October 2022

Special Focus: Plant Safety and Environment

Why sulfur plants fail: An in-depth study of sulfur recovery unit failures—Part 1

Equipment malfunction or an unplanned shutdown of a SRU can have a significant effect on a production company’s profitability, along with an equally serious impact on personnel safety and the environment.

Bohme, G. E., Sulphur Experts Inc.

Equipment malfunction or an unplanned shutdown of a sulfur recovery unit (SRU) can have a significant effect on a production company’s profitability, along with an equally serious impact on personnel safety and the environment. The goal of this article is to establish the highest-probability threats to—and to focus industry attention on—the reliability of sulfur recovery facilities. These threats were identified by analyzing hundreds of cases of SRU failures investigated by the author’s company over the last 30 yr to understand the root causes of these failures. Failure pathways include corrosion, plugging, temperature excursions, explosions and process gas/fluid releases. This article also offers the most effective strategies to prevent these failures.

The SRU

The role of the SRU is to convert the hydrogen sulfide (H2S) present in various industrial process gases—such as acid gas, sour water stripper (SWS) gas and other gases with sulfur species—to elemental sulfur. Government regulatory agencies typically specify the sulfur recovery efficiency (the percentage of inlet H2S to be recovered as elemental sulfur) required for each facility, or they specify the maximum allowable sulfur species emissions (H2S, sulfur dioxide, or total sulfur species) allowed from each facility. The SRU technologies that are available to meet these regulatory requirements, and the operating conditions required to achieve optimal efficiencies, are well known, and many other articles have dealt with the various reasons why SRUs may fail to achieve their efficiency/emissions requirements.

This article will not focus on the topic of regulatory failures but will address physical/mechanical failures of SRUs. Physical failures can seriously damage SRU equipment, minimize SRU throughput or shutdown an SRU completely, causing oil/gas/chemical production losses and associated profitability and repair costs. These physical failures can also have serious environmental and safety implications, with the worst cases resulting in injury or death.

The author’s company has provided consulting services to sulfur recovery and related industries (such as amine treating, sour water stripping and dehydration) for more than 50 yr, with documented cases going back more than 30 yr. During this period, the author’s company has conducted more than 3,000 projects in more than 60 countries, and currently manages between 200 and 300 projects per year, including a constantly increasing number of mechanical failure investigations. While this historical work does not cover the entirety of SRU failure cases, it is likely the largest collection of SRU failure case studies in the world and can therefore provide a valuable window into the frequency of, and the repercussions associated with, various failure mechanisms.

This article will focus on the highest probability threats to SRU facilities and on general strategies to identity and mitigate each of the different failure mechanisms. Note: The case numbers cited in the article are based on relatively serious incidents only, usually for cases that resulted in shutdowns, lost production, serious equipment damage and recordable incidents. While more minor cases in all failure categories are still extremely common, these were excluded from the case counts to better focus on the results.

FAILURE TYPES

For the purposes of this article, physical and mechanical failures in SRUs have been divided into five main categories (in order of prevalence): corrosion, plugging, temperature excursions, process fluid (gas/liquid) release and explosions. A description of each category, along with case number estimates, examples, consequences and recommendations for investigation and prevention, are presented in each of the following five sections.

Corrosion

SRU vessels and piping are mostly constructed from carbon steel. SRU condenser tube welds, condenser tubes and vessel corrosion allowances are usually on the order of 0.125 in. (125 mil), meaning that corrosion rates of a few mil/yr can be accommodated and dealt with during scheduled turnarounds. However, higher corrosion rates can result in a loss of containment in days, weeks or months—resulting in unscheduled shutdowns and possible process fluid releases. Corrosion scenarios in SRUs (FIG. 1) typically fall into four categories. These include the following:

