# Pressure Vessel Sampling Case Studies:

## Case 1: Level 3 LTA Fitness for Service Assessment

Often after sampling, the local thin areas (LTA) in the shell are filled with weld metal back to the nominal thickness of the shell. Typically, this also requires subsequent post weld heat treatment (PWHT) due to the thickness of the shell plate. Both procedures are costly, time consuming and have the potential to cause further damage to the vessel (distortion and cracking). An alternative to weld repair, is a Fitness-for-Service (FFS) assessment of the LTA using the prescribed analysis methods in API-579/ASME FFS-1 (API-579), an internationally recognized code for evaluating degradation in in-service pressurized equipment. API-579 is recognized by API-510, API-653, and NB-23 inspection standards. The LTA can be assessed using the methodologies of Part 5, Assessment of Local Metal Loss, in API-579 and the vessel can be declared FFS without weld repair. Each damage mechanism considered in API-579 includes 3 assessment levels, Level 1, 2 and 3. Level 1 provides the most conservative results. Each subsequent level requires additional analysis and inspection and produces less conservative results.

The results of a Level 1 screening assessment for the 4 typical samples obtained from the Saxon Sampler are summarized in Figure 1. Each plot includes the minimum required shell thicknesses for a single sample type, i.e., Charpy 3×1, Charpy 2×3, Plate, Round w/Charpy’s. Shell thicknesses are included for samples taken at welds or in a shell with a joint efficiency of 1.0, base metal for a shell with a joint efficiency of 0.8, and base metal for a shell with a joint efficiency of 0.7. The thickness curves are a function of the inside diameter of the shell. For example, a Charpy 3×1 sample taken at a weld location in a shell with a 60-inch inside diameter requires a shell thickness of 1.669-inches to meet the API-579 Part 5 local thin area criterion, and therefore be considered FFS without weld repair. Note that this required thickness reduces to 1.164-inches if removed from the base metal of a shell with a joint efficiency of 0.8.

The methodology in Part 5 of API-579 uses a remaining strength factor (RSF) to determine acceptability for FFS. The RSF is defined as a ratio of the collapse load of the damaged component to the collapse load of the undamaged component. Closed form equations are used to establish an RSF for a given LTA. The criterion for FFS is RSF ≥ RSFa, where RSFa = 0.9.

A Level 3 assessment was performed for the LTAs generated from the 4 typical samples obtained from the Saxon Sampler to support the screening results and demonstrate the conservatism in a Level 1 analysis. The Part 5 Level 3 analysis included explicitly evaluating the LTAs using Finite Element Analysis (FEA). Four (4) models were generated, one for each LTA, and included a shell thickness equal to the Level 1 requirement for a shell with a 60-inch inside diameter (weld location). The material selected for the Level 3 assessment was SA-285-C with an allowable stress (S) of 13,750psi. Mises stress plots for each model based on an elastic analysis (EL) are provided in Figure 2. Note that the peak stress identified in each model is below the membrane + bending stress limit of 3S (41,250psi). The results for each model are summarized in Table 1. Note that the elastic limits (PL ≤ 1.5S/RSFa and PL + PB +Q ≤ 3S/RSFa) are satisfied for each model. The average margin on the elastic failure criterion is 1.54.

Additionally, limit load (LL) and elastic-plastic (EP) assessments were performed to identify the Level 3 RSFs. A LL analysis utilizes an elastic perfectly plastic material model with a yield stress set equal to 1.5S. An EP analysis utilizes a true-stress true-strain material model which includes strain hardening. Plots of the 2 material models are shown in Figure 3. Each model was run to failure to identify the collapse load of the damaged component. Additionally, pristine shells were run in a similar fashion to identify their corresponding collapse loads. The RSFs were computed for each assessment based on the RSF ratio defined above. The LL and EP results are summarized in Table 1. The average RSFs are 0.971 and 0.958 for the LL and EP analyses, respectively. Note that the Level 1 results, which are documented in the screening curves, are based on an RSF of 0.9. Both the LL and EP results indicate the actual RSF is much higher (>0.950). The results of the Level 3 EL, LL, and EP assessments indicate that the Level 1 screening results are conservative.

An additional local strain check was performed to assess the potential for local failure (cracking) at the LTA location. The acceptance criterion for protection against local failure is a strain ratio ≤ 1.0. The strain ratio is the equivalent plastic strain divided by the triaxial strain limit. The average strain ratio identified for the assessments is 0.015. Therefore, the LTA locations are not at risk of local failure. Note that the results of these assessments assume the shells are not operating in cyclic service or operating at temperatures within the creep range.

Brittle fracture is a sudden and catastrophic damage mechanism, i.e., instant failure of the pressure boundary, as shown in Figure 1 and Figure 2. Carbon and low-alloy steels are most susceptible. Brittle fracture occurs when crack-like flaws are present and the resistance to crack propagation is below a critical value. The resistance to crack propagation is measured as a material’s toughness. Toughness is typically measured in terms of a critical stress intensity (K_{IC}) in units of ksi√in. The toughnesses of these materials are a function of temperature and when the temperature falls below a certain point the toughness can drop rapidly, as shown in Figure 3. Toughness is closely related to the amount of energy that can be absorbed by the material without cracking and therefore closely trends with Charpy impact test data. The higher the absorbed impact energy at a given temperature, the higher the toughness, as shown in Figure 4. ASTM standard E23 defines the requirements for Charpy Impact Tests. The test requires impact specimens to be broken to identify the absorbed energy. This data can be correlated to material toughness and used in an API-579 Level 3 fracture assessment.

