5 Reasons Why Performance Evaluations are Essential for Your Processing Units
Annual health checks for Sulfur Recovery Units (SRU) and Amine Units have become an industry standard, ensuring operational performance and reliability form ongoing operations and before scheduled turnarounds.
1-Establishing Baseline Performance
Baseline performance data is crucial for assessing the current state of SRUs and Amine Units. This data acts as a reference point, allowing operators to detect deviations from normal operations. Without a baseline, identifying specific issues becomes challenging, leading to extended downtime and increased maintenance costs.
2-Early Detection of Issues
Regular health checks enable early identification of operational inefficiencies, potential corrosion, contamination, fouling, and other issues. Catching these problems early helps prevent them from escalating into costly shutdowns or safety incidents.
3-Optimization Opportunities
By regularly analyzing system performance, SRE’s health checks reveal optimization opportunities. This could involve setting new operating parameters, fine-tuning the amine circulation rates, or adjusting the temperatures within the SRU. These improvements can lead to better recovery rates, lower emissions, and reduced energy consumption.
4-Supporting Turnaround Planning
Comprehensive health checks provide valuable data for planning turnarounds. Knowing the condition of equipment and potential trouble areas allows for precise scheduling and resource allocation, minimizing downtime and optimizing repair efforts.
5-Ensuring Compliance and Safety
In industries dealing with hazardous materials like H2S, safety is paramount. SRE’s rigorous safety protocols, including the use of SCBAs and trained engineers for sample collection, ensure that all health checks comply with the highest safety standards, protecting personnel and the environment.
Sulfur Recovery Engineering (SRE) offers comprehensive health check services that go beyond routine maintenance, establishing baseline performance, pinpointing optimization opportunities, and identifying potential issues early to avoid costly unscheduled and emergency shutdowns.
Book your Performance Evaluation with SRE today
From Fuel to Fines: Key Operating Costs in Sulfur Recovery Units
Managing a Sulfur Recovery Unit (SRU) involves more than just initial setup costs; it encompasses a spectrum of ongoing expenses that can significantly impact operational efficiency and regulatory compliance. Let's delve into the breakdown of these costs based on a recent YouTube transcript, categorizing them into three main areas: operating costs, maintenance costs, and emergency costs.
1. Operating Costs
Operating costs are fundamental to day-to-day SRU functionality and include:
Fuel Gas: Used in incinerators, thermal oxidizers, and other processes to convert sulfur compounds into SO2. Costs can vary based on the type and availability of gas.
Hydrogen: Essential for hydrogenation reactors and other units. While using on-site hydrogen can save on procurement costs, it may contain contaminants that reduce catalyst lifespan.
CO2 Emissions: Many jurisdictions impose costs per ton of carbon emitted, impacting overall operational expenses.
2. Maintenance Costs
Maintenance ensures the longevity and efficiency of SRU components:
Catalysts: Crucial for sulfur conversion, with costs varying by type (e.g., Illumina, Titania) and lifespan (typically 4-6 years).
Condenser Tube Sheet Failures: Result from improper thermal management during startups and shutdowns, potentially costing upwards of five figures to repair.
Refractory Damage: Repair costs can escalate dramatically if damaged during a runaway fire.
Plugged Rundown Lines: Costs can arise from unplugging lines, especially if external assistance is required.
Performance Evaluations: Conducted periodically to optimize SRU operations, typically costing around $35,000 per evaluation for comprehensive assessments.
3. Emergency Costs
Emergencies can lead to severe financial repercussions and regulatory penalties:
Regulatory Fines: Non-compliance fines can be substantial, sometimes reaching millions, depending on the severity of emissions violations.
Production Losses: SRU downtime can incur significant daily losses, ranging from $100,000 to over $1 million, highlighting the criticality of swift troubleshooting and repair.
Consent Decrees: Regulatory mandates may require frequent performance evaluations, increasing operational costs.
The operation of SRUs involves meticulous cost management across various fronts. From daily operational expenditures to mitigating potential emergencies and regulatory fines, understanding and planning for these costs are critical for maintaining operational reliability and compliance. By proactively addressing these cost factors, refineries and gas plants can optimize their SRU operations and ensure sustainable performance in the face of regulatory scrutiny and operational challenges.
Understanding these nuances not only helps in budgeting effectively but also in strategizing long-term operational excellence and compliance within the dynamic landscape of sulfur recovery management.
Case Study: Troubleshooting Decrease in Recovery Efficiency
Problem Identification
An existing client brought SRE in to troubleshoot an unexplained decrease in recovery efficiency within their Sulfur Recovery Unit (SRU). The plant had three SRU trains and had been experiencing high H2S levels in the product from the downstream degassing operation.
