Paper No.
541
USE OF IN-LINE INSPECTION
DATA FOR INTEGRITY
MANAGEMENT
Patrick H. Vieth Kiefner & Associates, Inc. P.O. BOX 268 Worthington, Ohio 43085 Steven W. Rust Battelle 505 King Avenue Columbus, Ohio 43201 Blaine P. Ashworth TransCanada PipeLines TransCanada PipeLines Tower 111-5th Avenue Calgary, Alberta, Canada T2P 3Y6
ABSTRACT In-line inspection is a proven technology used by pipeline operators to monitor the integrity of their pipeline. The information provided by the inspection can be used to identify immediate integrity concerns and can be used in the development of long term integrity plans. This paper provides a case history of methods developed and implemented for one pipeline operator to ensure the short-term and long-term integrity of their pipelines. The focus of this paper is the use of high resolution magnetic flux leakage (MFL) inspection tools in the detection, and sizing, and assessment of corrosion-caused metal loss. INTRODUCTION TransCanada PipeLines (TCPL) operates 14,500 km of natural gas transmission pipelines. Their pipeline system is comprised of up to seven (7) parallel pipelines which are routed through southern portions of Saskatchewan, Manitoba, Ontario, and Quebec. Most of these pipelines were constructed between 1956 and 1982, and they range in diameter from 508 mm to 1066 mm (20-inch to 42-inch). Two line breaks occurred in 1994 attributable to external corrosion-caused metal loss (galvanic corrosion). These line breaks were the first major service failures due to corrosion in their 40-year operating history. In response to these failures, a corrosion risk assessment model was developed. It was used to prioritize in-line inspections for locations that may have sustained corrosion-caused metal loss. Based upon the results of the risk assessment, a long range program was developed to inspect the entire pipeline system. Another corrosion failure occurred in 1996. In response to these failures, the in-line inspection program was accelerated such that the entire pipeline system
Copyright @1999 by NACE International. Requests for permission to publish this manueeript in any form, in part or in whole must be made in writing to NACE International, Conferences Division, P.O. Box 218340, Houston, Texas 77218-8340. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in the U.S.A.
(except sections coated with fusion bonded epoxy) would be inspected by the end of 1999. The number of inspections and kilometers of pipe inspected by year is summarized in Table 1. The pipeline operator identified the need to develop a formalized in-line inspection (ILI) management program for conducting and responding to corrosion-caused metal loss inspections. The purpose of this formalized program was to ensure accurate, consistent, and thorough handling of the data and to maximize the benefits of conducting an in-line inspection. An overview of this program is described in Reference 1. As part of this program, a two-phased excavation program was implemented. Phase 1 excavations are planned for locations that have been identified by the tool to be potentially immediate integrity concerns. These locations are typically excavated within 120 days of completing the inspection. Under specific circumstances, a location is excavated as soon as possible and a pressure reduction is implemented until the excavation is completed. Once the immediate integrity concerns have been addressed through the Phase 1 excavation program, the ILI data are used to develop a long term program to address corrosion features that have not been excavated and to establish a reinspection interval, Excavations that are identified through this analysis are referred to as the Phase 2 excavation program. The focus of the remainder of this paper is the process followed to identify potential Phase 2 excavations and to establish reinspection intervals for the nearly 10,000 km of pipe inspected in 1997, 1998, and 1999. APPROACH The Phase 1 excavations are identified through a deterministic approach. That is, locations are identified for excavation if the reported depth of corrosion is greater than or equal to 70°/0 wall loss or have a predicted failure stress less than or equal to 100% of the specified minimum yield strength (SMYS) of the pipe. While this approach is certainly valid to identi& immediate integrity concerns, it does not provide a reasonable means for evaluating the status of corrosion along the pipeline nor does it provide the means for evaluating changes in other parameters such as operating stress level, variable estimated corrosion growth rates, or inspection tool performance (accuracy of reported defect dimensions). Therefore, another analysis tool has been developed to use the in-line inspection data for long term integrity management and development of the Phase 2 excavation program and to establish re-inspection intervals. This approach is referred to as Probability of Exceedance (POE). The POE approach provides the means for systematically summarizing and illustrating the ILI results in a less deterministic fashion. The POE for each corrosion feature is calculated to evaluate the ‘probability’ of a leak or the ‘probability’ of a rupture. It should be noted that the POE results presented herein are suitable for relative comparisons but the absolute value of the POE results (e.g., 1 x 10-2) should be used with caution. In fact, the POE results are likely conservative since one would have expected all of the Phase 1 excavations to result in repairs. However, less than 20’% of the excavations and corrosion assessments actually resulted in repairs once the corrosion features were excavated. Two POE values are calculated for each corrosion feature reported by the tool; one to evaluate the ‘probability’ of a leak (depth of corrosion greater than 80% of the wall thickness) and the other to evaluate the ‘probability’ of a rupture (predicted failure stress less than the operating pressure of the pipeline). POE for the Leak Criterion The probability that the actual depth of corrosion exceeds 80% of the wall thickness (leak criterion) is presented schematically by the three pig calls(l) presented in Figure 1. These pig calls have reported depths of 20%, 50°/0, and 80°A wall loss as shown along the x-axis in this figure. The horizontal line represents an actual depth of corrosion equal to 80’% of the wall thickness. A distribution of expected actual depths of corrosion for each of these three pig calls is represented by the bellshaped curve. The curves are established through a comparison between the depths of corrosion reported by the tool (pig call depths) and the depths of corrosion measured in the field after completing an excavation. For the 20’XOpig call, there is a relatively small probability that the actual depth of corrosion is greater than or equal to 80’% of the wall thickness. This is represented by the small portion of the distribution that extends above the horizontal
‘1) Corrosion features reported by ILI tools are commonly referred to as ‘pig calls’.