Heavy walled reactors are prone to brittle fracture as many are built from susceptible materials and often are pressurized prior to reaching the required temperature to obtain adequate toughness. The heavy walled design also provides more opportunities for fabrication flaws. Reactors typically operate in aggressive service and may be subject to hydrogen embrittlement and aging effects. All of which will reduce material toughness. The risk of brittle fracture can be evaluated by developing a Minimum Allowable Temperature (MAT) curve. This is a plot of allowable pressures as a function of temperature, as shown in Figure 5. Current process data can be compared to the MAT to determine the risk of brittle fracture. If the process conditions (including start-up and shutdown) are to the right of the limiting MAT curve, then there’s little risk of brittle fracture. If process conditions fall to the left of the limiting MAT curve, then there’s risk of brittle fracture and process conditions should be adjusted to comply with the limiting curve.

This case study considers a 1.25 Cr-0.5 Mo, 4-inch-thick reactor operating at 1100 psig at 800°F. At operating temperatures above 700°F, 1.25 Cr – 0.5 Mo material is subject to embrittlement. The severity of the embrittlement can be correlated to a parameter called X-bar. X-bar is a function of tramp elements (X-bar = 10*%P+5*%Sb+4*%Sn+%As)*100). Typical values of X-bar range from 10 – 50, with the higher the number the greater the likelihood of embrittlement. Newer steels will typically have X-bar = 15 and older steels X-bar = 35. Without information regarding the toughness of the material, conservative estimates would require the assumption of X-bar = 35 and this results in the MAT curve shown in Figure 6. The effects of embrittlement can be seen when comparing the far-right curve to the “Curve A” MAT curve. Curve A corresponds to ASME exemption Curve A materials without environmental effects. 1.25Cr-0.5Mo is a Curve A material. However, testing the material to determine its current toughness, may result in the MAT curve shown in Figure 7 which is much less conservative than the embrittlement curve shown in Figure 6.

In this case study, the effect of testing reveals that the limiting MAT curve may vary significantly from what would be determined using conservative assumptions. In this case the MAT curve may shift as much as 250°F to the left as a result of using test data. These results would indicate less risk for brittle fracture (assuming future operating conditions remain similar to historic conditions) and may provide justification to modify start-up and shutdown procedures to bring equipment off-line and on-line quicker to shortening outages.

## Case 3: Creep Sensitivity Assessment

Pressurized equipment operating at high temperatures may be susceptible to creep damage. Creep is the slow continuous deformation (strain) of a material. Under high temperature exposure, even with constant loading, the material will continue to strain over time. The resulting strain rate will increase quickly (primary creep) then remain relatively constant for a long period of time (secondary creep) and then increase rapidly leading to creep rupture (tertiary creep), as shown in Figure 1. The rupture life of a component is related to the material’s initial strain rate and a material-dependent parameter . The relationship is shown in the following equation:

This relationship is known as the Materials Property Council (MPC) Omega Method. This method is documented in Part 10 of API-579. The Omega-parameter and the initial strain rate are functions of stress and can be computed using the following equations:

The coefficients *a* and *b* are published for a variety of materials in API-579. The coefficients assume no initial creep damage. *T* is the absolute temperature.

To determine the rupture life of a component, the full temperature-stress history of the component is required. If the history is unknown, then a conservative operating history should be chosen.

Creep is a function of both temperature and stress, slight variation in these parameters can result in significant variations in rupture life. Therefore, conservative assumptions of the past operating history can lead to very limiting rupture lives. Likewise, underestimating the past operating conditions can lead to premature creep failures.

Often historic operating conditions are not available. This can be due to poor record keeping, change of service, change of ownership, etc. The advantage of the Omega method is that the Omega and strain rate coefficients can be determined though mechanical testing, and the results will reflect the full operating history up to the time of testing. Therefore, no historical data is needed if creep testing is performed. The resulting parameters can be used to evaluate the remaining life of the component, as shown in Figure 2.

Consider a 2.25Cr-1.0Mo vessel in operation for 40-years. Documentation of the historic operating conditions goes back 30-years. The operation is steady-state at 850°F with local stresses near discontinuities equal to 1.25*S, where S is the allowable stress. To determine the remaining creep life of the vessel, an assumption has to be made of the operating conditions for the first 10-years. If it is assumed that the operating conditions for the first 10-years are equal to the historic data provided for the last 30-years, then the remaining creep life is 25.5-years. However, if the vessel operated at 875°F for the first 10-years before it was repurposed, then the remaining creep life is only 4.6-years. Similarly, if the vessel operated at 825°F for the first 10-years, then the remaining creep life is 32.5-years. The 25°F swing in operating temperature for first 10-years of operation suggests a 27.9-year swing in remining life. As a conservative approach, the vessel would require replacement within 5-years. However, performing an Omega test on the vessel material would account for the full operating history of the vessel and provide the coefficients to determine the Omega and strain rate parameters. These parameters could then be used to accurately predict the remaining creep life of the vessel, ultimately minimizing risk, and potentially extending the service life of the vessel. Omega creep testing may take 2-3 months to complete.