide was noted in one five-mile section of the pipeline. The number of SCC sites and the crack depths in that region were markedly higher than in the other regions of the pipeline. The proportion of cracks with depths greater than 20% was also higher in that region. The presence of a sulfate reducing bacterial environment will accelerate crack growth rate under the same loading conditions. That region of the pipeline is considered to be at a higher risk to SCC than the rest of the pipeline.

The CD tool has one limitation, and that is the inability to discriminate a shallow crack (<12% wall) in the presence of deep corrosion. Such defects, which have an effective depth that equals corrosion plus crack depth, could be deleterious to the pipeline. Locating such defects is critical to the continued quest for achievement of increased pipeline reliability. Consequently, it was determined that the compression wave (zero degree) ultrasonic corrosion tool (UT corrosion tool) was necessary. The UT corrosion tool was run in the Rainbow's 610mm (24") mainline in April 1999. This tool was configured with a corrosion threshold of 0.8mm (0.03"), resulting in any


corrosion shallower than 0.8mm (0.03") would not be detected. This threshold was selected to limit the amount of data collected, while still allowing for the detection of significant shallow corrosion defects. Following the UT corrosion tool run an excavation program was undertaken based on the results from both the CD tool and UT corrosion tools.

In addition to rehabilitating corrosion defects that compromised pipe integrity, additional shallow corrosion defects were identified that demonstrated a linear character and occurred in regions where there was higher susceptibility for SCC. Three such sites were identified that had shallower cracking in deep corrosion, which wasn't reported by the CD tool and the previous MFL tool runs. Figure 10, shows a typical C-Scan for a corrosion that exhibited linearity, high differential pressure and occurring in regions that exhibit SCC. The white line is representative of the corrosion. Figure 11 is a photomicrograph of corrosion with SCC identified using the CD tool. It is critical to note that SCC was only observed in 50% of the sites identified using this methodology. This demonstrates the need for exhibiting caution regarding integrity management of cracks solely with the shear CD tool. For the 610 mm (24") Rainbow pipeline, this resulted in increased reliability of the system.

DISCUSSION

The occurrence of cracking in the neutral pH environment exhibits limited correlation to differential pressure and stress ratio (minimum to maximum pressure). A detailed hydraulic flow model was utilized to predict the pressure along the pipeline, and this pressure is dependent on whether a light or a heavy crude is transported through the system. This flow model was utilized to estimate the minimum and maximum hoop stresses at various locations, where SCC was either predicted or located on the pipeline. In Figures 12 and 13 the stress ratio and pressure differential are plotted as a function of maximum crack depth at SCC locations excavated in the years 1997-98. There is a distinct tendency for the deeper cracks to occur at larger differential pressures and at lower stress ratios. Crack depths ranging from 10 to 40% were noted when the differential pressure was greater than 1,000 kPa (145 psi). Additionally, at stress ratio's greater than 0.8 the crack depths were lower than 30% wall. This field data indicates that cyclical load is a factor in SCC, which is consistent with models proposed in the literature. It is important to note that cracking was exhibited at the lower stress ratios and higher differential pressures: and this indicates either initiation at a later stage in the life of the pipeline and/or lower crack growth rates.

A limited correlation was found with the extent of SCC and depth of SCC with soil and drainage. There is a predominant occurrence of SCC in lacustrine and moraine till (sandy till and

silty clay) soils, as shown in Figure 14. Lacustrine materials are postglacial deposits consisting of sand, silt or clay, and are well sorted or stratified. Moraine is poorly sorted mixture of particle sizes ranging from clay to boulders and unstratified. Topographically they are in ranges that are undulating. Means analyses compares sets of data to evaluate whether there are any differences, and how significant are such differences. As shown in Figure 15, the crack depths are significantly lower, with 90% confidence, in organics over clay-type soils as compared to lacustrine and moraine. The higher propensity for cracking in lacustrine and moraine may be due to increased soil stresses, or perhaps higher porosity ensuring water availability at disbanded locations.