FIG. 1. Examples of SRU corrosion
  • High-temperature H2S sulfidation
    • Corrosion rates become concerning around 300°C (572°F) (9 mil/yr)1
    • Corrosion rates increase rapidly as temperatures increase [e.g., 37 mil/yr at 400°C (752°F)]1
    • Normal process temperatures at or above this range exist in the reaction furnace and wasteheat boiler (WHB), as well as in some catalyst beds and some condenser inlets
  • Low-temperature solid sulfur/liquid water contact corrosion
    • Typical corrosion rates of 50 mil/yr–70 mil/yr2
    • Can be as high as 500 mil/yr, depending on conditions and species present2
    • Most common in condenser outlets and in liquid sulfur collection and storage, and can occur anywhere the metal temperature falls below 119°C (246°F), which is the freezing point of sulfur
  • Sulfuric acid (SO3) corrosion
    • SO3 is not normally present in SRU gas streams, due to the reducing chemistry of the process
    • Most SO3 is created in the incinerator under oxidizing conditions
    • Has a dewpoint (condenses as liquid sulfuric acid) that depends on concentration; dewpoint ranges from 90°C–200°C (194°F–392°F)3
    • Depending on pH, corrosion rates can be more than 100 mil/yr
  • Water-side corrosion4
    • Various corrosion mechanisms, including oxygen and alkalinity, among others
    • Corrosion rates depend on the mechanism and can be very rapid.

The author’s company’s case studies include hundreds of corrosion incident investigations and number around 25/yr–30/yr, making corrosion the most common failure mechanism category. High-temperature H2S corrosion (most commonly on WHB tube sheets and WHB outlets) and low-temperature frozen sulfur contact corrosion (most commonly on condenser outlet pipes and sulfur storage vessels) are by far the most numerous and are relatively equally represented in the case files (10/yr–12/yr). This indicates that, despite the constantly improving understanding of these corrosion mechanisms and how to avoid them, they continue to be extremely prevalent. Most of the recent case studies have found that the SRU design is not usually the problem (i.e., vessels and piping are usually designed to maintain suitable metal surface temperatures), but that the corrosion results primarily from poor construction practices, poor maintenance, and poor understanding by plant personnel of the importance of skin temperature regulation.

SO3 corrosion case studies are less prevalent, averaging around 2/yr. The most common location for this type of corrosion is in heat exchangers located downstream of the incinerator, where the exchanger tube wall temperatures can easily drop below the SO3 dewpoint, although corrosion of the incinerator stack and the incinerator emissions analyzers have also been noted at many locations.

Water-side corrosion is the least prevalent in the case files, with only a handful of incidents determined to be definitively linked to water-side corrosion mechanisms alone. This may be because water quality is usually carefully monitored and adjusted at most facilities by outside water treatment specialists, and because the other three process-side corrosion mechanisms are simply more likely. Regardless, water-side corrosion does occur and must still be treated properly in the design and operation of the SRU.

Incident investigations for corrosion failures should always begin with the exact location of the failure (i.e., the hot end or cold end of a condenser or WHB tube) and include detailed photographs and inspections of the failure areas. Water-side corrosion failures can often be easily distinguished from process-side corrosion with a visual determination from which side the corrosion progressed—while high-temperature H2S corrosion and low-temperature wet sulfur contact corrosion can often be distinguished by the operating temperature and conditions at the exact failure location. SO3 corrosion can often be easily identified by the presence of a green iron sulfate corrosion product that is not present with other mechanisms, and by the fact that it can only occur downstream of an oxidizing location (e.g., an incinerator). Unfortunately, many incident investigations only begin after the corroded areas or vessels have been removed and replaced without detailed examination, meaning that the most likely root cause must be estimated based on a process review only.

Regarding corrosion prevention, the following recommendations are associated with the most common root causes:

