November 2017

Maintenance and Reliability

Case histories of amine plant equipment corrosion problems–Part 1

Lost production from corrosion costs the oil and gas industry more than $1 B/yr.1

Daughtry, J., Teletzke, E., INEOS Oxide GAS/ SPEC Technology Group

Lost production from corrosion costs the oil and gas industry more than $1 B/yr.1 Past corrosion incidents provide insight into the causes of corrosion and the preventive actions required to protect plant equipment and reduce costly plant downtime.

FIG. 1. Typical alkanolamine acid gas removal system process flow diagram.<sup>2</sup>
FIG. 1. Typical alkanolamine acid gas removal system process flow diagram.2

Corrosion has been observed on every piece of equipment in the typical amine acid gas removal process (FIG. 1). While this configuration is common, many variations on this design exist due to the unique requirements of each acid gas removal application. This two-part series includes six real-world case histories, collected over the past 30 yr, of amine plant experience demonstrating examples of seven different types of corrosion: pitting, erosion, galvanic, selective leaching, stress and fatigue failure, cavitation and fouling.

An emphasis is placed on solving corrosion problems using the following scientific methods: amine chemistry, engineering design, metallurgy, material design, x-ray inspection and computer simulation. Identifying the root cause of corrosion and other process failures often involves a multidisciplinary approach using a combination of these tools.

Reboilers in the acid gas removal process

Properly designing and operating the reboiler are essential to minimizing corrosion risks in the amine acid gas removal process. High temperatures are present in this part of the system by design, which elevates the corrosion risk. Proper operation of the reboiler also protects the rest of the amine system from corrosion, as under-stripping and the resulting high acid gas loadings can cause corrosion in the regenerator and lean amine piping.

FIG. 2. Schematic of a kettle-type reboiler in an amine plant.
FIG. 2. Schematic of a kettle-type reboiler in an amine plant.

The function of the reboiler is to provide enough heat to the amine solution to reverse the exothermic acid base reaction that occurred in the absorption process, which releases the carbon dioxide (CO2) and hydrogen sulfide (H2S) bound to the amine. Heat from the reboiler is supplied to the low-pressure regenerator in the form of steam, which travels upward through the column counter-current to the amine flow.

Depending on the size and requirements of the application, there are multiple methods of providing heat to the reboiler. For example, remote locations often use natural gas, while larger gas plants and refineries use steam, which is readily available. Some larger plants use a waste heat recovery system, which utilizes a heat transfer medium. Hot pressurized water (H2O) has also been used as a heat source. In the ammonia industry, quenched synthesis gas is used in the regeneration process.

The most common reboiler design in amine plants is the kettle-type reboiler (FIG. 2). In a kettle-type reboiler, the amine is on the shell side, while the heat transfer medium is on the tube side. A weir is in place to ensure that the tubes containing the heat transfer medium remain submerged. Pumps are often used with a kettle-type reboiler if the liquid head is insufficient to deliver liquid from the regenerator bottoms to the reboiler.3

FIG. 3. Typical horizontal thermosyphon reboiler.
FIG. 3. Typical horizontal thermosyphon reboiler.

Thermosyphon reboilers (FIG. 3) use the density difference between the regenerator bottoms liquid and the reboiler outlet vapor-liquid mixture to provide sufficient liquid head to deliver the tower bottoms into the reboiler. Thermosyphon reboilers are the most common type of reboiler used in refinery applications.3

Some amine plants use a direct-fired, furnace-type reboiler (FIG. 4); however, this type of reboiler is less common than kettle and thermosyphon reboilers in amine applications. In a furnace-type reboiler, no heat transfer medium is used. Amine circulates through the tubes inside the furnace while heat is supplied to the furnace via combustion of a fuel source. The first case study will show how the design and operation of a furnace-type reboiler resulted in pitting and erosion/corrosion on the reboiler tubes.

While the reboiler configurations in FIGS. 2–4 are typical, each amine plant is unique and can deviate significantly from the standard design. The “Octopus”-style reboiler shown in FIG. 5 is an example of an unconventional reboiler design from an ammonia industry amine process that uses synthesis gas as a heat source for the reboiler.

