November 2024
Maintenance, Reliability and Inspection
SMR feed effluent hairpin exchanger: Once upon a time—An unusual thermal mix-point failure—Part 2
This article presents a review of a failure that happened in a hairpin heat exchanger type on the shell side in a H2 (H2) reformer unit.
A thermal mix-point is a known location that can create thermal stress that leads to failure. Usually, this stress is generated by two streams that have a high-temperature differential. This is often seen at a heat exchanger bypass; however, the heat exchanger itself can also be subject to the same damage mechanism and it is important to review this possibility at the design stage. This article presents a review of a failure that happened in a hairpin heat exchanger type on the shell side in a H2 (H2) reformer unit. This mechanism was not identified during the design phase and led to a failure after only two years of operation. Part 1 reviewed the situations encountered during the design stage and how they affected the material selection. Part 2 will review the design selection.
Feed effluent exchangers can be exposed to a high-temperature differential between the shell side and tube side, depending on the design type (concurrent or countercurrent flow design). In the case presented here, a hairpin feed effluent exchanger was subjected to carbonic acid condensation and required replacement. The original construction was made of 1.25Cr-0.5Mo on the shell side and tube side. The tube material was Sa-213-TP304L. The exchanger had been in operation since 2004, and a replacement was planned for 2014 (FIGS. 2, 3 and 4).
FIG. 2. Failure location.
FIG. 3. Failure location in the field.
FIG. 4. Shell liquid penetrant inspection.
Design selection review process. As mentioned, the exchanger was experiencing carbonic acid corrosion and a cladded shell in 316L grade was originally recommended based on the need to avoid potential cracking mechanisms that could lead to through wall failure. So, this was an initial concern. The selection of 316L stainless steel was motivated by its high resistance to carbonic acid.2,8,16
However, the project started 14 mos before the turnaround when this heat exchanger was planned to be replaced. Typically, the project is supposed to start 2 yr in advance. At the design stage, the manufacturer mentioned that there was a high risk of fit-up issues between the tube bundle with the shell if a cladded option was selected—more time was needed to design the exchanger. A decision was necessary: either the exchanger was going to be replaced in-kind with a 1.25Cr-0.5mo material, or the exchanger could be made of solid stainless steel 316L. Additionally, selecting the solid stainless steel would have a lower fabrication cost.
To meet the project schedule, a risk evaluation was completed to validate if it was acceptable to select the solid stainless-steel option.
Chloride presence. The process engineer validated if chloride could be present in this stream. The steam methane reformer is designed to use water condensate generated from the site’s steam reboilers; so, chloride should be inexistant in this water feed. Also, because the unit feed is partially hydrogen (H2) from the catalytic reformer, the chloride concentration could be present. However, the H2 unit is equipped with a chloride guard vessel. In addition, the unit treats the feed with desulfurized zinc oxide reactors. These reactors have a chloride guard layer that is added in case the main chloride guard vessel is bypassed for catalyst replacement. The feed is tested every day to validate if chloride is present, and the detection limit of the testing method is 0.1ppm.
However, after the failure and the chemical analysis that showed a high concentration of chloride, the question was reviewed. This is detailed in Part 1 of the article (October). It has been identified that water condensate unit producers are often unable to provide enough water, forcing the unit to use boiler feed water (BFW). This was not identified before the failure. The chemical analysis of the BFW did not have a high chloride concentration. The average measurement is around 0.005 ppm–0.600 ppm. This concentration is still low, but the condensation/evaporation phenomena could still concentrate chlorides at a very high level in the shell. The sodium, calcium and potassium present in the analysis shows that there was BFW carry-over in the process. It was estimated that BFW droplets carry-over could have contributed to chloride in the process stream.
Risk of stainless steel selection. It was important to have confidence that solid stainless steel would work in this environment. From a corrosion resistance perspective, ample information on the resistance against carbonic acid is provided in literature.2,8,17,18 Additionally, the tubes and the barrel tubesheet were made of stainless steel grade 304L. These components have been in service for 12 yr without showing signs of corrosion and cracking. Based on this positive experience, and by comparing it to typical assessment methodology for CL SCC,17,18 indications supported that the cracking risk susceptibility was low. Also, it was not considered to use higher alloy due to the good performance of the SS304L.