  • High-temperature H2S sulfidation
    • Ensure proper design, installation and maintenance of refractory and ferrules in high-temperature SRU areas—areas that will, or might, operate hotter than 300°C (572°F). Refractory and ferrule design should be conducted by competent personnel and should ensure that metal surfaces will be below this temperature limit where possible. Installation and maintenance of these materials should also be conducted and supervised by competent personnel with strong experience in these areas. Following the installation of these materials, it is important to use proper dry-out/curing procedures as recommended by the material supplier.
    • Utilize proper operating procedures that will not damage the refractory and ferrules, especially during high-temperature operating conditions like fuel-gas firing (e.g., startups, shutdowns and hot standbys) and oxygen enrichment conditions. This includes operating procedures that will avoid overheating or melting these materials, and which are usually based on a safe maximum temperature (allowing for measurement errors and temperature variabilities) of around 1,550°C (2,732°F). This also includes procedures that will avoid thermally shocking the materials—usually defined as heating/cooling them faster than the normally recommended maximum of 50°C/hr.
    • Measure reaction furnace refractory wall (as opposed to process gas) temperatures, usually through a specialized full-time thermocouple located at the refractory wall or through a pyrometer designed to measure refractory temperatures. Temporary thermocouple installations can also be used where appropriate, especially during low-temperature startup conditions. Finally, simulations can be used to determine process temperatures based on process conditions and can be used to confirm conditions that might result in damaging temperatures regardless of the reported values.
    • Ensure proper external heat release from the reaction furnace, so that the shell temperature will not increase significantly beyond the temperature achieved by the internal refractory. The reaction furnace is the only vessel that should not be insulated; instead, a thermal shroud should allow heat to escape from the furnace shell without wind, rain or snow having a direct impact on the shell.
    • Use proper boiler feedwater chemistry and proper blowdown procedures to minimize the buildup of scale on boiler tube surfaces and to ensure maximum heat transfer and minimum tube-wall temperatures.
    • Consider the use of stainless-steel materials in locations where the metal temperatures cannot be maintained below the recommended limit or where the use of refractory materials is impractical (i.e., catalyst bed grating and support mesh).
    • Conduct regular external piping and vessel metal temperature scans to look for temperatures above the recommended maximum. In cases where internal refractory failures have occurred, temporary external cooling measures (i.e., steam or air blowing on the metal surface) can help limit corrosion until the refractory can be repaired.
  • Low-temperature solid sulfur/liquid water contact corrosion
    • Properly insulate all vessels and pipes downstream of the reaction furnace. Insulation should be designed to keep metal surface temperatures hotter than 119°C (246°F).
    • In addition to insulation, consider the use of external heating [typically, 50 psi (345 kPa) steam heating] in the areas that operate at the lowest temperatures [usually anything below 150°C (302°F)]. This type of external heating is already in common use in many areas of sulfur plants (e.g., liquid sulfur rundown lines, transfer lines and seal/storage devices), but it is also useful protection in other areas, such as in condenser outlets and long-tail gas lines.
    • Replace all insulation and external heating elements as soon as possible if they are ever removed for inspection or repair. Regularly check all steam heating loops—including all steam traps—to ensure that they are properly installed and operating.
    • Conduct regular external piping and vessel metal temperature scans to look for temperatures below the recommended minimum and add insulation or external heating where required.
    • Include a proper sweep of the SRU during shutdown procedures to remove as much sulfur as possible before the unit is shut down and opened to atmosphere. In cases where the plant will be left shut down for long periods, incorporate further mechanical sulfur-cleaning steps in combination with moisture-prevention steps (i.e., nitrogen blanketing).
  • SO3 corrosion
    • Where possible, control SO3 formation in oxidizing locations by minimizing both excess oxygen levels and temperatures. For acid gas-fired reheaters, make routine flowmeter checks and analytical checks to ensure that they are being operated well below stoichiometry (usually 60%–75% of stoichiometry). For incinerators, these should ideally be operated with 2%–3% excess oxygen in the effluent gas, and, in the worst case, with no more than 5% excess oxygen. Incinerators should also be operated at the lowest temperature that achieves the required levels of contaminant destruction and plume dispersion. Many facilities operate much hotter than the required temperature due to poor understanding of incinerator operations or because of license requirements.5
    • Use SO3 dewpoint estimates3 to determine the expected incinerator dewpoints under both normal and worst-case conditions. Where possible, keep metal temperatures (both bulk process gas temperatures and metal wall temperatures) downstream of oxidizing locations above the estimated SO3 dewpoint for all cases. Ensure that operating conditions minimize the amount of time spent under worst-case conditions, including during startup and shutdown operations, since these can result in temporary SO3 condensation.
    • When considering heat recovery downstream of an incinerator, either ensure that the design minimizes the risk of crossing the SO3 dewpoint on metal surfaces (including exchanger tube walls) or reconsider whether heat exchange is an acceptable design option.
  • Water-side corrosion
    • Ensure that water treatment and monitoring satisfy vendor recommendations.
    • Follow the vendor recommendations regarding continuous and intermittent blowdown rates.
    • Conduct routine water-side inspections and cleaning whenever the sulfur plant is down and available for inspection.

