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International Pipeline Conference — Volume 1 ASME 1998


C. E. Jaske and J. A. Beavers CC Technologies, Inc. Dublin, OH 43017-1386 USA

INTRODUCTION Wenk (1974) reported that the first case of external stress corrosion cracking (SCC) on natural gas pipelines occurred in the mid 1960's. Hundreds of SCC-related pipeline failures have occurred since that time. A distinguishing characteristic of SCC failure is the presence of patches of many longitudinal surface cracks in the body of the pipeline that link up to form long shallow flaws. Early SCC failures were intergranular, where the fracture faces were covered with black magnetite or iron carbonate films and showed little evidence of general corrosion. As pointed out by both Wenk (1974) and Sutcliffe, et al. (1972), a solution of concentrated carbonate plus bicarbonate was believed to the environment that caused this type of SCC cracking. This environment is now known 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. Until TransCanada PipeLines Ltd. (TCPL) started finding SCC on their polyethylene tape coated pipelines in the 1980's, the environmental aspects of SCC of natural gas pipelines were believed to be reasonably well understood. An extensive field investigation reported by Justice and Mackenzie (1988) showed that the occurrence of this type of SCC correlated with nearneutral-pH (pH < 8) dilute CO2-containing electrolytes and that cracking was not observed where higher pH electrolytes were detected. 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 (Delanty and Marr, 1992), other pipeline companies, including NOVA Corporation, have also found near-neutral-pH SCC on their pipelines. (Urednicek, et al., 1992) The major morphological differences between near-neutralpH and high-pH SCC are the dominant fracture mode and the extent of general corrosion. Near-neutral-pH SCC is transgranular and is often accompanied by corrosion of the crack walls and the outer pipe surface. In contrast, high-pH cracking is intergranular and is usually accompanied by little evidence of corrosion of the crack walls or the outer pipe surface. Morpho-

ABSTRACT Oil and gas pipelines are subject to stress corrosion cracking (SCC) in groundwater environments. Recent SCC failures have emphasized the need for accurate failure prediction models that can be used to assess the integrity and safety of existing pipelines. SCC is characterized by patches of many longitudinal surface cracks in the body of the pipeline that link up to form long shallow flaws, with length-to-depth (L/d) ratios that are typically in the range of 50 to 200. Such flaws are particularly challenging for standard failure prediction models. Because inelastic material behavior is usually associated with SCC failures of pipelines, the authors previously developed a failure prediction model that utilizes inelastic fracture mechanics (IFM). The IFM procedures employ the J integral to evaluate crack-like flaws and are implemented by means of computerized calculations because of the complexity of the numerical analyses required for their application. In addition, the model uses simplified stress analysis to compute estimates of local net-section stress. Failure is predicted to occur either when the applied J value is equal to J toughness or the netsection stress is equal to flow strength. To improve the failure model, recent work has concentrated on long, deep surface cracks. Multiple surface cracks and their possible interaction have been considered. A method for evaluating crack interaction is introduced, and examples of crack-interaction predictions are presented. Also, the failure model was modified to include ductile tearing as well as crack initiation.


Models for predicting failure pressure are used to predict the maximum size of flaw that may remain in a pipeline after hydrotesting. In this application, the largest flaw that could have survived the hydrotest becomes the initial flaw for predicting remaining life at operating pressure. Failure prediction models are also employed to support failure analyses. The flaw size and operating conditions at the time of the rupture are input to a model to check out the postulated failure scenario. A large difference between the predicted and actual failure conditions indicates that additional, usually more detailed, analysis of the failure is required.