Steps Taken to Address the Problem
1-Initial Compositional Analysis:
SRE performed a compositional analysis of the process gas and found low conversion across Converter 2.
The SRU was generally well-operated, and no significant changes had occurred since the last test period.
2-Simulation and Catalyst Activity:
Simulations reconfirmed that the catalyst activity in the second converter bed was lower than expected.
Despite the catalyst being replaced only six months prior, the sudden reduction in efficiency was puzzling.
3-Inlet Temperature and Sample Testing:
Further analysis revealed that the converter inlet temperature was above the normal recommendation.
SRE installed a sample probe at the inlet, discovering a different gas composition than at the converter one outlet.
4-Identifying a Leak:
The analysis suggested a hole in the multipass condenser, allowing process gas from the first pass to contaminate the second pass.
This leakage explained the reduced conversion efficiency and increased inlet temperature at Converter 2.
5-Degassing Operation Review:
Before the client shut down to repair the condenser leak, SRE evaluated the degassing pits to understand why H2S levels were up to 200 ppm in the liquid sulfur.
Adjustments to the agitator and pump circulation rates were tested. It was found that the circulation rate was too low for adequate degassing.
One of the two sulfur pumps was found to be barely operational and required a complete overhaul.
6-Repair and Validation:
The condenser and pump repairs were scheduled during a planned shutdown.
SRE assisted with the shutdown and subsequent startup, performing tests to verify the effectiveness of the repairs.
Post-repair tests confirmed that recovery efficiency improved to above the license limit of 98%, and H2S levels in the liquid sulfur returned to specification.
Summary of Findings and Benefits
Operational Improvements: Quick identification and repair of the multipass condenser leak and the sulfur pump issues restored the plant's efficiency.
Financial Savings: Early detection and repair prevented further damage to the SRU and avoided substantial costs associated with contaminated product.
Product Quality: Restored liquid sulfur to meet H2S specifications, ensuring high-quality output.
This case study illustrates SRE's proficiency in diagnosing and resolving complex SRU issues efficiently. By identifying and repairing leaks and optimizing degassing operations, SRE restored the client's recovery efficiency and product quality. Other companies can benefit from SRE's thorough approach and expertise in maintaining and improving SRU operations, avoiding potential downtimes and financial losses.
Speak with an SRU Specialist
7 SRU Catalyst Killers: Identifying and Mitigating Contaminants in Sulfur Recovery Units
Catalysts are the heart of the sulfur recovery process, crucial for ensuring high efficiency and low emissions. However, various contaminants can deactive and damage these catalysts, leading to reduced performance and increased operational costs. This article explores the primary contaminants, their mechanisms, and methods for mitigation, alongside the financial impact of catalyst misuse.
Catalysts in sulfur recovery units (SRUs) facilitate the conversion of hydrogen sulfide (H2S) into elemental sulfur. Over time, contaminants can deactive these catalysts, impacting their effectiveness and lifespan. Identifying and understanding these contaminants is critical for maintaining optimal performance.
Major Contaminants and Their Impact
1- BTEX (Benzene, Toluene, Ethylbenzene, Xylene)
Mechanism: BTEX components are not fully destroyed in the reaction furnace (RF) and polymerize on the Claus catalyst.
Deactivation Type: Permanent.
Mitigation: Ensure complete destruction in the RF, maintain correct temperatures, and monitor BTEX levels in the feed.
2-Methanol
Mechanism: Methanol bypasses the RF via an acid gas bypass, leading to polymerization on the catalyst.
Deactivation Type: Permanent.
Mitigation: Properly control bypass systems and monitor methanol concentrations.
3-Soot and Liquid Sulfur Deposition
Mechanism: Incomplete combustion during startup or improper burner stoichiometry leads to soot formation, plugging converter beds.
Deactivation Type: Temporary.
Regeneration: Heat soak.
Mitigation: Optimize startup procedures and maintain burner efficiency.
4-Sulfation
Mechanism: Excessive free oxygen from the RF or reheaters causes sulfation of the catalyst.
Deactivation Type: Permanent.
Mitigation: Control oxygen levels and ensure proper operation of reheaters.
5- Steam (Hydrothermal Aging)
Mechanism: Long-term exposure to excessive water vapor leads to structural damage.
Deactivation Type: Permanent.
Mitigation: Minimize steam introduction and prevent boiler leaks.
6-Thermal Aging
Mechanism: High temperatures during sulfur fires cause catalyst sintering.