Plugging

Plugging of SRUs can occur anywhere in the liquid sulfur flow path (i.e., through the rundowns and seal devices) or through the process gas flow path (FIG. 2). The root causes through either of these pathways typically fall into one or more of the following five categories:

 FIG. 2. Examples of SRU plugging.
FIG. 2. Examples of SRU plugging.
  • Solid sulfur
    • Has a freezing point of 119°C (246°F)
    • Can occur anywhere in the SRU (with enough heat loss), but most likely in cooler locations, such as in condenser outlets and in liquid sulfur collection and storage areas
  • Elemental carbon (soot)
    • Most soot is created by improper fuel gas firing during startups and shutdowns
    • Soot can be continuously created in poorly operated fuel gas-fired reheaters and tail gas unit (TGU) burners
    • Can be created in the reaction furnace during large spikes in feedgas hydrocarbon levels
    • Usually gets filtered out across catalyst beds or deposits in low areas such as condensers and rundowns
  • Iron corrosion products
    • Created by the mechanisms discussed in the Corrosion section of this article
    • Can cause plugging where created (i.e., in condenser tubes) or can collect in low points like condensers and rundowns
  • Alumina fines
    • Comes from refractory or catalyst dust
    • Dust is usually created during catalyst or refractory installation, and is not typically created during normal operation
    • Deposit occurs immediately downstream of where it is created, most commonly in condensers and rundowns
  • Ammonia salts
    • In SWS gases, ammonia can react with carbon dioxide to produce salt at temperatures below 85°C (185°F)
    • Salts are most common in SWS lines and knockout drums
    • Ammonia can react with SO3 to produce salt at temperatures below 280°C (851°F)
    • Some ammonia is always present in SRUs processing SWS gas, but SO3 can only be created in oxidizing areas like acid-gas-fired reheaters
    • Ammonia salts are most common in condensers downstream of improperly operating fired reheaters.

The author’s company has many hundreds of plugging case studies, accounting for around 25/yr–30/yr, tying plugging with corrosion as the most common failure mechanism category. Plugging issues due to solid sulfur, soot and corrosion products are all relatively equally common, at around seven cases/yr. Plugging cases due to catalyst or refractory fines are less common, at around two cases/yr—and these cases almost always occur right after startup in plants that did not conduct proper cleaning of vessels. Plugging due to ammonia salts is the least common incident, with less than one case/yr, but this type of plugging tends to be very rapid when it does occur. These case counts are only for significant plugging issues that resulted in large throughput decreases or complete shutdowns—and minor plugging cases (e.g., a temporary blockage of a liquid sulfur rundown) are extremely common.

Incident investigations for plugging issues can be significantly aided if samples of the plugging material are available. In these cases, samples can be analyzed for elemental breakdown by x-ray dispersive spectrometry (EDS), which can immediately identify the plugging components (FIG. 3). Otherwise, if samples are not available, the incident investigation usually involves the determination of the plugging location (from a detailed pressure survey of the plant and visual examination of all liquid sulfur rundown lines) in combination with a review of the operating conditions and history to determine the most likely root cause.

FIG. 3. EDS analysis example.
FIG. 3. EDS analysis example.

