Many sulfur recovery process units in service today weren’t designed for today’s throughput demands or emissions standards. In some cases, they’ve been modified, repaired and sometimes pushed past their original design basis.
The result is a unit that may still be running but is doing so inefficiently, unreliably or outside compliance. Here are three common problems associated with low sulfur recovery process unit performance, and how engineering and sulfur recovery unit troubleshooting can solve them.
Problem #1: Catalyst Degradation
Catalyst degradation is one of the most common and least visible SRU performance problems. A Claus catalyst is typically activated alumina. Titania is sometimes used in lower portions of the first bed, and occasionally in subsequent beds. Catalyst activity loss can occur due to the following:
Sulfated Alumina
Alumina (and even titania) can react with sulfur oxides, deactivating active sites. This usually happens when excess air is sent to the reaction furnace burner, enough to cause free oxygen to exit the combustion chamber. Sulfur plants with direct-fired reheaters may experience trace oxygen escaping from those reheaters into the catalyst beds, especially when fueled by natural gas. Decreasing the air-to-fuel ratio or increasing the firebox residence time may be needed.
If such excess air has not occurred for too long, such deactivation can be mostly reversed by a “rejuvenation” procedure. This procedure entails operating with significantly reduced air at elevated catalyst feed temperature for a few days.
Carbon Deposition
This most often occurs when excess heavy hydrocarbons are carried in with the feeds from the upstream amine or sour water stripper units. Often, this results in “dusty” carbon that blocks catalytically active sites and can even increase pressure drop. A “sulfur wash” procedure can reverse dusty carbon.
The sulfur wash entails lowering catalyst bed temperatures so that some of the sulfur formed actually condenses in a catalyst bed. Such an operation may need to be maintained for several days, during which the product sulfur will appear black or dark grey due to carbon.
If the hydrocarbons are high in aromatics, especially benzene, traces of them can survive the thermal reactor and crack on the catalyst. This is a mostly permanent degradation of catalytic activity. Additionally, extreme carryover of heavy hydrocarbons can result in consolidated (non-dusty) carbon deposition in the catalyst bed, which causes activity loss, a more significant pressure drop and generally cannot be reversed.
Hydrothermal Aging
This is a normal aging process loss that occurs over a long period of time. Temperature changes in the presence of water vapor can slowly cause the catalyst to expand and contract, warping and misshaping its surface, and destroying its micro-pore structure. As a result, even well-operated sulfur plants may require a catalyst changeout every 4 to 8 years.
Burnout
Burnout is a temperature runaway caused by free oxygen from the reaction furnace (or reheat burner) burning elemental sulfur on the catalyst, resulting in extremely high temperatures. Rapid, permanent deactivation can occur. Other problems include damage to bed supports, the vessel shell and piping.
A degraded catalyst bed directly increases the amount of sulfur compounds exiting the SRU. If the SRU tail gas unit cannot adequately capture the increased sulfur compounds (or if there is no tail gas unit), SO2 emissions will increase at the stack. For facilities subject to EPA NSPS Subpart UUU or state-level sulfur emission limits, this isn’t just an efficiency problem—it’s a compliance exposure with real regulatory and financial consequences.
An adequate engineering response requires understanding the above conditions driving the degradation, not just the degradation itself. Replacing the catalyst without correcting root causes will likely repeat the degradation cycle.
Problem #2: Aging Infrastructure
Sulfur storage and piping infrastructure, including jacketed sulfur lines, seal legs, sulfur pits and tanks, accumulate risk differently than process equipment. Failures associated with sulfur storage and piping infrastructure tend to be localized and repairable, which creates a natural incentive to keep patching equipment rather than assessing the system’s overall condition. We recently worked on a project that demonstrated when it may be better to replace a system rather than make iterative repairs.
In this SRU sulfur storage tank replacement project, the client had made multiple repairs to a converted LPG vessel over decades, managing H2S vapor exposure, shell corrosion and internal steam pipe failures one incident at a time. At a certain point, the accumulated integrity risk made continued repair the higher-risk option. We designed a replacement vessel to fit and executed the changeout in a congested area while keeping SRU #1 in service and without destabilizing adjacent foundations.
Problem #3: Air-to-Feed Ratio Control
Combustion air control can have significant consequences when it drifts. The margin for error is narrow in both directions:
Too much combustion air results in more SO2 than is needed to react with H2S to form sulfur. This excess SO2 eventually exits the SRU unreacted, increasing emissions. Excess SO2 will also have impacts on a downstream tail gas unit, increasing reducing gas needs, and possibly causing low quench water pH.
Way too much combustion air drives free oxygen into the catalyst beds, where it sulfates catalyst alumina, deactivating it. As mentioned above, higher levels of free oxygen will combust sulfur adsorbed in the catalyst, causing extreme catalyst-destroying temperatures.
Too little combustion air results in more H2S than needed to react with the SO2 to make sulfur. This excess H2S eventually exits the SRU unreacted, increasing emissions. In a “react, absorb & recycle” tail gas unit, extreme H2S slip may overwhelm the tail gas unit’s amine system’s ability to capture all H2S, resulting in a real SO2 emission increase from an incinerator.
In some units, combustion controls may be unreliable. Analyzers may be slow to respond, poorly calibrated or degraded. The control loops that translate the analyzer signal into combustion air flow may not be adequately tuned or well-configured for current feeds and operations.
The engineering fix isn’t always a control system overhaul. It may be a feed characterization exercise and analyzer recalibration. However, identifying which problem you actually have requires understanding both the process chemistry and the instrumentation.
Should I Revamp or Repair My System?
Repairing addresses a specific failure, while revamping addresses a design basis problem. This distinction matters because applying repair logic to a design-based problem produces a unit that stays in service but never actually performs correctly.
The engineering services behind this kind of assessment span process, mechanical and instrumentation disciplines. For an in-house engineering team that specializes in each of these disciplines and more, you can count on JEPCO to perform sulfur recovery unit troubleshooting.
FAQs
What are the most common problems associated with sulfur recovery units?
Catalyst degradation from sulfating of alumina, from hydrocarbon contamination, from air-to-feed ratio control drift, and from aging infrastructure in sulfur storage and piping systems are frequent issues in operating SRUs. Each has a distinct root cause and requires a different engineering response.
How do engineers optimize SRU performance?
Optimization typically starts with a performance assessment to compare actual sulfur recovery efficiency against the unit’s design basis, evaluate catalyst activity and review the accuracy of air demand control instrumentation. The findings determine whether the fix is operational, mechanical or a combination of both.
When should an SRU be revamped rather than repaired?
When the unit’s design basis no longer matches current operating requirements in terms of capacity, feed composition or emissions compliance, continued repairs address symptoms without solving the underlying problem. A revamp assessment evaluates whether targeted modifications can close that gap or whether the unit needs to be re-engineered.
Paul Evans, PE
Process Engineering Manager
Paul Evans is JEPCO’s process engineering manager and a licensed professional engineer with broad experience in refining operations, mining and mineral processing, alternative fuels and chemicals. His work spans renewable diesel plants, feed pretreatment units, flare gas recovery systems and debottlenecking projects, with core expertise in process modeling, heat and material balancing, pressure relief systems and CFD modeling.
Steve Gates
Senior Staff Process Engineer
Steve Gates is a senior staff process engineer at JEPCO with nearly four decades of experience in gas processing, upstream facilities and refining. His specialties include sulfur recovery unit engineering, process analysis and brownfield project execution, and he presented “On-Line Replacement of a Below-Grade Steel Sulfur Tank” at the 2019 Brimstone Sulfur Symposium in Vail.
