Jaske-Beavers IGRC98 Paper TSO-13 by DNV Columbus

PREDICTING THE FAILURE AND REMAINING LIFE OF GAS PIPELINES SUBJECT TO STRESS CORROSION CRACKING IGRC98 Paper TS0-13 1998 International Gas Research Conference 8-11 November 1998, San Diego, CA USA C.E. Jaske and J.A. Beavers CC Technologies, Inc. USA http://www.cctechnologies.com

ABSTRACT For safe and reliable operation, engineering procedures are needed to predict the failure and remaining life of gas pipelines that are subject to stress corrosion cracking (SCC). Inelastic fracture mechanics (IFM) procedures that employ the J integral have been developed to evaluate the integrity of pipelines with crack-like flaws. These IFM procedures are extensions of well established methods for evaluating the integrity of pipelines with corrosion flaws. They are implemented by means of computerized calculations because of the complexity of the numerical analyses required for their application. Failure predictions are based on either a J fracture toughness criterion or flow strength criterion, depending on which one predicts the lower failure stress or smaller critical flaw size. Remaining SCC life is computed as the time required for the flaw to grow from its initial size to a final size that is predicted to cause failure at the operating pressure.

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INTRODUCTION The first incident of external stress corrosion cracking (SCC) on natural gas pipelines reportedly occurred in the mid 1960's [1], and numerous SCC-related failures have occurred since that time. A characteristic of SCC failures is the presence of colonies of many longitudinal surface cracks in the body of the pipe that link up to form long surface flaws. Early SCC failures were intergranular, and the fracture faces were covered with black magnetite or iron carbonate films with little evidence of general corrosion. A concentrated carbonate plus bicarbonate solution was identified to be the most likely environment responsible for the cracking.[1, 2] This environment is now known as the classical or highpH cracking environment; it is simulated in the laboratory using a 1N NaHCO3 + 1N Na2CO3 solution, that has a pH of about 9.3. The environmental aspects associated with 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 SCC correlated with near-neutral-pH (pH < 8) dilute CO2containing electrolytes and that cracking was not observed where higher pH electrolytes were detected.[3] This form of SCC has been termed near-neutral-pH, low-pH, or non-classical SCC. Since the discovery of near-neutral-pH SCC by TCPL,[4] other pipeline companies, including NOVA Corporation, have also identified near neutral-pH-SCC on their lines.[5] The main morphological differences between near-neutral-pH and high-pH SCC are the fracture mode and the extent of general corrosion. Near-neutral-pH SCC is transgranular and corrosion of the crack walls and outer surface of the pipe is often associated with this form of cracking. In contrast, high-pH SCC 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-pH SCC and high-pH SCC include the large colonies of longitudinal cracks on the outside surface of the affected pipelines, the presence of magnetite and iron carbonate films on the crack surfaces, and very long flaws. Flaw length-to-depth ratios in the range of 50 to 200 are typically found in SCC failures of pipelines. Safe and reliable operation requires appropriate engineering procedures and models for evaluating the potential for failure and the remaining life of pipelines subject to SCC. Procedures for evaluating the integrity of pipelines with non-crack-like local thin areas (LTAs) have been developed in past research and testing.[6-10] An empirical linear elastic fracture mechanics (LEFM) model has been used to assess crack-like flaws.[10] The petrochemical industry [11, 12] uses a failure-analysis diagram (FAD) from PD 6493 [13] to assess the integrity of structures with crack-like flaws. This FAD employs the linear elastic stress intensity factor (K) to characterize fracture toughness and the reference stress to characterize flow strength. The FAD method works reasonably well as long as the stress is less than about 40% of the flow strength. However, its accuracy decreases when the stress exceeds 40% of the flow strength, which is usually the case for gas pipelines. For high levels of stress, inelastic fracture mechanics (IFM) usually provides more accurate failure predictions than the FAD approach. For this reason, the authors have developed IFM procedures that employ the J integral to predict the failure of pipelines with crack-like flaws.[14-17] These IFM procedures were adapted from those used to evaluate the structural