There is also an increased tendency for SCC occurrence in well drained and imperfect drainage conditions as shown in Figure 16. Additionally, the means analyses shows that the cracks are significantly deeper in the well-drained and imperfectly drained locations as shown in Figure 17. The poor drainage soil has significantly lower crack depths as compared to well and imperfect drainage at a 95% confidence level. This is consistent with the absence of sulfate reducing bacteria along the pipeline system. Stagnant conditions are more conducive to bacteria, which might imply that poor drainage should correlate to SCC. The absence of this is consistent with predominant cracking in well-drained and imperfectly drained soil. These trends are different than that noted on the pipeline system with data from the initial excavation program from 1994 to 1996 (1).

The rehabilitation of sub-critical cracking has reduced the risk of a leak or rupture on this pipeline system. The CD tool is a key element of pipeline rehabilitation, but it is believed that the UT corrosion tool is also required to ensure SCC mitigation. In the future integrity management of the 610mm (24") Rainbow pipeline system will include continued refinement of the modeling, re-inspection with CD and UT corrosion tools, combined with rehabilitation using the compression sleeves. This is envisioned as a long-term program, which will have decreasing inspection frequencies as crack growth rates and corrosion growth rates are further quantified. The trends of parameters such as stress ratio, differential pressure, soil type, drainage and topography can be utilized either; to mitigate cracking on the existing pipeline system, or to assist in identification of SCC susceptibility on other pipeline systems.

CONCLUSIONS

Pipeline integrity management for Rainbow's 610mm (24") pipeline is being accomplished without hydrostatic testing, but rather utilizing in-line inspection tools and pipeline rehabilitation program. The fracture mechanics predictions have been consistent with observations regarding the impact of hydrostatic tests. Additional metaliographic and fractographic


analyses will be critical to further validation. The hydrostatic testing has been proven to be an adequate short-term integrity management tool. The predominant corrosion product of iron carbonate indicates a carbon dioxide induced corrosion, and near neutral pH SCC. Sulfate reducing bacteria (SRB) are not the major cause for the SCC on the Rainbow system, however indications are that presence of SRB's could accelerate cracking in very localized areas if present. There are indications that the propensity for cracking is higher in certain soil and drainage types, and at higher cyclical loads. These indications coupled with corrosion inspection data can be utilized to identify the presence of SCC on pipeline systems.

REFERENCES

1. R.M.Krishnamurthy, R.W. MacDonald, P.M. Marreck, in International pipeline Conference 1996, Calgary.

2. PD 6493: 1980; British Standards Institution, March 1980. 3. T. L. Anderson, in " Fracture Mechanics: Fundamentals &

Application, CRC Press, 1991. 4. B. Harle and J. Beavers, paper No. 242, published in the

annual NACE conference, 1994. 5. T. Ingham and E. Morland, in Elastic-Plastic Fracture:

Second Symposium, STP, ASTM, 1989. 6. G. Green, R. F. Smith and J.F. Knott, in Proceedings,

British Steel Corp. Symposium on the Mechanics and Mechanisms of Crack Growth, M.J. May, Ed., Cambridge, UK, April 1973, Paper 5.

7. G. D. Fearnehough, in Proceedings, British Steel Corp. Symposium on the Mechanics and Mechanisms of Crack Growth, M.J. May, Ed., Cambridge, UK, April 1973, Paper 16.

8. H.Wilhems, O.A. Barbian, and N. I. Uzelac, in Internatiational Pipeline Conference, 1998, Calgary.

9. Wenyue Zheng et al., Joint Industry Project on Stress Corrosion Crack Growth, 1998. R.N. Parkins and B.S. Delanty, in Eigth Symposium in Line Pipe Research , 1993, Houston.


Rainbow Pipe Line Company, Ltd.