Regarding the prevention of plugging, the following recommendations are associated with the most common root causes (Note: A more detailed discussion of plugging mechanisms and recommendations on avoiding and reversing plugging can be found in literature6):

  • Solid sulfur
    • Prevent sulfur freezing through proper design, insulation and external heating. Ensure that all insulation and external heating elements are replaced as soon as possible if they are ever removed for inspection or repair. Regularly check all steam heating loops to be certain that they are properly installed and correctly operating.
    • Conduct routine external temperature scans to look for cold spots. Add insulation or external heating where required.
  • Elemental carbon (soot)
    • Always confirm stoichiometry when the reaction furnace is being fired on a fuel gas stream or when any inline heaters (SRU reheaters or TGU burners) are initially being restarted with fuel gas. Stoichiometry checks involve measuring excess oxygen as an indication of excess stoichiometry operation (a portable fuel-cell-style oxygen analyzer is recommended for this service) and directly measuring process gas soot using various simple filter tests. Note: Damaged burners or poorly designed or operated burners can result in poor mixing and create multiple stoichiometry zones within the same burner, resulting in simultaneous soot and excess oxygen measurements.
    • Minimize baseline hydrocarbon content, along with the frequency and severity of hydrocarbon spikes in the acid gas and SWS gas streams, by optimizing the design and operation of the amine and SWS units. Detailed recommendations for minimizing hydrocarbons in these two units are available in literature.
    • Conduct sulfur wash procedures to remove soot from catalyst beds, where applicable. These procedures are best applied shortly after the soot has been created (i.e., within days or weeks), since experience has indicated that the soot can agglomerate and harden over time, making it harder to remove.
  • Iron corrosion products
    • Prevent corrosion by using the detailed recommendations presented in the Corrosion section.
  • Alumina fines
    • Conduct a preliminary removal of any visible dust after catalyst/refractory installation through vacuuming and sweeping of the affected vessels.
    • Prior to restarting a plant after a turnaround involving refractory or catalyst changes, conduct a thorough dust blow procedure. This involves using the sulfur plant air blower to blow dust out of the affected vessel and into the atmosphere (or to a dust collection device). The dust blow procedure is usually done vessel by vessel, with vessels reconnected to the next downstream vessel as they are cleaned. An exact procedure depends on the ease and ability of creating various breakpoints in the process and should be combined with buttoning-up steps for the various vessels after they have been entered during turnaround. The dust blow procedure has the additional benefit of removing all other lightweight contaminants, such as loose corrosion scale, soot and other light debris.
  • Ammonia salts
    • Keep ammonia-containing SWS streams at or above 85°C (185°F) prior to entering the reaction furnace.
    • Ensure good reaction furnace ammonia destruction by maintaining furnace temperatures at or above 1,250°C (2,282°F). This can be achieved by various methods, including acid gas bypass designs, oxygen enrichment, feed gas preheating and fuel gas co-firing.
    • Properly tune acid gas-fired reheaters to avoid SO3 formation. This should involve metering checks and analytical checks to confirm stoichiometry.

Part 2

Part 2—which will focus on temperature excursions, process fluid (gas/liquid) releases and explosions—will be published in the November issue. HP

NOTE

This article was first presented at the Laurance Reid Gas Conditioning Conference in Norman, Oklahoma, in February 2022.

LITERATURE CITED

  1. Marriot, R. A., R. Sui, N. I. Dowling and C. B. Lavery, “High Temperature Sulfidation of Carbon Steel under Claus Waste Heat Boiler Conditions,” Alberta Sulphur Research Limited Quarterly Bulletin, July–September 2020.
  2. Clark, P. D., N. I. Dowling and C. B. Lavery, “Corrosion in Claus Tail Gas and Pit Off Gas Lines,” Alberta Sulphur Research Limited Quarterly Bulletin, July–September 2015.
  3. Yeaw, J. S. and L. Shnidman, “Dew point of flue gases of fuels containing sulfur,” Power Plant Engineering, 1943.
  4. Huchler, L. and E. Nasato, “Hidden Opportunity: Maximise Reliability of the Waterside of Sulfur Recovery Units,” CRU Sulphur Conference 2020.
  5.  Kiebert, J. and J. Sames, “Sulphur Plant Incinerators Emission and Energy Conservation: A Balancing Act,” 2013.
  6. Bohme, G., “Why Sulphur Plants Plug,” Laurance Reid Gas Conditioning Conference, February 2019.

The Author

Related Articles

From the Archive

Comments

Comments

{{ error }}
{{ comment.comment.Name }} • {{ comment.timeAgo }}
{{ comment.comment.Text }}