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integrity of steam piping [18-23], were modified to account for SCC instead of creep cracking, and are implemented by means of computerized calculations. The evaluation of pipeline failure and remaining life has important practical applications. When a flaw is found by inspection, the effect of this flaw on failure stress and remaining life must be evaluated to decide what action should be taken -- continued operation, repair, or replacement. Inspection intervals and limiting sizes for flaw detection can be established from estimates of critical flaw size at failure and predictions of remaining life. Predictions of failure stress and remaining life can be used to assess the risks associated with leaving undetected flaws in a pipeline. For example, failure pressure and remaining life are often estimated for a hypothetical flaw that has a size equal to the detection limit of the inspection tool. Models used to predict failure pressure can also be used to predict the maximum size of flaw that may remain in a pipeline after hydrotesting. In this case, the largest flaw that could have survived the hydrotest becomes the initial flaw for predicting remaining life. Finally, failure prediction models can be employed to support failure analyses. The flaw size and operating conditions at the time of failure 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. TECHNICAL APPROACH Figure 1 presents a flowchart of the technical approach used to predict failure and remaining life for stress-corrosion flaws. First, the initial flaw size is characterized by means of in-service inspection or hydrotesting and an effective semi-elliptical flaw is defined. If a detailed flaw-depth profile is available, the effective area and length of this profile [6] is used to define the effective depth of the semi-elliptical flaw. Otherwise, the effective flaw is based on the maximum flaw length and depth or the critical size flaw predicted to cause failure under hydrotest conditions. Next, the critical flaw size predicted to cause failure under operating conditions is estimated to define the final flaw size for the remaining life assessment. Both J fracture toughness and flow strength failure criteria are evaluated to estimate the critical flaw size. Finally, remaining life is computed based on growth from the initial to the final flaw size. If the flaw growth rate is not known or can not be estimated, remaining life can not be predicted and some type of monitoring or remediation must be implemented to assure safe gas pipeline operation. Details of the mathematical expressions used to predict failure and remaining have been presented and reviewed in previous papers [14-17]. Thus, only the key items are covered in the current paper. The critical flaw size for the flow-strength failure criterion is computed by solving the following equation for the effective flaw area (A): ﾏデ = Sfl [(1 - A/Ao)/(1 - A/(MAo))]

(1)

where ﾏデ is applied stress at failure, Sfl is the flow strength of the material, Ao is the flaw length times the wall thickness (t), and M is the Folias factor [6]. For a specific flaw length (L), the depth (d) of a semi-elliptical flaw is then computed using the value of A obtained by solving Equation (1). Because M is a function of L, the solution must be obtained by an iterative numerical procedure. TSO-13.3

The flow strength of a material is usually defined as the average of its tensile yield strength (TYS) and its tensile ultimate strength (TUS) Sfl = (TYS + TUS)/2

(2)

In some cases, the definition of flow strength is based only on the yield strength of common pipeline steels [6]. However, the authors have found that Equation (2) provides accurate failure predictions for a wide variety of steels, including common pipeline steels. 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. The following expression is used to compute values of J for a semi-elliptical surface flaw [14, 15]: J = Qf Fsf [σ2 π d/E + f3(n) d εp σ]

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(3)

Characterize Flaw Size

In-Service Inspection

Yes

Is There a Detailed Flaw Profile?

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 Critical Flaw Size for Operating Conditions

J Fracture Toughness Failure Criterion

Compute Remaining Life Based on Toughness Limit

Hydrotesting

Yes

Does Toughness Give a Smaller Critical Flaw than Flow Strength?

Flow Strength Failure Criterion

Compute Remaining Life Based on Flow Strength Limit

Figure 1. Approach for Predicting Failure and Remaining Life.

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where Qf is the elliptical shape factor, Fsf is the free-surface factor, σ is the local stress, d is the crack depth, E is the elastic modulus of the material, f3(n) is a function of the strainhardening exponent developed by stress analysis, n is the strain-hardening exponent of the material, and εp is plastic strain. The stress-strain behavior of the material must be characterized to calculate the values of f3(n) and εp in Equation (3). Typically, stress versus plastic strain is characterized by a power law. The strain hardening exponent is the exponent of this power law, while the tensile yield strength is used to determine the power-law coefficient. Standard laboratory test procedures [24, 25] are used to measure J fracture toughness (Jc) and the J-R curve (J as a function of crack growth for ductile tearing) for pipeline steels. If J fracture-toughness data are not available, Jc values are estimated from Charpy V-notch impact energy (CVN) using one of two empirical correlations [10, 26]. One correlation gives a large value of fracture toughness that is an estimate of Jc for unstable fracture [10], whereas the other correlation gives a lower-bound estimate of the plane-strain fracture toughness [26]. Recently, both the flow-strength and J-fracture-toughness failure criteria were extended to include the possible interaction of multiple flaws [17]. Also, toughnessdependent failures can be predicted using the ductile instability criterion when a J-R curve is available [17]. In some cases, the SCC flaw growth rate (da/dt) can be characterized as a power-law function of the value of J [24, 25]: da/dt = G Jg