FIG. 4. Forced recirculation direct-fired reboiler.
FIG. 4. Forced recirculation direct-fired reboiler.

 

FIG. 5. “Octopus”-style synthesis gas-heated reboiler. Photo courtesy of Dyno Nobel.
FIG. 5. “Octopus”-style synthesis gas-heated reboiler. Photo courtesy of Dyno Nobel.


With declining natural gas prices providing cheap energy, reboiler optimization has focused less on energy savings and more on reducing corrosion and the associated downtime and maintenance costs. The first three case studies will discuss how operating conditions, metallurgy and contamination can lead to corrosion and loss of performance in the amine system reboiler. Part 2 will focus on centrifugal pump cavitation corrosion, stress and fatigue failure and pump bearing fouling and seizure.

CASE STUDY 1: REBOIlER TUBE FAILURE—PITTING AND EROSION/CORROSION

Problem

Reboiler tube failures occurred at a Central Texas gas processing plant. Upon inspection, pitting and erosion/corrosion failures were discovered on the reboiler tubes.

Background

A natural gas processing facility designed to treat 25 MMscfd of natural gas with 11.3 mol% CO2 to less than 1,000 ppmv of CO2 using diethanolamine (DEA) converted to a formulated methyl diethanolamine (MDEA) blend to increase capacity and realize energy savings. No corrosion had been observed with DEA, and no corrosion was anticipated with the MDEA blend. In 1990, reboiler tube failures occurred. An inspection of the reboiler revealed pitting and erosion/corrosion on the reboiler tubes.

This plant was on a routine amine analytical program with the amine supplier, and the sample history showed no evidence of increased corrosivity. The amine concentration (45 wt%–50 wt%) and the lean CO2 molar loadings (less than 0.025 mole/mole) had been maintained within the recommended range for preventing corrosion. Additionally, all of the amine samples were as clear as H2O, and the levels of contaminants in the amine solution were within acceptable limits. With the amine chemistry eliminated as the cause of corrosion, the focus shifted to the configuration and operation of the reboiler that had experienced the tube failures.

Observations

The regenerator at this amine plant used a direct-fired furnace-type reboiler like the one shown in FIG. 6. The amine was fed on the tube side from the top of the reboiler. The amine piping took four passes from the feed at the top of the reboiler to the outlet on the bottom. The lower two passes were located along the wall of the reboiler directly adjacent to the center line of the burners.

FIG. 6. Furnace-type, direct-fired reboiler.
FIG. 6. Furnace-type, direct-fired reboiler.

The burner was located in the central lower portion of the furnace and produced a flame with a temperature of 1,000°F. The upper two amine passes were completely above the burner area and were not direct radiant passes. The temperature near the upper amine passes was measured at approximately 450°F. As the amine traveled through the reboiler, it was heated and vaporized to create a vapor-liquid interface. The solution entered the lower section of the reboiler, where the tube skin temperature would approach 1,000°F.

With the change from DEA to a formulated MDEA solvent, a lower circulation rate was required to treat the inlet gas stream, and less heat duty was required to regenerate the amine. Due to the reduced amine flow through the reboiler, the amine in the bottom passes of the reboiler reached excessive temperatures of more than 270°F.

FIG. 7. Pitting corrosion observed on the reboiler furnace tubes. Photo courtesy of Jefferson Pipeline Co.
FIG. 7. Pitting corrosion observed on the reboiler furnace tubes. Photo courtesy of Jefferson Pipeline Co.

A total of four leaks were discovered—two on each lower pass approximately 12 ft from a burner tip and 2.5 ft above the burner centerline. An X-ray inspection of the piping revealed a pitted section of the piping 3 ft–5 ft in length along the horizontal tube center line (FIG. 7). Three of the four leaks were located on the near (fire) side of the tubes.