Discussion. After reviewing the corrosion resistance against carbonic acid, the chloride concentration in the unit and the good experience of SS304L in this service, the decision was made to use a solid stainless-steel material. To reduce the cost of the project, meet the tight schedule and improve the corrosion resistance of the equipment, all decisions led to the selection of this option.
At the design stage, the possibility of thermal fatigue was not expected. The good performance of the tube bundle and the barrel tubesheet indicated that this selection had a low risk of failure. These two components were exposed to the corrosion media and maintained excellent performance. The liquid that was present in the shell was surely touching the tubes; however, after the failure investigation it is believed that due to the very low thickness and the temperature of the tubes, the thermal stress was lower than what the shell was experiencing.
The thermal fatigue was missed during the design process and it led to a leak after only 2 yr of operation. With the information obtained from the failure analysis, it can be concluded that the main damage mechanism that drove the failure is thermal fatigue. Chloride could have played a synergetic role, but considering that the base metal failed and that the other components (tubes and barrel tubesheet) did not experience cracking—and that thermal fatigue can generate a similar cracking morphology—the probability the chloride caused the failure is low.
This failure is also related to the project process. If the project had started as scheduled, the manufacturer and the project engineering group could have met the initial requirement to use cladded material. Due to the lack of time, the manufacturer could not design a mechanical solution—this led to the selection of a non-bulletproof material, thus creating a higher-risk environment. Lu, et al., presented failure analysis cases like those in this article because, in the end, this failure could have been identified at the design stage.20 A project schedule to develop complex equipment is vital and enough time must be allowed to develop an appropriate design. Additionally, the original equipment that was installed in 2014 was subject to thermal fatigue; however, this also was not identified at the time.
The final design used will cover the carbonic acid corrosion, thermal fatigue and Cl SCC. With the amount of chloride present in the exchanger, it is still possible to experiment chloride stress corrosion cracking.
Considering all of these damage mechanisms, the adequate design is composed of a shell in 1.25Cr-0.5mo cladded with alloy 625. The thermal expansion of alloy 625 is similar to the 1.25Cr-0.5mo and it is nearly immune to chloride cracking.2,20 Duplex stainless steel was not selected for the clad material due to the high operating temperature and the high chloride. It is not possible to select a different heat exchanger type due to the lack of space in the process unit. The inspection plan must still follow the potential crack initiation caused by the thermal fatigue.
Takeaways. A hairpin feed-effluent exchanger shell made of 1.25Cr-0,5mo was exposed to carbonate acid. A project was initiated to replace the exchanger with a cladded 1.25Cr material with 316L but the project schedule was too short due to the complexity of the replacement. Due to the lack of time, a decision was made to select a solid stainless-steel shell. Validations were made to quantify the risk of Cl SCC and it was considered low probability. Thermal fatigue was not identified as a potential damage mechanism. In summary,
- A heat exchanger should be carefully designed for thermal fatigue when a two-phase flow is present due to shock condensation.
- A hairpin exchanger can be more susceptible due to the barrel tubesheet configuration that acts as a dead leg. This dead leg can lead to condensate liquid from the shell process side that will then evaporate, leading to additional thermal stress.
- The complex fabrication project should be started in advance to ensure there is enough time for adequate design and to meet the fabrication requirements.
- Solid stainless-steel equipment should be selected carefully and most of the time should be avoided.
- Thermal fatigue can have a morphology similar to chloride stress corrosion cracking.
- Even if a small amount of chloride is present, the condensation/evaporation process can dramatically increase the chloride concentration.
The final solution proposed is to select 1.25Cr-0,5Mo cladded with 625 alloy to resist the carbonic acid corrosion, potential Cl-SCC and thermal fatigue. It is not possible to select a different heat exchanger type due to the lack of space in the process unit. The inspection plan will still need to follow the potential crack initiation caused by the thermal fatigue.
DISCLAIMER
Suncor Energy Inc. and its affiliates (collectively Suncor) do not make any express or implied representations or warranties as to the accuracy, timeliness or completeness of the statements, information, data and content contained in this paper and any materials or information (written or otherwise) provided in conjunction with this paper (collectively, the information). The information has been prepared solely for informational purposes only and should not be relied upon. Suncor is not responsible for and is hereby released from any liabilities whatsoever for any errors or omissions in the information and/or arising out of a person’s use of, or reliance on, the information.
