FITNESS-FOR-SERVICE EVALUATION OF PIPELINES WITH STRESS-CORROSION CRACKS OR LOCAL CORROSION By
Carl E. Jaske and John A. Beavers
CC Technologies CC Technologies, Inc. 5777 Frantz Road Dublin, OH 43017-1386 USA http://www.cctechnologies.com Presented at
The International Conference on Advances in Welding Technology (ICAWT ’99) October 26-28, 1999 Galveston, Texas USA
FITNESS-FOR-SERVICE EVALUATION OF PIPELINES WITH STRESS-CORROSION CRACKS OR LOCAL CORROSION Carl E. Jaske and John A. Beavers1
ABSTRACT Pipelines are subject to stress-corrosion cracking (SCC) and corrosion in ground-water environments. An engineering approach has been developed for evaluating the fitness for service (FFS) of pipelines that may operate in such environments. The approach utilizes J-integral fracture mechanics to quantify the growth and instability of SCC flaws. A mechanics model of locally thin areas is used to evaluate corrosion flaws. This paper reviews the development of the FFS approach, describes recent improvements to it, and discusses its validation by comparison with the results of laboratory testing and field experience. Procedures for estimating material fracture toughness and predicting pipeline fracture are presented. Available data on stress-corrosion crack-growth and corrosion rates are reviewed, and their use in the prediction of remaining safe operating life is discussed. Two examples are presented to illustrate the application of the FFS approach. INTRODUCTION Fitness for service, as applied to pipelines can be defined as an analytical procedure for determining if a pipeline is fit to operate without the risk of failure. FFS is needed to maintain safe and reliable pipeline operation, avoid environmental impact, and optimize maintenance programs. Estimating the remaining strength and life of in-service pipelines are key elements of their FFS assessment. FFS assessment is used to establish intervals for in-line inspection (ILI), prioritize ILI results for field inspection, establish hydrostatic testing intervals, determine if operating pressure must be reduced, decide to repair or cut out a defect, and prioritize inspection, re-coating or repair. In general, FFS addresses many types of defects and material degradation mechanisms. The scope of this paper is limited to the consideration of SCC and corrosion. Evaluating the effects of local corrosion on pipeline FFS has long been a concern of operators. There has been extensive research on this topic,(1-2) and researchers have developed methods of evaluating the effects of local corrosion on pipeline strength for general use by pipeline operators.(3-4) The ASME B31 Code method(3) was found to be too conservative for many situations, so a less conservative and more accurate effective area method was developed and incorporated into the RSTRENG computer program.(4) These methods are based on flow-strength failure criteria and are widely used to assess the strength of pipelines with locally thin areas. However, they are not directly applicable to SCC because they do not evaluate the possibility of fracture-toughness dependent failure. 1
CC Technologies Laboratories, Dublin OH 43016 USA
1
SCC is a topic of concern in recent research. The first incident of external SCC on natural gas pipelines occurred in the mid 1960's(5) and hundreds of failures have occurred since that time. A characteristic of this form of failure is the presence of colonies of many longitudinal surface cracks in the body of the pipe that link up to form long shallow flaws. The early failures all were intergranular, and the fracture faces were covered with black magnetite or iron carbonate films with little evidence of general corrosion. A concentrated carbonate + bicarbonate solution was identified as the most probable environment responsible for the cracking.(5-6) This environment is now referred to as the classical or high-pH cracking environment and is simulated in the laboratory using a 1N NaHCO3 + 1N Na2CO3 solution, that has a pH of about 9.3. The environmental aspects of SCC of natural gas pipelines were thought to be reasonably well understood until TransCanada PipeLines Ltd. (TCPL) started experiencing SCC on their polyethylene tape coated pipelines in the 1980's. An extensive field investigation showed that the occurrence of SCC correlated with nearneutral-pH (pH < 8) dilute CO2-containing electrolytes and that cracking was not observed where higher pH electrolytes were detected.(7) This form of SCC has been termed near-neutral pH, low-pH, or non-classical SCC. Since the discovery of nearneutral-pH SCC by TCPL,(8) other pipeline companies have also identified near neutralpH SCC on their lines.