(4)

where G and g are constants that depend on the material and environment. Integrating Equation (4) from the initial to the final flaw size gives the remaining flaw-growth life. When da/dt is approximately constant and independent of J over the observed range of SCC flaw-growth behavior, the value of G equals the linear flaw-growth rate and the value of g equals zero. VALIDATION OF FAILURE MODEL The technical approach outlined in Figure 1 and reviewed in the preceding section is complex, and its use requires a number of iterative computations. These computations are time consuming to perform by hand but are easily performed using a personal computer. For this reason, the CorLAS™ (Corrosion Life Assessment Software) computer program was developed to perform the required calculations. The program runs on personal computers that utilize either MS-DOS, including Windows, or Macintosh OS and are equipped with math coprocessors. The failure model has been shown to provide very good predictions of the published data [10] for full-scale burst tests of API X52, X60, and X65 steel pipe [13, 14]. Tensile strength and Charpy impact energy values were reported for each specimen. The approach gave good predictions of the critical flaw size when the Charpy impact data were used to estimate J fracture toughness values for unstable crack extension.

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In a Canadian study of SCC on pipelines [27], the CorLASâ&#x201E;˘ computer program was found to provide the best failure predictions of the four approaches that were evaluated. Those predictions are shown as solid circles in Figure 2. The predicted failure stress is plotted as a function of the actual failure stress and the 45-degree line indicates an exact correlation between those stress values. The stresses are given as a percentage of the specified minimum yield strength (SMYS) of the pipeline steel, and the predictions were made using an effective flaw characterized by its maximum depth and length. Except for one case, the predicted failure stresses were very close to the actual failure stresses. The flawdepth profile data for that case revealed that the SCC flaw was much deeper at its central portion than near its ends, so its effective length was poorly characterized by its maximum length. The predicted failure stress was close to the actual failure stress when the actual flaw-depth profile was used to characterize its effective length, as indicated by the open circle in Figure 2.

Predicted Using Maximum Flaw Predicted Using Effective Flaw 1-to-1 Correlation

Predicted Failure Stress (%SMYS)

120

100

80 Use of Effective Flaw Length Improved the Prediction

0 0

100

120

Actual Failure Stress (%SMYS)

Figure 2. Correlation of Predicted with Actual Failure Stress, Data from Reference [27].

SCC FLAW GROWTH BEHAVIOR Data on SCC flaw growth behavior in near-neutral-pH environments have been developed both from laboratory testing [24, 25] and field experience. Early laboratory work indicated that the SCC rate could be expressed as the power-law function of J given by Equation (4). Growth rates ranging from 3 x 10-7 to 6 x 10-4 mm/s (0.37 to 745 in/year) were TSO-13.7