Evidence of erosion was also observed in the elbows in the lower passes of the reboiler where there was wetting and drying along the vapor-liquid interface. An X-ray inspection of the upper two passes in the area directly above the areas that had failed on the lower passes showed no evidence of pitting or erosion/corrosion.

Conclusions

After the investigation was completed, the following conclusions were drawn:

  1. Excessive skin and amine temperatures resulting from
    a 1,000°F heat source and reduced amine circulation rate caused pitting corrosion on the reboiler tubes nearest to the heat source. The corrosion occurred
    at the interface between the liquid and vapor phases.
  2. Erosion/corrosion was observed in the elbow along the liquid-vapor interface, where amine solution temperatures exceeded 270°F.

Corrections

The following corrections were made:

  1. To find a solution to the corrosion problem, iron-constantan thermocouple junctions were welded several feet apart on each tube to record surface temperature. The use of an iron-constantan thermocouple junction is an example where galvanic corrosion has positive results. When the junction experiences a change in temperature, a voltage is created. The voltage can then be interpreted using thermocouple reference tables to calculate the temperature.
  2. An amine surge tank and recirculation pump were installed, and a recirculation rate was established to keep the reboiler tube temperature below 250°F. The vapor-liquid interface was eliminated, and the pitting and erosion/corrosion of the furnace tubes was corrected.

CASE STUDY 2: SELECTIVE LEACHING OF 400 SERIES STAINLESS STEEL

Problem

A reboiler low-level alarm sounded, which resulted in an automatic plant shutdown to prevent equipment damage.

Background

A 150-gpm amine plant using a 50 wt% formulated MDEA solvent had been treating natural gas for approximately 1 yr without any operational problems. The natural gas conditions were as follows: 20 MMscfd containing 8% CO2 and 10 ppm H2S at 1,000 psig and 95°F. The treated gas specifications were less than 2% CO2 and less than 4 ppm H2S, which were consistently being met.

When the reboiler low-level alarm sounded, operations tried numerous times to restart the plant. However, when heat was added to the reboiler, the low-level alarm triggered an automatic system shutdown. Operations began to troubleshoot the alarm by calibrating the instrumentation to confirm if the low-level alarm represented the true level inside the vessel. A technician was asked to evaluate the alarm instrumentation and control software. No problems were identified with the instrumentation and control systems, confirming that the low-level alarm was an accurate representation of the level in the reboiler. The troubleshooting focus shifted to the amine analytical history.

The analytical history revealed an increase in chromium (Cr) and a purple coloration of the amine. Typically, a purple tint to the amine solution indicates the presence of Cr, and analysis with inductively coupled plasma mass spectrometry (ICP-MS) confirmed that Cr was present. The presence of Cr in amine systems often indicates corrosion to stainless steel equipment. In addition to Cr, the sample was tested for iron (Fe) and nickel (Ni). Fe was present, but no Ni was found in the solution. This data suggested that the Cr source came from 400 series stainless steel, which does not contain nickel, unlike 300 series stainless steel.

The process and instrumentation diagrams (P&IDs) for this process indicated that 400 series stainless steel trays and bubble caps were being used in the regenerator tower. This setup was problematic, as 400 series stainless steel is not compatible with amine service. Amines will selectively leach Cr from 400 series stainless steel, resulting in rapid corrosion to the metal.4 Additionally, there was potential for galvanic corrosion between 400 series stainless steel and the carbon steel shell of the absorber. The recommendation was made to drain the regenerator and reboiler to inspect for corrosion damage to the 400 series stainless steel materials.

During the inspection, a restriction was found in the amine feed line from the regenerator to the reboiler. Pieces of the stainless steel trays and bubble caps were found blocking the feed line to the reboiler. The damaged tray materials were removed from the feed line, and subsequent testing confirmed that the damaged material was 400 series stainless steel. A tray vendor was contacted and a quotation for stainless steel 304L was requested.