(9) Morphological differences between near neutral pH and high pH SCC include the dominant fracture mode and the extent of general corrosion. Near neutral pH SCC is transgranular and, frequently, corrosion of the crack walls and outer surface of the pipe is associated with this form of cracking. High pH cracking is intergranular, and there is usually little evidence of corrosion of the crack walls or outer surface of the pipe. Morphological similarities between near neutral and high pH SCC include the presence of large colonies of longitudinal cracks on the outside surface of the affected pipeline, high aspect ratio cracks and the presence of magnetite and iron carbonate films on the crack surfaces. Flaw length-to-depth ratios in the range of 50 to 200 are typically found in investigations of SCC failures of pipelines. With the advent of SCC problems, a FFS procedure that addresses both crack-like and corrosion flaws needed to be developed. A modified linear elastic fracture mechanics (LEFM) approach was first used to assess crack-like flaws in pipelines.(10) The petrochemical industry(11-12) uses failure-analysis diagrams (FADs) from PD 6493(13) to assess the integrity of structures with crack-like flaws. These FADs use the linear elastic stress intensity factor (K) to characterize the fracture toughness failure criterion and tensile properties to characterize the strength failure criterion. This method works well as long as the applied stress is less than about 40% of the failure strength. Because of inelastic material behavior, the FAD approach loses accuracy when the applied stress exceeds about 40% of the failure strength, which is usually the case for pipelines. In this region of applied stress, inelastic fracture mechanics (IFM) can be employed to obtain accurate assessments of structural integrity. For this reason, the authors developed IFM procedures that employ the J integral to evaluate integrity of
2
pipelines with crack-like flaws.(14-18) The IFM procedures were adapted from those used to evaluate the structural integrity of steam piping;(19-24) however, they were modified to account for SCC instead of creep cracking. The IFM procedures are implemented by means of computerized calculations using the CorLASâ&#x201E;˘ computer program.(25) This paper reviews the technical approach developed by the authors for evaluating the FFS and integrity of pipelines subject SCC and corrosion during service. The validation of the approach and the characterization of SCC flaw growth also are reviewed. Finally, two examples are presented to illustrate the application of the approach. REVIEW OF THE TECHNICAL APPROACH The flowchart of Figure 1 illustrates the overall approach used to assess SCC or corrosion flaws. The first step is characterization of the initial flaw size. Then, the critical or final flaw size at failure under operating conditions is predicted. The remaining life is computed based on growth from the initial to the final flaw size. If the final flaw size is not greater than the initial one, no remaining life is predicted. Also, if the flaw growth rate can not be estimated, remaining life can not be predicted and some form of monitoring is recommended to assure safe pipeline operation. The size of the surface flaw is characterized by means of in-service inspection or hydrotesting. In-service inspection may yield a detailed profile or contour of the flaw depth as a function of its length, or it may yield only the flaw length and depth. When a detailed flaw-depth profile is available, an effective surface flaw is determined from this profile using the procedures described in detail by Kiefner and Vieth.(4) The effective area of the surface flaw is defined by its effective length and actual cross-sectional depth. The depth of a semi-elliptical flaw having the same length and area as the effective flaw then is calculated to determine the effective flaw depth. If a detailed profile is not available, the effective surface flaw is characterized as having a semielliptical shape with the measured depth and length. When hydrotesting is used to characterize the surface flaw, the effective flaw size is estimated to be the largest flaw that would have survived the hydrotest based on the same failure criterion used to compute the critical flaw size under operating conditions. In practice, these effective flaw sizes are estimated as a function of flaw length-to-depth (L/d) ratio, because the L/d ratio affects the critical flaw depth. The critical flaw size is computed for two different failure criteria: J fracture toughness and flow strength. As pointed out previously, J fracture toughness is used because IFM is more accurate than LEFM when the applied stress is greater than approximately 40% of the failure strength. Both fracture toughness and flow strength must be considered as possible failure modes for crack-like flaws, whereas only flow strength must be considered for failure of non-crack-like flaws that are typical of local corrosion. The smaller of the two calculated critical flaw sizes is the one predicted to result in failure.
3
Characterize Flaw
Hydrotesting
In-Service Inspection
Yes
Is There a Detailed Flaw Profile?
Com pute Effective Flaw s and Define Equivalent Sem i-Elliptical Flaws
Define Effective Sem iElliptical Flaw s Based on Their Length and Depth
J Fracture Toughness Criterion
Com pute Rem aining Life Based on Toughness Limit
Estim ate Critical Effective Sem i-Elliptical Flaws for Hydrotest Conditions
No
Com pute Critical Flaw Size for Operating Conditions
Yes
Is Flaw Crack-Like and Does Toughness Control?