logical similarities between near-neutral-pH SCC and high-pH SCC include the presence of large colonies of longitudinal cracks on the outside surface of the affected pipeline, cracks with large length-to-depth (L/d) ratios, and the presence of magnetite and iron carbonate films on the crack surfaces. Flaw L/d ratios in the range of 50 to 200 are typically found in investigations of SCC failures of pipelines. Safe and reliable pipeline operation requires appropriate engineering procedures and models for evaluating the fitness for service (FFS) and structural integrity of pipelines with SCC flaws or that may be subject to SCC. Procedures for evaluating the integrity of pipelines with non-crack-like local thin areas (LTAs) have been developed in past work. (Kiefner and Duffy, 1971; Kiefner, et al., 1973; Kiefner , 1974; ASME, 1991; and Kiefner and Vieth, 1993) Kiefner, et al. (1973) used empirical modifications of linear elastic fracture mechanics (LEFM) to assess crack-like flaws. The petrochemical industry (PVRC, 1997) is using a failureanalysis diagram (FAD) from PD 6493 (BSI, 1991) to assess the integrity of vessels, piping, and tanks with crack-like flaws. This FAD uses the linear elastic stress intensity factor (K) to evaluate the fracture toughness failure criterion and the reference stress to evaluate the strength failure criterion. This FAD approach works reasonably well as long as the reference stress is less than about 40% of the failure strength. Because of inelastic stress-strain behavior, however, the accuracy of the FAD approach decreases when the reference stress exceeds about 40% of the failure strength, which is usually the case for pipelines. For high values of reference stress, inelastic fracture mechanics (IFM) is used to obtain accurate assessments of structural integrity. For this reason, Jaske and Beavers (1996 and 1997) and Jaske, et al. (1996) developed IFM procedures that utilize the J integral to evaluate integrity of pipelines with crack-like flaws. These IFM procedures were taken from those that were developed by Jaske (1984, 1986, 1988, 1990, and 1993) and Marschall, et al. (1992) to evaluate the integrity of high-temperature steam piping; however, they were modified to assess SCC instead of creep cracking. The IFM procedures are implemented by means of computerized calculations because of the complexity of the numerical analyses required for their application. The evaluation of pipeline integrity is a practical problem of great importance to industry. When possible flaws are indicated by in-service inspection, either at a field dig site or at a location identified by an in-line inspection tool, these indications must be assessed. If there is a high probability that these indications reveal the presence of SCC, the integrity of the pipeline must be evaluated to decide what action should be taken -- continued operation, repair, or replacement. Alternatively, the evaluation of pipeline integrity can be used to establish a plan for in-service inspection. In this case, an inspection interval and a limiting size for flaw detection are set based on estimates of critical flaw size and predictions of remaining life. Integrity evaluation provides a means for assessing the risks of undetected flaws that may be left in the pipeline. In this case, failure pressure and remaining life are estimated for a hypothetical flaw that has a size equal to the detection limit of the inspection technique.

OVERVIEW OF THE TECHNICAL APPROACH Fig. 1 presents a flowchart of the technical approach that is used to assess the integrity of pipelines subject to SCC. The first step is characterizing the flaw to define the initial flaw size for remaining life assessment. The second step is predicting the critical flaw size at failure to define the final flaw size for remaining life assessment. The third step is computing the remaining life based on growth from the initial to the final flaw size. Of course, 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 type of monitoring or SCC mitigation must be implemented to assure safe pipeline operation. The flaw size is characterized by means of either in-service inspection or hydrotesting. In-service inspection data may define either a detailed profile of the flaw depth as a function of its length, or it may provide only indications of the maximum flaw length and maximum flaw depth. When a detailed flaw-depth profile is defined, an effective surface flaw is determined from this profile using the procedures described in detail by Kiefner and Vieth (1993). The effective flaw area is defined by its effective length and actual cross-sectional depth. The depth of a semi-elliptical flaw of the same length and area as the effective flaw is then used to determine the effective flaw depth. If a detailed profile is not available, the effective surface flaw is defined as the semi-elliptically shaped flaw with the measured maximum depth and maximum length. When hydrotesting is used to define the flaw, the effective flaw size is estimated to be the largest flaw that would have survived the hydrotest based on the same failure model that is used to compute the critical flaw size under operating conditions. In practice, these effective flaw sizes are estimated as a function of L/d ratio, because the L/d ratio directly 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 reference stress is greater than approximately 40% of the failure strength. Both fracture toughness and flow strength are considered as possible failure


Characterize Flaw Size

In-Service Inspection


Is a Detailed Flaw Profile Available?

J Fracture Toughness Failure Criterion

Fig. 1


Estimate Effective Semi-Elliptical Flaw as Critical Flaw for Hydrotest Conditions

Define Effective Semi-Elliptical Flaw Based on Flaw Length and Depth

Compute Effective Flaw and Define Equivalent Semi-Elliptical Flaw

Compute Remaining Life Based on Toughness Limit


Flow Strength Failure Criterion

Compute Critical Flaw Size for Operating Conditions


Does Toughness Give a Smaller Critical Flaw than Flow Strength?