measured on rising load tests of compact-tension (CT) specimens. Under more realistic cyclic loading conditions that simulate pressure fluctuations in an operating pipeline, the rate of cracking was not a function of the applied J value. During steady state cycling, maximum crack-growth rates were about 2.0 x 10-8 mm/s (0.025 in/year). The prior loading history on the specimen was the primary factor controlling the crack-growth rate. Decreasing the frequency (from 10-4 Hz to 10-5 Hz) and changing the waveform (from triangular to trapezoidal) decreased the crack-growth rate slightly, but the effects may be within experimental scatter. Decreasing the R ratio (from 0.9 to 0.6) while maintaining the same maximum load increased the crack-growth rate by over a factor of two. Some stable crack extension occurred during a simulated hydrostatic test sequence (overload), but the overload also promoted a decrease in the crack-growth rate.[28] Crack growth rate data for actual pipelines has been developed primarily from analyses of field SCC failures. One method of estimating the crack-growth rate is to divide the total crack depth by the life of the pipeline. This method is expected to give nonconservative estimates because 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, the potent cracking environment to develop, and the SCC to initiate. Improved estimates of crackgrowth rates may be obtained where there are demarcations on the fracture surface that are associated with prior hydrostatic testing. This latter technique has yielded rates in the range of 1 x 10-8 to 2 x 10-8 mm/s (0.012 to 0.024 in/year) for the growth of near-neutral-pH stress corrosion cracks. When Equation (4) is integrated from the initial to the final flaw size to calculate remaining SCC life, some constraint must be placed on flaw shape as it grows. One of three options is used to define the flaw shape during growth: (1) growth with a constant length-todepth (L/d) ratio, (2) growth with a constant crack length, or (3) constant growth all along the crack front. The constant L/d criterion is applied to small SCC cracks where significant crack interlinking within the colony is expected to occur during growth. For large SCC flaws that are likely to consist of cracks that have already linked, the constant L/d criterion is too conservative, and the flaw is modeled to be growing constantly. If it is suspected that a large flaw will increase only in depth but not in length, the constant length criterion is used. In most practical cases, the difference between constant length and the constant growth criterion is negligible. REMAINING LIFE PREDICTION This section describes a typical example of predicting the remaining SCC life for an operating gas pipeline. The pipeline dimensions and material properties are listed below: Outside diameter = 0.914 m (36 in.) Wall thickness = 9.53 mm (0.375 in.) Specified minimum yield strength (SMYS) = 448 MPa (65 ksi) Specified minimum ultimate strength = 531 MPa (77 ksi) Minimum J fracture toughness = 219 kJ/m2 (1250 in-lb/in2) The design maximum allowable operating pressure (MAOP) was 6720 kPa (975 psig), using a design factor of 72% of SMYS. After in-service inspection of the pipeline, it was TSO-13.8

concluded that no SCC flaw deeper than 20% of the wall thickness was present in the pipeline. Thus, 20% of the wall thickness or 1.91 mm (0.075 in.) was used as the initial flaw depth for the analysis. The CorLASâ&#x201E;˘ computer program was used to compute critical minimum flaw depth and minimum remaining life as a function of flaw length for a typical SCC flaw growth rate of 10-8 mm/s (0.012 in/year). The results are presented in Figure 3. Based on the inspection results, the maximum initial flaw depth (open circles) is a constant at a value of 1.91 mm (0.075 in.), while the critical minimum flaw depth (open squares) decreases with increasing flaw length for flaw lengths equal to or greater than 78 mm (3.06 in.). Leaks are predicted for flaw lengths less than 78 mm (3.06 in.). The minimum remaining life also decreases with increasing flaw length for flaw lengths equal to or greater than 78 mm (3.06 in.). To avoid possible SCC failures within a re-inspection interval of 10 years, flaws greater than 230 mm would need to be removed from service or measures to eliminate the possibility of SCC flaw growth would have to be implemented. The predicted remaining lives were minimum values because the initial flaw depth was a maximum value and the critical flaw depths were predicted from minimum material properties. When hydrotesting is used to estimate the initial flaw depth, the estimates of critical flaw depth at the hydrotest pressure and at MAOP should be made using average material properties [16]. Using minimum properties for the hydrotest pressure and MAOP will underestimate the critical flaw depths and give non-conservative predictions of remaining life. As discussed by Jaske and Beavers [16], both the initial and final flaw depths decrease with increasing crack length when hydrotesting is employed.

10 Maximum Initial Depth Minimum Critical Depth Minimum Remaining Life, years

Flaw Depth, mm

25 20

6 15 Leak

Rupture 10

Minimum Remaining Life, years

0 0

100

200

300

400

500

600

Flaw Length, mm

Figure 3. Predicted Flaw Depth and Remaining Life as a Function of Flaw Length.

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SUMMARY

The approach discussed in this paper provides a good method of predicting the failure and remaining life of gas pipelines that operate in environments where SCC may occur. The approach uses the effective-flaw concept to define the worst effective flaw length and depth for a measured surface-flaw depth profile. The critical flaw size at failure is determined by using both a flow-strength failure criterion and a J-fracture-toughness failure criterion. The validity of this approach was verified by predicting the failures of pipeline-specimen burst tests and actual pipelines during operation and hydrotesting. An example was discussed to show the application of this approach to a realistic problem.

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