Flow Strength Criterion
No
Com pute Rem aining Life Based on FlowStrength Lim it
Figure 1. General Approach for Assessment of SCC and Corrosion Flaws
4
The remaining life is the time required for the flaw to grow from its initial to final size. It is computed by integrating the flaw-growth relationship from the initial to final flaw size. The SCC flaw growth rate (da/dt) is expressed as a function of the value of the J integral and can be measured by means of laboratory testing or estimated based on field experience. The corrosion rate must be characterized for corrosion flaws. For pipeline applications, da/dt and the corrosion rate are often found to be approximately constant over the range of loading conditions experienced in service. In this case, remaining life is simply the difference between the final and initial flaw size divided by the rate of flaw growth. Flow-Strength Failure Criterion The critical flaw size for the flow-strength failure criterion is determined by solving the following equation for the effective flaw area (A): ﾏデ = Sfl RSF = Sfl [(1 - A/Ao)/(1 - A/(MAo))]
(1)
where ﾏデ is applied nominal stress at failure, Sfl is the flow strength of the material, RSF is the remaining strength factor, Ao is the flaw length times the wall thickness, and M is the Folias factor given by Kiefner and Vieth.(4) For a specific relation among A, L, and d, such as a semi-ellipse with a constant L/d ratio, L and d are uniquely defined by the value of A obtained from solving Equation (1). However, since M is a function of L, the solution must be obtained iteratively. Flow strength is determined from tensile yield strength (TYS) or from a combination of tensile yield strength and tensile ultimate strength (TUS) using one of the following two expressions: Sfl = TYS + 68.95 MPa (10,000 psi)
(2a)
Sfl = TYS + Cfl (TUS - TYS)
(2b)
Cfl is a constant between 0 and 1.0 and is usually taken to be 0.5. Equation (2a) is based on burst tests of steel pipe specimens,(10) while Equation (2b) with Cfl = 0.5 is widely used in plastic collapse analysis. SCC often causes multiple surface flaws to develop on pipelines. When more than one flaw is found in the same region, the possibility of flaw interaction must be considered. An interacting flaw will fail at a lower stress than predicted by evaluating any these flaws as a single, isolated flaw. Flaw interaction is evaluated as a general extension of the effective area method. Multiple flaws are assessed by repeated application of Equation (1) for all possible combinations of the flaws. The flaw or combination of flaws with the lowest value of RSF, the term in brackets in Equation (1), is predicted to cause failure. If the evaluation reveals that a single flaw has the lowest RSF, no interaction is predicted. If the evaluation reveals that some combination of the flaws has the lowest RSF, then interaction is predicted.
5
Flaw interaction is predicted to occur when the RSF values for the individual flaws (RSFi) exceed the RSF for the combined flaw (RSFc). In other words, RSFi = [(1 - Ai/Aoi)/(1 - Ai/(MiAoi))]
(3)
and RSFc = [(1 - Ac/Aoc)/(1 - Ac/(McAoc))]
(4)
Then, flaw interaction occurs when All RSFi ≥ RSFc
(5)
Equation (5) is evaluated for all possible flaw combinations. If more than one value of RSFc satisfies Equation (5), then the flaw combination with the minimum value of RSFc is predicted to cause failure. Application of the interaction model is demonstrated for the two surface flaws illustrated schematically in Figure 2. Their RSF values are RSF1 = [(1 - A1/Ao1)/(1 - A1/(M1Ao1))]
(6)
and RSF2 = [(1 - A2/Ao2)/(1 - A2/(M2Ao2))]
(7)
To compute the RSF value for the combined flaw using Equation (4), Ac = A1 + A1 and Lc = L1 + s + L1, where s is the flaw separation. Interaction is predicted to occur, when RSF1 and RSF2 ≥ RSFc
(8)
Otherwise, no interaction is predicted. This interaction model is being evaluated in current research. A1
A2
s
L1
L2
t
Lc
Figure 2. Illustration of Two Axial In-Plane Surface Flaws
6
Fracture-Toughness Failure Criterion The critical flaw size for the fracture-toughness failure criterion is determined in either one of two ways using the J integral. The first method is computing the condition for which the applied value of J integral (Jap) is equal to the J fracture toughness (Jc) of the material. If Jc is taken to be JIc, the condition for initiation of tearing (crack advance) is predicted. However, if Jc is taken to be a maximum toughness, the condition for failure or tearing instability is predicted. The second method is computing the tearing instability condition where the applied tearing parameter (dJap/da) is equal to the tearing resistance (dJ/da) of the material, as illustrated in Figure 3. Both methods require iterative calculations to determine the critical flaw size.