line representing an actual depth of 80% wall loss. The probability that a pig call with 209’. wall loss results in actual corrosion greater than 800/0wall loss is relatively small but it is not zero. For the 50% pig call, there is a greater probability that the actual depth of corrosion is greater than or equal to 80% of the wall thickness. This is represented by the larger portion of the distribution that extends above the horizontal line representing an actual depth of 80°/0 wall loss. For the 80’XOpig call, there is the greatest probability that the actual depth of corrosion is greater than or equal to 80% of the wall thickness. This is represented by the larger portion of the distribution that extends above the horizontal line representing an actual depth of 80°/0 wall loss. POE for the Rupture Criterion The probability that the predicted burst pressure is less than the maximum operating pressure is presented schematically by the three pig calls in Figure 2. The results are presented in terms of Rupture Pressure Ratio (IU?R). An RPR equal to 1.00 corresponds to a predicted failure stress equal to 100% of SMYS. Similarly, an RPR equal to 0.90 corresponds to a predicted failure stress equal to 9094. of SMYS. The pig calls in Figure 2 have calculated RPR values of 0.90, 1.00, and 1.10. These RPR values can be calculated using any corrosion assessment criterion (e.g., B31 G, RSTRENG 85’%0Area, or RSTRENG Effective Area based on dimensions reported by the tool). A distribution of expected actual RPR values for each of these three pig calls is represented by the bell-shaped curve. The horizontal line represents an actual RPR equal to 0.77 based upon an RSTRENG Effective Area analysis of the field measurement data. For the 75% by 200 mm pig call with an RPR equal to 0.90, there is a relatively large probability that the RPR based upon field measurements may be less than or equal to 0.77. This is represented by the portion of the distribution that extends below the horizontal line representing an actual RPR equal to 0.77. For the 50’7. by 200 mm pig call with an RPR equal to 1.00, there is a smaller probability that the RPR based upon field measurements may be less than or equal to 0,77. This is represented by the portion of the distribution that extends below the horizontal line representing an actual RPR equal to 0.77. For the 20% by 200 mm pig call with an RPR equal to 1.10, there is a relatively small probability that the RPR based upon field measurements may be less than or equal to 0.77. This is represented by the portion of the distribution that extends below the horizontal line representing an actual RPR equal to 0.77. The probability that a pig call with 20% wall loss results in actual RPR less than 0.77 is relatively small but it is not zero. Once the POE for each corrosion feature has been calculated based upon the Leak Criterion and the Rupture Criterion, the greater of the two POE results is maintained to characterize the corrosion feature. APPLICATION
OF THE POE RESULTS
One advantage of the POE approach is that it provides a reasonable method for comparing the results of multiple inspections, the status and distribution of corrosion along the pipeline, and variations in parameters such as operating stress level, variable estimated conosion growth rates, and/or inspection tool performance (accuracy of reported defect dimensions). Methods for incorporating these variables will be discussed later. Once a POE has been calculated for every corrosion feature, the results can be analyzed and presented many different ways. For example, the POE results can be presented on a feature-by-feature basis, a joint basis, or some other defined length interval such as 20 meters (60 feet) for a typical excavation or 1.0 km (0.62 miles) for a typical section considered for recoating or cathodic protection system changes. The POE results can be combined for any of these intervals based upon the following equation:
POE1n_,
= l-
fi (l-P,) i=l
(1)
where Pi is the POE value calculated for each corrosion feature within the interval. with’n’ number of corrosion features (pig calls) is calculated as follows:
For example, the POE for a pipe joint
POEJOti, = 1 - (1 -P,)(I -P2)..(1 -Pn.l)(l -Pn)
(2)
where Pi is the POE for the iti corrosion feature within the interval. The tabulated results for one inspection are presented in Table 2. These results are presented in descending order based upon the POE result. The POE results are presented graphically in Figure 3 for the 100 corrosion features with the highest POE. The columns of results in Table 2 are defined as follows: column column column column column Cohmm column Cohunn column column column column column column column