Compute Remaining Life Based on Flow Strength Limit

Technical approach for assessing integrity of pipelines subject to SCC


modes for crack-like flaws. The smaller of the two calculated critical flaw sizes is the one predicted to cause failure. Remaining life is computed as the time required for the flaw to grow from its initial to final size. The SCC rate (da/dt) is expressed as a function of the value of the J integral. Values of da/dt are measured by testing specimens in the laboratory or are estimated from field data. Remaining life is calculated by evaluating the definite integral of this function from the initial to the final crack size. The mathematical expressions used to implement the flawassessment approach have been presented previously by Jaske and Beavers (1996 and 1997) and Jaske, et al. (1996). Only the expressions directly related to the improvements of the approach are discussed in this paper. Critical flaw size for the flow-strength failure criterion is determined by solving the following equation for the effective flaw area (A): sf = Sfl RSF = Sfl [(1 - A/Ao)/(1 - A/(MAo))]

and pipe diameters for oil and gas pipeline SCC failures in Canada. Both the predicted and actual stresses are given as a percentage of the specified minimum yield strength (SMYS) of the pipe steel. The 45-degree dashed line indicates an exact correlation between those stress values. As shown in Fig. 2, the original predictions were made using an effective flaw defined by only its maximum depth and length. Except for one case, the original predicted failure stresses were very close to the actual ones. 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 not well defined by the maximum flaw 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 Fig. 2. Thus, the SCC-assessment approach has been shown to work well for single flaws in pipelines.



Predicted Failure Stress (%SMYS)

where sf 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. 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 by solving Eq. (1). However, since M is a function of L, the solution must be obtained iteratively. The critical flaw size for the fracture-toughness failure criterion is determined by computing the conditions for which the applied value of J is equal to the J fracture toughness of the material. This calculation also is done iteratively. IFM formulations for a semi-elliptical surface flaw are used to compute the values of J as a function of crack size and nominal stress. The material properties required for use of the flaw-assessment approach are flow strength, stress-strain behavior, J fracture toughness, and flaw-growth rate. Flow strength is based on tensile yield strength or a combination of tensile yield strength and tensile ultimate strength. Plastic strain is used in calculating the value of J as a function of stress. Stress versus plastic strain is characterized by a power law. The strain hardening exponent (n) is the exponent of this power law, while the yield strength is used to determine the power-law coefficient. Standard laboratory test procedures (Harle, et al., 1994 and 1995) are used to measure J fracture toughness (Jc). If J fracture-toughness values are not available, they are estimated from CTOD fracture-toughness data or Charpy V-notch impact energy data (Kiefner, et al., 1973; and Wilkowski, et al., 1987). The SCC flaw growth rate (da/dt) is characterized either as a power-law function of J (Harle, et al., 1994 and 1995) or as a constant value that is independent of J over the observed range of flaw-growth behavior (Beavers and Hagerdorn, 1996; and Jaske and Beavers, 1997). Jaske and Beavers (1996 and 1997) and Jaske, et al. (1996) have validated this approach for single flaws by showing that its predictions agree well with the results of full-scale pipe tests (Kiefner, et al., 1973) and field experience (NEB, 1996). For example, Fig. 2 shows the predictions of failure stress for 14 in-service or hydrotest SCC failures (NEB, 1996). These data were reported to represent the range of materials, flaw shapes,

Based on Maximum Flaw Based on Effective Flaw 1-to-1 Correlation



Use of Effective Flaw Improved the Prediction




0 0







Actual Failure Stress (%SMYS)

Fig. 2 Predictions of failure stress for SCC failures

FLAW INTERACTION MODEL 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. Interacting flaws will fail at a lower stress than predicted by evaluating any these flaws as a single, isolated flaw. In the improved failure model, flaw interaction is evaluated as a general extension of the effective area method. Multiple flaws are assessed by repeated application of Eq. (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 Eq. (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.


occur. This type of evaluation can be used to help establish inspection requirements for measuring flaw length, depth, and separation.

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))]


and RSFc = [(1 - Ac/Aoc)/(1 - Ac/(McAoc))]



Then, flaw interaction occurs when All RSFi â&#x2030;Ľ RSFc

Relative Flaw Size (A/Ao)


Eq. (4) is evaluated for all possible flaw combinations. If more than one value of RSFc satisfies Eq. (4), 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 Fig. 3. Their RSF values are RSF1 = [(1 - A1/Ao1)/(1 - A1/(M1Ao1))]


and RSF2 = [(1 - A2/Ao2)/(1 - A2/(M2Ao2))]


0.6 No Interaction 0.4



To compute the RSF value for the combined flaw using Eq. (3), Ac = A1 + A1 and Lc = L1 + s + L1, where s is the flaw separation. Interaction is predicted to occur, when RSF1 and RSF2 â&#x2030;Ľ RSFc

Diameter = 0.914 m Thickness = 9.53 mm L1 = L2 = 127 mm


0 0







Relative Flaw Separation (s/L1)


Fig. 4 Prediction of the conditions for interaction of two equally sized flaws in a pipeline A1





The flaw interaction model can be applied in a deterministic manner, as illustrated by the above example, or in a probabilistic fashion if probability density functions are defined for the variable parameters. Research is underway to validate this model for two large colinear flaws by means of full-scale burst testing of pipe specimens. Future plans include extension to non-colinear flaws, evaluation more than two flaws, evaluation of small SCC flaws, and probabilistic modeling of multiple flaw interaction.