Value of J Integral
Applied J
da
dJ
Material J-R Curve
Ductile Tearing Instability Applied dJ/da => Material dJ/da
Crack Depth, a
Figure 3. Illustration of Tearing Instability Criterion
The following IFM formulation for a semi-elliptical surface flaw is used to compute values of applied J as a function of crack size (a) and stress (σ): J = Qf Fsf a [σ2π/E + f3(n)εpσ]
(9)
Qf and Fsf are the flaw shape factor and free-surface factor, respectively. E is the elastic modulus, εp is the plastic strain, and f3(n) is a function from analyses performed by Shih and Hutchinson.(26) A power law characterizes stress as a function of plastic strain. The strain hardening exponent (n) is the exponent of this power law, while the yield strength and the strain hardening exponent are used to determine the power-law coefficient.
7
Standard laboratory test procedures(27-28) are used to measure J fracture toughness and tearing resistance. If J fracture-toughness and tearing-resistance data are not available, they are estimated from Charpy V-notch impact energy values using empirical relations developed from available test data for pipeline steels. Flaw interaction for the fracture-toughness criterion is modeled in a fashion similar to that employed for the flow-strength criterion. Values of the applied J integral are computed for each possible individual flaw (Jai) and for combined flaws (Jac). Then, flaw interaction occurs when Jac ≥ All Jai
(10)
Equation (10) also is evaluated for all possible flaw combinations. If more than one value of Jac satisfies Equation (10), then the flaw combination with the maximum value of Jac is predicted to cause a toughness-dependent failure. The lower stress or loading condition (e.g., pressure) associated with each of the two failure criteria is predicted to control failure. In other words, either toughness or flowstrength may control the failure of a crack-like flaw. Furthermore, the critical flaw length and depth may be different for each failure criterion. The actual critical flaw is predicted to be the one related to the controlling failure criterion. Flaw-Growth Rate In past laboratory work,(27-28) it was found that the SCC flaw growth rate (da/dt) could be characterized as a power-law function of the J integral: da/dt = G Jg
(11)
G and g are material/environment constants. Integration of Equation (11) from the initial to the final flaw size gives the remaining flaw-growth life. When da/dt is constant and independent of J over the observed range of flaw-growth behavior, the value of G is equal to the linear flaw-growth rate and the value of g is equal to zero. VALIDATION OF THE APPROACH Application of the approach reviewed in the previous section to the FFS assessment of pipelines requires a large number of iterative numerical computations. Personal computers are an ideal tool for implementing this approach. For this reason, the CorLAS™ (Corrosion Life Assessment Software) computer program(25) was developed to perform the required calculations. The CorLAS™ program has been used in numerous practical pipeline evaluations and has been updated as part of a recent research project. In previous studies,(14-16) the validity of the failure criteria used in the flaw-assessment approach was checked using published results(10) of full-scale pipe-burst tests. Those tests were performed on specimens of API X52, X60, and X65 steel pipe with machined
8
surface flaws of different lengths and depths. The tensile strength and Charpy impact energy of the steel were reported for each specimen, but no fracture-toughness data were reported. When Charpy impact energy was used to estimate the J fracture toughness for unstable crack extension, a good correlation was obtained between the predicted and actual flaw depth at failure. Based on this correlation, it was concluded that the approach gave good predictions of critical flaw size and should be applicable to the assessment of SCC flaws. In a Canadian study of SCC on pipelines,(29) the CorLASâ&#x201E;˘ computer program was used to predict the failure pressure for fourteen in-service or hydrotest failures. The data used in the calculations were reported to represent the range of materials, flaw shapes, and pipe diameters for oil and gas pipeline SCC failures in Canada. CorLASâ&#x201E;˘ was found to provide the best failure predictions of the four approaches evaluated in the Canadian study.