1: 2: 3: 4: 5: 6: 7: 8: 9: 10: 11: 12: 13: 14: 15:
Identification of inspection run Girth weld number reported by ILI (sequentially numbered by 10’s) Absolute odometer distance (in meters) reported by ILI Diameter of pipe, mm Nominal wall thickness of pipe, mm Maximum operating pressure of pipeline segment, psig SMYS of pipe, psi Length of corrosion feature reported by ILI, mm Depth of corrosion feature reported by ILI, % wall loss Rupture Pressure Ratio (RPR) based upon the RSTRENG 85% Area Criterion POE based upon ILI reported dimensions POE based upon 0.3 mm per year of corrosion growth after 2 years. POE based upon 0.3 mm per year of corrosion growth after 6 years. POE based upon 0.3 mm per year of corrosion growth after 10 years. POE based upon 0.3 mm per year of corrosion growth after 16 years.
A few observations from the results presented in Table 2 are worth pointing out. First, the corrosion features with the highest POE results were most likely excavated during the Phase 1 Excavation program since either the RPR was calculated to be less than 1.00 or the depth was reported to be greater than 70’% of the wall thickness (see Columns 9 and 10). These results show that the POE approach is consistent with the deterministic approach. Second, many of the corrosion features in Table 2 are located in closed proximity. For example, the 2“d feature and the 10* feature listed in Table 2 are located on the same pipe joint (Girth Weld Number 53700). Additionally, the 1“ and 2ndfeature listed in Table 2 are separated by only 2 pipe joints and could likely be examined through 1 excavation. Once the POE results have been produced in a format similar to that presented in Table 2, these data can be assessed several ways. For example, the results in Figure 4 present the change in POE over time based upon a constant corrosion growth rate of 0.3 mm per year for an inspection completed in 1997. As an example assume that the 10 features with the highest POE were remediated during the Phase 1 excavation program in 1997. The results presented in Figure 5 show the effects of corrosion growth and the examination of additional corrosion features over time, The upper, left curve in Figure 5 shows how the POE will increase over time as a result of the corrosion growth of the features. These results show that the POE will become greater than 1.0 x 10-1in 2004 if no additional features are excavated (see Point A). The next curve (squares) shows how the POE will increase over time as a result of the corrosion growth of the features and an excavation program where 2 features per year are excavated.(2) These results show that the POE will become greater than 1.0 x 10-1in2011 if 28 additional features are excavated (see Point B). It should be noted that these 28 additional features maybe located in close proximity to one another and possibly even several are located on a single joint of pipe. These results can then be used to evaluate the expected cost of completing these excavations in lieu of extending there-inspection from the year 2004 until the year 2011. These excavations can be planned over time and additional cost savings may be experienced if a long term excavation program is initiated. For example, excavations for parallel pipelines can be planned over time such that mobilization costs can be reduced.
‘2) It is worth clarifying that the 2 features per year (resulting in 28 features through 2011) are the 2 features with the highest POE each year.
Results similar to those presented in Figures 3,4, and 5 can be produced for each of the inspections completed and can be compared to develop a consistent and defensible plan for conducting additional excavations and for establishing reinspection intervals. DISCUSSION
OF THE RE.SULTS
The POE results presented within this are based on a pipeline that operates at 77% of SMYS and corrosion features that will grow in time at a constant rate of 0.3 mm per year. However, assumptions other than these can be readily incorporated into a POE analysis. As an example of the effects operating stress level, assume that a pipeline actually operates at 53% of SMYS. The POE analysis can be modified to evaluate the probability that the actual failure stress is less 53’%.of SMYS based upon the corrosion dimensions reported by the tool. Therefore, if the same corrosion feature is identified on this pipeline system and a pipeline system operating at of SMYS, the POE for the latter pipeline will be greater than that for the pipeline operating at 53~o of SMYS. 7’77.