Conclusions

The following conclusions were drawn from the event:

  1. Selective leaching of Cr from the 400 series stainless steel trays inside the amine regenerator caused the trays to disintegrate, and the damaged tray materials became lodged in the reboiler feed line
  2. Galvanic corrosion was also suspected between the 400 series stainless steel trays and the carbon steel shell of the tower
  3. The low level in the reboiler resulted from a restriction in amine flow between the regenerator bottoms and the reboiler.

Corrections

The following corrections were made:

  1. The corroded 400 series stainless steel tray remnants restricting amine flow were removed from the line between the regenerator bottoms and the reboiler.
  2. The 400 series stainless steel materials in the regenerator were replaced with 304L series stainless steel, which is compatible with amine service.
  3. Upon restarting the amine system, the low-level alarm did not sound, and the reboiler functioned as designed. No subsequent failures occurred with the 304L series stainless steel trays.

CASE STUDY 3: HYDROCARBON CONTAMINATION—HIGH LEAN LOADING

Problem

The accumulation of hydrocarbons in the regenerator of an amine plant resulted in foaming, unstable operation and high CO2 lean loadings.

Background

A gas processing facility using a formulated amine solvent to remove CO2 to less than 100 ppmv levels began experiencing foaming upsets in the regenerator, which resulted in the treated gas going off-specification. The amine sample analysis revealed a high CO2 lean loading of 0.08 mole/mole, compared to a recommended CO2 lean loading of 0.01 mole/mole–0.025 mole/mole for the amine solvent in this application. With high lean loadings identified as the cause of the reduced acid gas removal, the troubleshooting efforts focused on identifying the cause of reduced performance in the regenerator.

Operations noted that the regenerator had been experiencing frequent foaming upsets in recent months, which had resulted in a high pressure drop across the tower. To combat the foaming upsets, antifoam was being injected into the regenerator at a high rate. Despite the anti-foam injection, the regenerator continued to experience hydraulic upsets.

Observations

The formulated amine solvent used in this application requires approximately 1 mole of steam for every mole of acid gas stripped from the amine in the regenerator to achieve the desired lean loading. The molar ratio of steam to acid gas in the regenerator overhead is known as the reflux ratio. FIG. 8 shows how the reflux ratio is correlated with the overhead temperature and pressure of the regenerator.

FIG. 8. Regenerator reflux ratio correlation. Data provided by INEOS GAS/SPEC Technology Group.
FIG. 8. Regenerator reflux ratio correlation. Data provided by INEOS GAS/SPEC Technology Group.

Historically, the plant had maintained an overhead temperature of 205°F, corresponding to a reflux ratio of 1 at the regenerator overhead pressure of 10 psig. In recent months, the overhead temperature on the regenerator had decreased, despite the consistent application of heat duty to the reboiler. As the CO2 content of the treated gas began to increase, the plant was struggling to maintain an overhead temperature of 190°F with an overhead pressure of 10 psig on the regenerator. The 190°F temperature corresponds to a reflux ratio of 0.55, well below the target reflux ratio of 1. This data explained why the lean loading had increased to 0.08 mole/mole, but it did not explain why the heat duty provided by the reboiler was no longer sufficient to raise the overhead temperature of the regenerator to the desired 205°F.

The plant was shut down to inspect the reboiler for fouling or other issues that might result in reduced heating efficiency. After the plant was cooled, the fluid in the reboiler was drained and multiple layers were discovered in the liquid. Analysis of the layers revealed that the separate layers were toluene and anti-foam. Approximately 150 gal of toluene and antifoam were found floating on top of the amine solvent.

Before reaching the amine acid gas removal unit, natural gas streams pass through multiple separators and stabilizers designed to remove condensable hydrocarbon liquids. Additionally, gas-liquid coalescing filters of less than 0.3 microns (nominal) are recommended upstream of the amine process to keep contaminants and liquid hydrocarbons from entering the system. Even with these upstream separation devices in place, contamination can still occur and result in lost production, costly solvent losses and corrosion.