(29) Those predictions are shown as solid circles in Figure 4, where the predicted failure stress is plotted as a function of the actual failure stress and the 45degree dashed line indicates an exact correlation between those stress values. Both stresses are given as a percentage of the specified minimum yield strength (SMYS) of the pipe steel. As indicated in Figure 4, the original predictions (solid circles) were made using an effective flaw characterized by only the maximum depth and length. Except for one case, the predicted failure stresses were very close to the actual failure stresses. Detailed examination of the data for that case revealed that the SCC flaw was much deeper at its central portion than near its ends, so its effective size was much smaller than its maximum size. The predicted failure stress was very close to the actual failure stress when the actual flaw-depth profile was used to characterize its effective size, as indicated by the open circle in Figure 4. Thus, the approach has been validated for field experience as well as for full-scale test results. CHARACTERIZATION OF SCC FLAW GROWTH Both laboratory(27-28) and field data on the rate of SCC flaw growth in near-neutral-pH environments have been developed. The early laboratory studies showed that the crack-growth rate (da/dt) could be expressed as a function of J, as previously indicated by Equation (11). Crack-growth rates ranging from 3 x 10-7 to 6 x 10-4 mm/s (0.37 to 745 in/year) were measured on rising load tests of compact-tension (CT) specimens. Under more realistic cyclic load conditions, the cracking velocity was not a function of the applied J integral. During steady state cyclic loading, maximum cracking velocities were about 2.0 x 10-8 mm/s (0.025 in/year). The prior loading history was the primary factor that controlled the cracking velocity. Decreasing the frequency (from 10-4 Hz to 10-5 Hz) and changing the waveform (from triangular to trapezoidal) decreased the cracking velocity slightly, but the effects may have been within normal experimental scatter. Decreasing the R ratio (from 0.9 to 0.6) increased the cracking velocity by over a factor of two. Some crack extension occurred during a simulated hydrostatic test sequence, but the hydrostatic testing also promoted a decrease in the subsequent cracking velocity.(30)
9
Predicted Using Maximum Flaw Predicted Using Effective Flaw 1-to-1 Correlation
Predicted Failure Stress (%SMYS)
120
100
80 Use of Effective Flaw Improved the Prediction
60
40
20
0 0
20
40
60
80
100
120
Actual Failure Stress (%SMYS)
Figure 4. Correlation Between Predicted and Actual Failure Stress for SCC Failures(29)
Field crack growth rate data has been obtained primarily from analysis of field SCC failures. One method of estimating the crack velocity is to divide the total crack depth by the life of the pipeline. This method would be expected to give non-conservative estimates since the cracks generally do not initiate when the pipe is first placed in the ground. An incubation time is required for the coating to disbond, for the potent cracking environment to develop, and for the cracks to initiate. Improved estimates of cracking velocities may be obtained where there are demarcations on the fracture surface associated with prior hydrostatic testing. This latter technique has yielded average and maximum values of approximately 1 x 10-8 and 2 x 10-8 mm/s (0.012 and 0.024 in/year), respectively, for the growth of near-neutral-pH stress corrosion cracks. As pointed out previously, Equation (11) is integrated from the initial to the final flaw size to calculate remaining SCC life. If the growth rate is constant and independent of J, the difference between the final and initial flaw size is simply divided by that rate to calculate remaining SCC life. Some conditions must be placed on flaw shape as it grows. In the current approach, one of three options is used to define the flaw shape during growth: (1) growth with a constant L/d ratio, (2) growth with a constant crack length, or (3) constant growth all along the crack front. The first criterion, constant L/d
10
ratio is applied to small SCC cracks where significant crack inter-linking within the colony is expected to occur during growth. For large SCC cracks that are likely to consist of small cracks that have already linked, the constant L/d criterion is much too conservative. In this case, it is reasonable to model the crack as growing constantly. In some cases, it is suspected that large cracks increase only in depth but not in length during growth. The constant length criterion is used for these cases. In practice, the difference between the constant length criterion and the constant growth criterion is often negligible. EXAMPLE APPLICATIONS This section reviews two examples of applications where the approach described in this paper has been applied to pipelines. These are the evaluation of a field SCC failure and the prediction of remaining life based on the use of hydrotesting. These examples show the information needed to perform a FFS assessment of a pipeline. The needed information includes pipe outside diameter (OD), pipe wall thickness (WT), yield strength, ultimate strength, Charpy impact properties, maximum allowable operating pressure (MAOP), actual operating pressure, and defect size, shape, and orientation. Useful, but optional, information includes the flaw-depth profile, J fracture toughness, J tearing resistance, and strain-hardening exponent. Evaluation of Field Failure The FFS approach was applied to a failure that occurred on a gas pipeline during hydrotesting at 9,653 kPa (1,400 psig). The failure was caused by SCC.