Alternative corrosion growth rate models can also be incorporated into this analysis. If a more sophisticated corrosion growth rate model is available, the POE analysis can utilize these results for every corrosion feature. Therefore, the corrosion growth rate model will affect each corrosion feature over time based upon the more sophisticated corrosion growth rate model. A constant corrosion growth rate of 0.3 mm per year has been used in this paper. The POE analysis methods can also be used in many ways, For example, the POE results can be used within a risk model. The POE results can model the probability of corrosion failure and the consequences can be modeled along the pipeline. In addition, the POE analysis methods can be developed and used in conjunction with other in-line inspection tools such as deformation tools and crack tools. The development and validation of the POE analysis methods continue to evolve. The results presented in this paper have been provided to describe a POE analysis method which can be used as a tool for developing long term integrity plans and options for several pipeline systems. ACKNOWLEDGMENTS The authors would like to acknowledge colleagues who have contributed significantly to the development of the methods presented in this paper. Elden R. Johnson of Alyeska Pipeline Service Company has been a key contributor to the development and application of the probability of exceedance approach. Fred R. Todt of Battelle has been a key contributor to the data management and statistical data analysis. The authors are gratefid for their contributions. REFERENCES 1.
Vieth, P. H., Sahney, R., and Ashworth, B. P., “TCPL In-Line Inspection Management Program”, American Society of Mechanical Engineers, Proceedings of the International Pipeline Conference -1998, Calgmy, Alberta, June, 1998, Table 1. Summary of Inspections Planned through 1999 Year of Inspection 1994 1995 1996 1997 1998(3) 1999(4)
Number of Inspection Runs
Length of Pipe inspected, km
1 3 8 33 19 25
139 66 780 3,700 3,600 2,600
‘3) These inspections are in progress and planned through the end of 1998. ‘4) These inspections
are planned for 1999.
Table 2. Listing of POE Results for Inspection Number 1. Section
Inspection
1
Gh-th Weld Number
Odometer Dktance
Diameter,
53700
71573.75
864
mm
Nominal Wall Thickness mm
9.53
Maximum Operating Pre3surq psig
SMYS, psi
lLIReported
880
52000
604
Length, mm
ILI Reported Depth, % Wall Loss
(RSm&NG 85% Area)
48
0.773
POE Oyears
POE 2 years
POE 6 years
l.llE-01
2.34E-01 9.48E-02
POE 10 years
POE 16 years
6.02E-01
8.93E-01
9.97E-01
3.72E-01
7.45E-01
9.84E-01
Inspection
1
53730
71616.56
864
9.53
880
52000
570
41
0.842
3.56E-02
Inspection
1
60200
79559.06
864
9.53
880
52000
455
35
0.908
6.98E-03
2.47E-02
1.64E-01
5.02E-01
9,31E-01
2.42E-02
1.62E-01
4.99E-01
9.30E-01
Inspection
1
66210
86697.56
864
9.53
880
52000
327
40
0.890
6.82E-03
Inspection
1
54530
72560.00
864
9.53
880
52000
399
35
0.917
4.71E-03
1.77E-02
1.32E-01
4.47E-01
9.llE-01
7.74E-03
7.56E-02
3.26E-01
8.48E-01
Inspection
1
2610
4364.90
864
9.53
880
52000
351
33
0.943
1.78E-03
Inspection
1
53340
71143.56
864
9.53
880
52000
282
35
0.946
9.71E-04
4.58E-03
5.26E-02
2.63E-01
8.OIE-01
3.60E-03
4.44E-02