100 km

Pipe Lengths 4" - 91 km 6" - 65 km 8"-104 km 10" -13 km

2C" - 46C km 24" - 297 km

Figure 1: Map of the Rainbow Pipeline System


Figure 2: Photomicrograph of one crack that is blunted, and the shorter crack intact

I P R B G I

Figure 3: Fracture surface of a blunted crack, with plasticity at tip of the SCC crack

Transgranular auasi-cleavase

Liquid Nitrogen failure

Figure 4: Transgranular quasi cleavage surface with no blunting; no signs of plasticity between the transgranular and failure in liquid nitrogen

Figure 5: Tearing noted ahead of a crack tip; potentially generated during hydrotest


Figure 6: SCC in localized corrosion located by the CD tool

wmmmmm • I M i M W M f M M M B M B " '

Figure 8: SCC that is located off longitudinal due to direction of disbondament located by CD tool.

.. •• . '• .: ... ... :: .

Figure 7: SCC in deep corrosion (>20% wall) located bv the CD tool.

Figure 9: Corrosion long and longitudinal, valley type, misinterpreted by the CD tool as crack; due to sharp edges.

Figure 10: C-Scan from the UT corrosion tool, depicting linear corrosion, with the white line. This was corrosion with cracking

Figure 11: Deep corrosion with shallow corrosion, located at the prediction of the C-scan from Figure 10.


Figure 12: Stress corrosion crack depth versus differential pressure experienced at that location

Figure 13: Stress Corrosion Crack depth versus stress ratio (minimum pressure/maximum pressure) experience at that location

Number of SCC Occurences vs. Soil Type Crack Depth greater than 10% wall

Soil

Figure 14: Number of SCC occurrences, with depth greater than 10% wall, as a function of soil type

Lacustrine Oraanics/cl Sandv Till Siltv Clav

So

[(onflwav ))

illMaans 1)

Figure 15: Means analyses showing that with 90% confidence the organic type soil has a smaller crack depth as compared to other soil types


Figure 16: Number of SCC occurrences, with depths greater than 10% wall, as a function of Drainage

Figure 17: The poor and very poor drainage exhibit significantly lower crack depths as compare to other drainage types at 90% confidence.

Year No. of Joints No. of Joints Joints w/ Joints w/ Reason for Excavation excavated w/SCC > 1 5 % SCC >10% SCC

1993/94 275 117(42.5%) 9 (3.3%) 27 (9.8%) Deep Corrosion (MFL) 1995 105 50 (47.6%) 8 (7.6%) 18(17%) Deep Corrosion (MFL) 1996 40 18(45%) 13 (32.5%) 13 (32.5%) Shallow Corrosion (MFL)

& high pressure regions

Table 1: Summary of excavation programs from 1993 to 1996

%SMYS Appl. Crack Crack OPERATING PRESSURE:-Rehdyro: years (X-52) Press. (Failure) (Blunting) 545 500 450 400 350 300

(psi) (%Wall) (% Wall) 70 758 > 44% > 37.5% 0.64 0.91 1.31 1.88 2.71 3.97 75 812 >41% > 32.5% 1.35 1.79 2.44 3.33 4.59 6.48 80 867 >38% > 28.0% 2.35 2.99 3.93 5.21 7.00 9.61 85 921 >36% > 23.5% 3.78 4.71 6.03 7.80 10.24 13.74 90 975 >34% > 19.0% 5.80 7.08 8.88 11.27 14.50 19.03 95 1029 >29% > 14.5% 8.59 10.31 12.71 15.84 19.99 25.66

Table 2: Summary of predicted crack depths at blunting and failure, and the associated re-testing frequencies for a range of applied pressures

Year No. of Joints No. of Joints Joints w/ Joints w/ Reason for Excavation excavated w/SCC > 1 5 % SCC >10% SCC

1997 34 29 (85%) 22 (52%) 26 (76%) Crack Detection tool 1998 42 30 (71%) 20 (47.6%) 26 (62%) Crack Detection tool

(bulk was long. Corrosion) 1999 44 28 (64%) 13(29.5%) 20 (45%) Crack Detection tool 2000 30 24 (80%) 14 (46.6%) 18(60%) Crack Detection tool

Table 3: Summary of the excavation program from 1997 to 2000


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Liquid Pipeline Stress Corrosion Crackingproceedings.asmedigitalcollection.asme.org/data/...average crack depth greater than 30 to 35% wall, and with a length greater than 10 inches,