(15) The SCC flaw that caused the failure was located at the fusion line of an electric-resistance weld in an API X52 steel pipe. The fracture surface of this flaw was examined, and its depth was measured along the length of the flaw. The circles plotted in Figure 5 show these measurements. An effective flaw analysis was then performed using CorLASâ&#x201E;˘, and the effective semi-elliptical flaw is shown in Figure 5. This effective semi-elliptical flaw then was used to compute critical flaw depths for the pipeline based on the following measured average material properties: Yield strength = 487 MPa (70,700 psi) Ultimate strength = 576 MPa (83,500 psi) J fracture toughness = 42 kJ/m2 (240 lb/in) The actual critical depth of the effective flaw was 1.96 mm (0.077 in.), as shown in Figure 5. The predicted critical depths were 2.11 and 3.81 mm (0.083 and 0.150 in.) for the fracture-toughness and the flow-strength failure criteria, respectively. Thus, the failure was predicted to be governed by fracture toughness rather than flow strength, and the predicted critical flaw depth of 2.11 mm (0.083 in.) was close to the actual effective flaw depth of 1.96 mm (0.077 in.). If the failure had been limited by flow strength, a flaw almost twice as deep as the actual one would have been required to cause failure during the hydrotest. For this reason, it was concluded that the low
11
fracture toughness of the weld joint material was a contributing cause, along with SCC, to the failure.
Distance from Outer Surface, in.
0
Outer Wall
0.1
Actual Flaw Effective Semi-Elliptical Flaw
0.2
Inner Wall 0
1
2
3
4
Distance Along Pipe, in. Figure 5. Comparison of Actual and Effective SCC Flaw Depth Profile(15)
Remaining Life Prediction Based on Hydrotesting The results of hydrotesting can be used to predict remaining life. After a pipeline has been hydrotested without failures, the test pressure can be used to predict the largest flaw that could have survived and still remain in the pipeline. This flaw is the initial flaw for remaining life prediction, while the smallest flaw predicted to cause failure during operation is the final flaw for remaining life prediction. Average material properties are used to predict these flaw sizes and remaining life. Then an appropriate safety factor is applied to the result. Using minimum material properties to make such calculations usually overestimates the remaining life and is not recommended. A pipeline made of API X60 steel was hydrotested at a pressure that produced a nominal stress equal to 110% of SMYS. The pipe diameter and wall thickness were 0.762 m (30 in.) and 7.24 mm (0.285 in.), respectively, so the hydrotest pressure was 8,646 kPa (1,254 psig). The maximum operating pressure was 5,659 kPa (821 psig), which corresponded to a nominal stress equal to 72% of the SMYS. The following average material properties were measured for the pipe steel: Yield strength = 460 MPa (66,700 psi) Ultimate strength = 589 MPa (85,400 psi)
12
J fracture toughness = 429 kJ/m2 (2,450 lb/in) Using the average materials properties and the pipe dimensions, critical crack depth was calculated as a function of crack length at both the hydrotest and maximum operating pressures. The results of these calculations are shown in Figure 6. The open circles indicate the critical depth at hydrotest pressure, while the open squares indicate the critical depth at maximum operating pressure. Leaks were predicted for crack lengths less than 72.6 mm (2.86 in.). Thus, remaining lives to pipe rupture could not be defined for crack lengths shorter than this value. Remaining SCC lives were calculated for crack lengths equal to or greater than 72.6 mm (2.86 in.) using a typical SCC growth rate of 0.30 mm/year (0.012 in/year). As is shown in Figure 6, the predicted remaining life decreased as crack length increased and ranged from approximately 11 to 4 years. Depending on the lengths of SCC cracks that may be expected to develop in future service, the predicted remaining life can be used to establish when the pipeline should be hydrotested again or nondestructively inspected.
Depth at Hydrotest Pressure Depth at Maximum Operating Pressure Remaining Life
Critical Depth, in.