2.37E-01
7.77E-01
6399.90
864
9.53
880
52000
387
28
0.978
7.35E-04
2590
4321.30
864
9.53
880
52000
575
23
1.002
6.69E-04
3.32E-03
4. 19E-02
2.29E-01
7.69E-01
53730
71611.88
864
9.53
880
52000
379
26
0.995
3.86E-04
2.05E-03
2.98E-02
1.85E-01
7.19E-01
3840
6400.30
864
9.53
880
52000
556
20
1.029
2.65E-04
1.48E-03
2.35E-02
1.58E-01
6.83E-01
Inspection 1
53350
71156.19
864
9.53
880
52000
1.28E-03
2.llE-02
1.48E-01
6.68E-01
Inspection
1
56040
74604.25
864
9.53
880
Inspection
1
55040
73170.56
864
9.53
880
Inspection
1
54980
73103.69
864
9.53
Inspection 1
60990
80512.06
864
9.53
Inspection
1
3840
Inspection
1
Inspection
1
Inspection
1
222
36
0.965
2,25E-04
52000
324
26
1.005
1.74E-04
1.02E-03
1.80E-02
1.33E-01
6.43E-01
52000
285
27
1.007
1.05E-04
6.55E-04
1.29E-02
1.07E-01
5.93E-01
880
52000
281
27
1.008
9.51E-05
6J30E-04
1.21E-02
1.03E-01
5.84E-01
880
52000
25
64
1.160
9.35E-05
5.91E-04
1.20E-02
1.02E-01
5.82E-01
Inspection
1
57530
76381.69
864
9.53
880
52000
267
28
1.005
8.94E-05
5.68E-04
1. 16E-02
9.98E-02
5.78E-01
Inspection
1
66210
86698.06
864
9.53
880
52000
33
63
1.141
6.83E-05
4.48E@l
9.75E-03
8.85E-02
5.51E-01
4.03E-04
Inspection 1
60550
79990.50
864
9.53
880
52000
220
32
0.994
6.07E-05
9.02E-03
8.39E-02
5.40E-01
Inspection 1
2590
4321.00
864
9.53
880
52000
250
27
1.018
3.83E-05
2.68E-04
6.64E-03
6.80E-02
4.95E-01
Inspection 1
30380
41123.19
864
9.53
880
52000
231
29
1.011
3.64E-05
2.56E-04
6.42E-03
6.65E-02
4.90E-01
Inspection
66200
86685.38
864
9.53
880
52000
222
30
1.008
3.46E-05
2.45E-04
6.20E-03
6.49E-02
4.86E41
2.37E-04
1
Inspection 1
5010
8288.30
864
9.53
880
52000
214
31
1.005
3.34E-05
6.05E-03
6.39E-02
4.82E-01
Inspection
1
4010
6577.30
864
9.53
880
52000
276
24
1.031
3.18E-05
2.27E-04
5.86E-03
6.25E-02
4.78E-01
Inspection
1
59170
78340.88
864
9.53
880
52000
156
42
0.973
2.95E-05
2.13E-04
5.57E-03
6.03E-02
4.71E-01
.—
roba
Iity o
f -.
80
..
....”. .— --
&
10
20
*’<
,.,,. ,, ,, ,, ,. -. ‘\ /’
,‘.
.’
.
‘..
,/
-
.
..
80%
50%Pig
all
~
J
,
+
30 40 50 Pig Call Depth,
Figure 1. POE for Evaluating
YO
60 Wall
Pig t+all
. \-..... 1 ‘“l ‘--”-”--’---”
>,
—. ...._.. _.
L
o
\
,---A ----
.)--
,,.
... . .
danc(
70 Loss
the Likelihood
I
80
90
100
of a Leak
... . .
1:””
I
..
1.
.. . .. ... .. -.. . + 50%x 200my
..
.
!
75%x 2001
I
,,, ,., ,. ,
/
‘.
/<
.
/ t I
/’
I
I ‘.
---’-’---’1----’-’----
+
0.80
,
,
,
,
0.85
/’ 2-= -— -.- . .. ...a.-——— ----
–—---.–--.-.4--------------
~
1
0.90
I
t
0.95
1.05 1.00 RPR Pig Call
Figure 2. POE for Evaluating
the Likelihood
1.10
1.15
of a Service Failure.
1.20
Number o
10
20
30
40
of Features 50
60
70
80
90
100
I.00E+OO
I.00E-01
1.00E-02
:i “00E”03 %
1.00E-04
1.00E-06
1,00E-07 O years
1,00E-08
Figure 3. POE Results for Each Feature from Inspection Number 1.
Number o
10
20
30
40
of Features 50
60
70
80
90
100
1.00E+oo
I.00E-01
16 years
1.00E-02
10 years 1.00E-03 ! A % * a : &
1.00E-04 6 years 1.00E-05
1.00E-06
2 years
1,00E-07 O years
1.00E-08
Figure 4. POE Results for Each Feature from Inspection Number 1 Which Shows the Effects of Corrosion Growth (0.3 mm per year).
Year
1.OE+OO
1.OE-01
1.OE-02
1.0E03
1.OE-07
1.OE-08
1.OE-09
1.OE-10
Figure5. POE Results for Inspection Number l to Evaluate Potential Excavation Sites versus Re-Inspection Interval.