LITERATURE CITED
1 American Petroleum Institute (API) Standard 663, “Hairpin-type heat exchangers,” 1st Ed., May 2014.
2 American Petroleum Institute (API) Standard 571, “Damage mechanisms affecting fixed equipment in the refining industry,” 3rd Ed., March 2020.
3 Chawla, S. L. and R. K. Gupta, Materials selection for corrosion control, ASM Intl. (formerly American Society of Metals), 1993.
4 Dillon, C. P., Corrosion control in the chemical process industries, 2nd Ed., MTI Publication No. 45, Materials Technology Institute of the Chemical Process Industries Inc., 1997.
5 Nickel Institute, “The role of stainless steels in petroleum refining: A designers’ handbook series,” Paper #9021, 2020, online: https://nickelinstitute.org/media/1781/roleofstainlesssteelinpetroleumrefining_9021_.pdf
6 ASTM International (formerly American Society for Testing and Materials) Standard E3-11, “Standard guide for preparation of metallographic specimens,” 2017.
7 ASM International (formerly American Society of Metals), ASM Handbook, Volume 9: Metallography and microstructures, 2004.
8 ASM International (formerly American Society of Metals), ASM Handbook, Volume 13: Corrosion: Fundamentals, testing and protection, 1987.
9 Dean, S. W., “Chloride SCC of stainless steel? No - Cyclic strain cracking!” September 2000.
10 Association for Materials Protection and Performance (AMPP – formerly NACE International) 34101, “Refinery injection and process mixing points,” March 2001.
11 Association for Materials Protection and Performance (AMPP – formerly NACE International) SP0114-2014, “Refinery injection and process mix points,” 2014.
12 American Petroleum Institute (API) Recommended Practice 574, “Inspection practices for piping system components,” 4th Ed., Novermber 2016.
13 American Fuel & Petrochemical Manufacturers (AFPM) HAZ002.00, “Hazard identification: Injection point and process mixing point hazards,” Annual Meeting, 2016.
14 Donnelly, C., K. Bagnoli, L. M. Gustafsson and A. Skoulidas, "Strain based modeling of thermal fatigue at mix points," NACE CORROSION 2012, Salt Lake City, Utah, March 2012.
15 Al Abri, N. and J. R. Nair, "Case studies of thermal fatigue damage in duplex and stabilized stainless steel," NACE CORROSION 2019, Nashville, Tennessee, March 2019.
16 ASM International (formerly American Society of Metals), Corrosion in the petrochemical industry, 2nd Ed., 1997.
17 American Petroleum Institute (API) Recommended Practice 581, Risk-based inspection methodology, 3rd Ed., Washington DC, April 2016.
18 Nickel Institute, Paper 9021, “The role of stainless steels in petroleum refining: A designers’ handbook series,” 2020.
19 Shargay, C., T. Tajalli, K. Moore, L. Roberts and J. Allen, “Assessing stress corrosion cracking risks on stainless steel piping and equipment,” Nace International, 2017.
20 Lu, Y., V. Lagad and R. Alvarez, “Case studies of corrosion failures due to poor design and non-optimized materials selection,” Nace International, 2019.
The Authors
François Gilbert has been a Material Engineer for the last 13 yr at the Suncor refinery in Montreal. He is responsible for the risk-based inspection program and participates in fitness for service, developing inspection plans, completing root cause failure analyses, completing corrosion studies and implementing/reviewing operational integrity limits. He is also involved in a group of material specialists covering all Suncor sites. Gilbert earned BS and MS degrees in material engineering, is certified in API-510, API-571 and API-580 standards, and is a Professional Engineer in the Quebec province.
Olivier Jacob has been a Unit Inspector for the last 7 yr at the Suncor Montreal refinery. He participates in developing inspection plans, evaluating equipment integrity and coordinating turnaround inspection teams. He has a professional degree in materials and welding and a BS degree in material engineering. Jacob is certified by API-510, API-570, NBIC-CI/R and is a Professional Engineer in the Quebec province.
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