DUCTILE INSTABILITY MODEL As discussed earlier in this paper, the original fracture toughness model was based on a single critical value. When ductile steels, such as those used in pipelines, are subjected to J fracture toughness testing, they exhibit the initiation of cracking followed by a long period of ductile tearing. This behavior is characterized by a J-R curve, which is a plot of the J integral as a function of the amount of ductile crack extension. Thus, the JR curve is a material property measured by testing specimens in the laboratory. In a pressurized pipe, ductile crack extension will continue until a leak occurs that is large enough to cause a significant loss of pressure or until a point of instability is reached and sudden fracture occurs. For the fracture toughness failure criterion, the sudden fracture as a result of an instability in

Fig 3. Schematic illustration of two surface flaws

Fig. 4 shows predictions for a typical pipeline that were made using Eqs. (5), (6), and (7) with two flaws of equal size (i.e., A1 = A2 and L1 = L1). The pipeline diameter and wall thickness are 0.914 m and 9.53 mm, respectively. The flaws are both 127 mm long. The relative flaw size (A/Ao) is plotted as a function of the relative flaw separation (s/L1). Interaction is predicted for relative flaw separations on or below the curve, while no interaction is predicted for relative flaw separations above the curve. When the flaws are very deep (A/Ao approaching 1.0), the flaws must be very close for interaction to occur. When the flaws are very shallow (A/Ao approaching 0), the flaws must be separated by almost three times their length for no interaction to


elastic-plastic crack growth. The theory of Paris, et al. (1979) is applied to model this ductile tearing instability. The criterion used to evaluate ductile tearing instability is schematically illustrated in Fig. 5. The resistance of the steel to ductile crack extension is characterized by the J-R curve. For a specific pipeline and set of operating conditions the applied J value is calculated as a function of crack depth. Instability is predicted to occur when the slope of the applied J versus crack depth relationship (applied dJ/da) exceeds the slope of the J-R curve for the steel (material dJ/da). Research is underway to validate this model by means of full-scale burst testing of pipe specimens.

REFERENCES API, 1997, Recommended Practice For Fitness-ForService, RP 579, Draft Issue 8, American Petroleum Institute, Dallas, September 15. ASME, 1991, Manual for Determining the Remaining Strength of Corroded Pipelines, A Supplement to ASME B31 Code for Pressure Piping, B31G, ASME International, New York. Beavers, J. A., and Hagerdorn, E. L., 1996, “Near-Neutral pH SCC: Mechanical Effects on Crack Propagation, 9th Symposium on Pipeline Research, A.G.A. Catalog No. L51746, PRC International, American Gas Association, Inc., Arlington, VA, Paper No. 24. BSI, 1991, Guidance on methods for assessing the acceptability of flaws in fusion welded structures, PD 6493, British Standards Institution, London. Delanty, B. S., and Marr, J. E., 1992, “Stress Corrosion Cracking Severity Rating Model,” International Conference on Pipeline Reliability, CANMET, Calgary. Harle, B. A., Beavers, J. A., and Jaske, C. E., 1994, “LowpH Stress Corrosion Cracking of Natural Gas Pipelines,” Paper No. 242, Corrosion 94, NACE International, Houston. Harle, B. A., Beavers, J. A., and Jaske, C. E., 1995, “Mechanical and Metallurgical Effects on Low-pH StressCorrosion Cracking of Natural Gas Pipelines”, Paper No. 646, Corrosion 95, NACE International, Houston. Jaske, C. E., 1984, “Damage Accumulation by Crack Growth Under Combined Creep and Fatigue,” Ph.D. Dissertation, The Ohio State University, Columbus, OH. Jaske, C. E., 1986, “Estimation of the C* Integral for CreepCrack-Growth Test Specimens,” The Mechanism of Fracture, ASM International, Metals Park, OH, pp. 577-586. Jaske, C. E., 1988, “Long-Term Creep-Crack Growth Behavior of Type 316 Stainless Steel,” Fracture Mechanics: Eighteenth Symposium, STP 945, ASTM, Philadelphia, pp. 867 877. Jaske, C. E., 1990, “Life Assessment of Hot Reheat Pipe,” Journal of Pressure Vessel Technology, Vol. 112 (1), pp. 20-27. Jaske, C. E., 1993, “Life Prediction in High-Temperature Structural Materials,” Fatigue and Fracture of Aerospace Structural Materials, AD-Vol. 36, ASME, New York, pp. 59-71. Jaske, C. E., and Beavers, J. A., 1996, “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. Jaske, C. E., and Beavers, J. A., 1997, “Fitness-ForService Evaluation of Pipelines in Ground-Water Environments,” Paper 12, Proceedings of the PRCI/EPRG 11th Biennial Joint Technical Meeting on Line Pipe Research, April 8-10, Arlington, VA. Jaske, C. E., Beavers, J. A., and Harle, B. A., 1996, “Effect of Stress Corrosion Cracking on Integrity and Remaining Life of Natural Gas Pipelines,” Paper No. 255, Corrosion 96, NACE International, Houston. Justice, J. T., and Mackenzie, J. D., 1988, “Progress in the Control of Stress Corrosion Cracking in a 914 mm O.D. Gas Transmission Pipeline,” Proceedings of the NG-18/EPRG Seventh Biennial Joint Technical Meeting on Line Pipe