0.25
12 10
0.2
8
0.15
6
0.1
4 Leak Rupture
0.05
Remaining Life, years
0.3
2
0
0 0
5
10
15
20
Crack Length, in. Figure 6. Predicted Critical Crack Depths and Remaining Lives versus Crack Length
CONCLUSIONS The approach discussed in this paper can be used to evaluate the fitness for service (FFS) of pipelines that operate in ground-water environments where SCC and corrosion may occur. It uses the effective-flaw concept to define the worst effective flaws for a measured surface-flaw depth profile. One effective flaw is determined for the flow13
strength failure criterion, while another effective flaw is determined for the J fracture toughness failure criterion. Critical sizes at failure are predicted for both flaws, and the one with the lower failure pressure is predicted to be the controlling flaw. The validity of this approach was verified by predicting the failure of full-scale, burst-test specimens and actual pipeline failures during operation and hydrotesting. Two examples were presented to show that this approach could be applied to realistic problems. REFERENCES (1)
J. F. Kiefner, “Corroded Pipe: Strength and Repair Methods”, Paper L, Proceedings of the Fifth Symposium on Line Pipe Research, A.G.A. Catalogue No. L30174, American Gas Association, Inc., Arlington, VA, 1974.
(2)
J. F. Kiefner and A. R. Duffy, “Summary of Research to Determine the Strength of Corroded Areas in Line Pipe”, presented at public hearing Notice 71-3, Docket No. OPS-5, Office of Pipeline Safety, Department of Transportation, July 20, 1971.
(3)
ASME, Manual for Determining the Remaining Strength of Corroded Pipelines, A Supplement to ASME B31 Code for Pressure Piping, B31G, ASME International, New York, 1991.
(4)
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(5)
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(6)
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(7)
J. T. Justice and J. D. Mackenzie, “Progress in the Control of Stress Corrosion Cracking in a 914 mm O.D. Gas Transmission Pipeline,” Paper No. 28, Proceedings of the NG-18/EPRG Seventh Biennial Joint Technical Meeting on Line Pipe Research, Pipeline Research Committee of the American Gas Association, Inc., Washington, D.C., 1988.
(8)
B. S. Delanty and J. E. Marr, “Stress Corrosion Cracking Severity Rating Model,” Proceedings of the International Conference on Pipeline Reliability, CANMET, Calgary, 1992.
(9)
M. Urednicek, S. Lambert, and O. Vosikovsky, “Stress Corrosion Cracking – Monitoring and Control,” Proceedings of the International Conference on Pipeline Reliability, CANMET, Calgary, 1992.
14
(10)
J. F. Kiefner, W. A. Maxey, R. J. Eiber, and A. R. Duffy, “Failure Stress Levels of Flaws in Pressurized Cylinders”, Progress in Flaw Growth and Fracture Toughness Testing, STP 536, ASTM, Philadelphia, pp. 461-481, 1973.
(11)
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(12)
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(13)
BSI, Guidance on methods for assessing the acceptability of flaws in fusion welded structures, PD 6493, British Standards Institution, London, 1991.
(14)
C. E. Jaske and J. A. Beavers, “Effect of Corrosion and Stress-Corrosion Cracking on Pipe Integrity and Remaining Life,” Proceedings of the Second International Symposium on the Mechanical Integrity of Process Piping, MTI Publication No. 48, Materials Technology Institute of the Chemical Process Industries, Inc., St. Louis, pp. 287-297, 1996.
(15)
C. E. Jaske, J. A. Beavers, and B. A. Harle, “Effect of Stress Corrosion Cracking on Integrity and Remaining Life of Natural Gas Pipelines,” Paper No. 255, Corrosion 96, NACE International, Houston, 1996.
(16)
C. E. Jaske and J. A. Beavers, “Fitness-For-Service Evaluation of Pipelines in Ground-Water Environments,” Paper 12, Proceedings for the PRCI/EPRG 11th Biennial Joint Technical Meeting on Line Pipe Research, Arlington, VA, 1997.
(17)
C. E. Jaske and J. A. Beavers, “Review and Proposed Improvement of a Failure Model for SCC of Pipelines,” Proceedings of the International Pipeline Conference, Volume 1, ASME International, New York, 1998, pp. 439-445.
(18)
C. E. Jaske and J. A. Beavers, “Predicting the Failure and Remaining Life of Gas Pipelines Subject to Stress Corrosion Cracking,” IGRC98 Paper TSO-13, Proceedings of the 1998 International Gas Research Conference, San Diego, 8-11 November, 1998.
(19)
C. E. Jaske, “Life Assessment of Hot Reheat Pipe,” Journal of Pressure Vessel Technology, Vol. 112 (1), pp. 20-27, 1990.
(20)
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