Hydrocarbon contamination of the amine solvent changes the surface tension of the amine solvent, leading to increased foaming tendency. Severe foaming can disrupt the regeneration process and reduce tray efficiency. This predicament often results in high CO2 and H2S lean loadings, which reduce the ability of the amine to absorb acid gas and increases the corrosion risks in the reboiler and lean amine piping. If a plant is experiencing hydrocarbon contamination, the inlet coalescer filter should be inspected to determine if it is designed and functioning properly.

As a secondary protection against contamination, a carbon bed is recommended for removing hydrocarbons that pass through the plant inlet filtration and enter the amine solution. To protect the regenerator from hydrocarbon contamination, the carbon bed must be installed on the rich side of the amine system. The carbon bed is intended to be a secondary protection against contamination, and can be exhausted in a relatively short period of time in the case of significant hydrocarbon contamination.

Among hydrocarbon contaminants, benzene, toluene and xylene contaminations present unique challenges to the amine process. Normally, the carcinogen benzene passes through the amine system with the treated gas. Xylene is split between ortho-, meta- and para-xylene forms. The boiling points are 291°F, 282°F and 280°F, respectively. With boiling points higher than the normal 250°F reboiler temperature, they will remain in the reboiler as a liquid.5

With a boiling point of 231°F, toluene can condense in the amine solution and accumulate in the regenerator. Once inside the regenerator, toluene can concentrate in the still and form an internal reflux. With a molecular weight of 92.14 g/mol compared to H2O at 18 g/mol, toluene vapor is much heavier than H2O and will displace valuable steam vapor flow, thereby disrupting regenerator tray hydraulics. With a reduction in the steam traffic required to strip the amine, an increase in the CO2 lean loading can occur. After removing the toluene contamination and excess antifoam, the process was resumed without regeneration upsets. The lean loading returned to the normal recommended range (0.01 mol/mol–0.025 mol/mol CO2 loading), and the system was able to meet the treated gas specification.

Conclusions

The following conclusions were drawn from the event:

  1. The cause of the off-spec natural gas was contamination of the amine by toluene, which was refluxing internally inside the regenerator. The toluene in the regenerator soaked up the heat duty required for stripping the amine and created an unstable hydraulic condition, which reduced mass transfer efficiency in the column.
  2. In an attempt to control the foaming in the regenerator, the excessive amounts of antifoam used were ineffective and eventually contributed to reduced performance in the reboiler due to the volume of H2O displaced.
  3. No corrosion failures occurred in this example. However, if the plant were to operate with high lean loadings for an extended period of time, the plant would likely experience pitting corrosion in the reboiler, where high temperatures are present.

Corrections

The following corrections were made:

  1. Toluene contamination was the root cause of the treating problem. The source of contamination resulted from a defective inlet coalescer filter element. Once the element was replaced with a filter sized less than 0.3 micron (nominal), the toluene contamination was resolved.
  2. The use of antifoam agents is an effective tool for solving and controlling most foaming problems, but excessive antifoam use can make foaming worse. New procedures were put in place to limit the use of antifoam agents in the event of foaming and to change activated carbon and inlet coalescer filters first.

The three case studies demonstrate that corrosion in alkanolamine systems can be identified, minimized and controlled with a multidisciplinary approach that takes into account chemistry, engineering design, metallurgy and computer simulations. Part 2 will provide in-depth analysis on three additional case studies, and will focus on centrifugal pump cavitation corrosion, stress and fatigue failure and pump bearing fouling and seizure. HP

LITERATURE CITED

  1. Popoola, L. T., A. Sh. Grema, G. K. Latinwo, B. Gutti and A. S. Balogun, “Corrosion problems during oil and gas production and its mitigation,” International Journal of Industrial Chemistry, 2013.
  2. Teletzke, E. and C. Bickham, “Troubleshoot acid gas removal systems,” CEP Magazine, 2014.
  3. Jaya, A. and K. Kolmetz, “Reboiler engineering design guidelines,” 2013.
  4. INEOS GAS/SPEC Metallurgical Guidelines for Amine Systems.
  5. Handbook of Chemistry and Physics, 60th Ed., CRC Press Inc., 1979–1980.

The Authors

Related Articles

From the Archive

Comments