Value of J Integral

Applied J

dJ da Material J-R Curve

Ductile Tearing Instability Applied dJ/da > Material dJ/da

Crack Depth, a

Fig. 5 Schematic illustration of the ductile instability criterion

SUMMARY A very good model for predicting the failure of pipelines subjected to SCC was developed in past work. In the current study, the model was improved to incorporate the evaluation of multiple flaw interaction and ductile tearing instability. These improvements are being validated in current experimental and analytical studies.


Research, Paper No. 28, Pipeline Research Committee of the American Gas Association, Inc., Arlington, VA. Kiefner, J. F., 1974, “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. Kiefner, J. F., and Duffy, A. R., 1971, “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. Kiefner, J. F., and Vieth, P. H., 1993, “The Remaining Strength of Corroded Pipe”, Paper 29, Proceedings of the Eighth Symposium on Line Pipe Research, A.G.A. Catalog No. L51680, American Gas Association, Inc., Arlington, VA. Kiefner, J. F., Maxey, W. A., Eiber, R. J., and Duffy, A. R., 1973, “Failure Stress Levels of Flaws in Pressurized Cylinders”, Progress in Flaw Growth and Fracture Toughness Testing, STP 536, ASTM, Philadelphia, pp. 461-481. Marschall, C. W., Jaske, C. E., and Majumdar, B. S., 1992, “Assessment of Seam-Welded Piping in Fossil Power Plants,” EPRI Final Report TR-101835, Electric Power Research Institute, Palo Alto, CA. NEB, 1996, Public Inquiry Concerning the Stress Corrosion Cracking of Canadian Oil and Gas Pipelines, MH-2-95, National Energy Board, Calgary, November. Paris, P. C., Tada, H., Zahoor, A., and Ernst, H., 1979, “The Theory of Instability of the Tearing Mode of Elastic-Plastic Crack Growth,” Elastic-Plastic Fracture, STP 668, ASTM, Philadelphia, pp. 5-36. PVRC, 1997, Workshop on Development of Standards for Fitness-for-Service and Continued Operation of Equipment Overview of API RP 579, Las Vegas, NV, February 3. Sutcliffe, J. M., Fessler, R. R., Boyd, W. K., and Parkins, R. N., 1972, “Stress Corrosion Cracking of Carbon Steel in Carbonate Solutions,” Corrosion, Vol. 28, p. 313. Urednicek, M., Lambert, S., and Vosikovski, O., 1992, “Stress Corrosion Cracking – Monitoring And Control,” International Conference on Pipeline Reliability, CANMET, Calgary. Wenk, R. L., 1974, “Field Investigation of Stress Corrosion Cracking,” 5th Symposium on Line Pipe Research, A.G.A. Catalog No. L30174, American Gas Association, Inc., Arlington, VA, p. T-1. Wilkowski, G. M., et al., 1987, “Degraded Piping Program Phase II, Semiannual Report, April 1986 - September 1986”, NUREG/CR-4082, Vol. 5, Battelle’s Columbus Division, Columbus, OH , April.


Jaske-Beavers IPC 1998 Paper  

C. E. Jaske and J. A. Beavers CC Technologies, Inc. Dublin, OH 43017-1386 USA 439 440

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