Deactivation Type: Permanent.
Mitigation: Avoid thermal excursions and maintain safe operational temperatures.
7-Heavy Hydrocarbons
Mechanism: Heavy hydrocarbons crack and form coke, blocking catalyst pores.
Deactivation Type: Permanent.
Mitigation: Optimize feedstock composition and prevent heavy hydrocarbon carryover
Avoiding Contamination
Preventing catalyst contamination involves maintaining strict operational controls and regular monitoring:
Ensure proper destruction of contaminants in the RF.
Control bypass systems to prevent methanol and heavy hydrocarbons from entering the catalyst beds.
Optimize startup and shutdown procedures to minimize soot formation.
Maintain proper temperatures to avoid sulfur condensation.
Regularly inspect and repair boiler systems to prevent hydrothermal aging.
Avoid thermal excursions by controlling process temperatures and preventing sulfur fires.
Financial Impact of Catalyst Misuse
Catalyst deactivation leads to significant financial burdens due to reduced efficiency, increased maintenance costs, and potential unscheduled shutdowns. Misuse can result in:
Increased operational costs due to frequent catalyst replacements.
Higher energy consumption and lower process efficiency.
Downtime for maintenance and catalyst regeneration or replacement.
How We Can Help: Performance Testing and Optimization
Sulfur Recovery Engineering (SRE) offers comprehensive performance testing and optimization services. Our experts can:
Conduct thorough assessments to identify contamination sources.
Provide tailored solutions to prevent and mitigate catalyst deactivation.
Offer regular monitoring and maintenance programs to ensure long-term efficiency and reliability.
Protect your catalysts and ensure optimal performance of your sulfur recovery units. Contact SRE today to schedule a consultation and learn how we can help you maintain peak efficiency and minimize operational costs.
The Heat Is On! – Why Temperature Plays an Important Role in Sulfur Recovery
The iconic skyline of Alberta’s natural gas sector is marked by labyrinthine tubes and tunnels, pipes and platforms. Atop it all—like candles on the cakes of carbon—are sputters of live flame, alighting the morning sky.
Far more than just a deterrent to low-flying aircrafts (and birds), the powerful heat of the reaction furnace ensures sulfur extraction is maximized, and the purity of outflow is an optimal makeup for cleanliness and machine reliability.
Too Hot to Handle:
Working with sour water means bringing all the good along with the bad. Side reactions inside the reaction furnace will invariably produce unwanted products like CO, H2, COS, and CS2. Luckily, other contaminants such as BTEX, Mercaptans, NH3, HCN, Methanol, and HCs may be destroyed in the reaction furnace with proper calibration and sufficient heat.
While 900℃ (1650℉) is the minimum temperature for flame stability, heats of 1050℃ (1920℉) or above are capable of destroying the unwanted contaminants. Bear in mind the reaction furnace is kinetically limited based on residence time, turbulence, and temperature, as well as burner efficiency.
Through the Fire and Flames:
In our Sulfur Recovery experience, combustion air flow rates are nearly always off by at least 10–20%. While this is standard, we must work to ensure this margin of possible error is not exacerbated. Proper mixture of gasses and the installation of a high-efficiency burner can increase reaction furnace temperatures up to 100℃, which helps to reach the target temperatures mentioned previously.
This is crucial not only for efficiency, but for optimal refinery health. Proper burn-off of ammonia in the reaction furnace is essential, as residuals can carry over to the condensers and converters, bringing with them the risk of forming ammonia salts. These salts will negatively impact heat transfer and recovery efficiency. As with most sulfur recovery unit issues, you won’t know there is a problem until it is too late.
As with any efficient furnace system, management of both inflow and output should be carefully monitored, with changes to procedure made according to the changes in both. Ensure your plant is optimized for the feed it receives. For example, when H2S qualities are low in gas plants, a front side split configuration is often best for ensuring minimal additions of air and nitrogen to the system.
Conclusion:
Sulfur recovery isn’t always easy, but it is undoubtedly important. In the end, you should run your reaction furnace like you would your bathtub: the hotter, the better; the better, the cleaner! Learn more about how we can help you optimize your Sulfur Recovery by contacting us at our website, subscribing to our newsletter, or by giving us a call today.
Breakdown: Claus Processing Units
Today we will be breaking down the different components of Claus Processing Units. Let’s take a look at each component and some best practices to guide you as you consider your own operations.
Reaction Furnace
This is the first unit in the Sulfur Recovery Unit (SRU) process where feed enters and where thermal combustion happens. Most of the heat is produced in this section due to the highly exothermic reaction (H2S is burned using oxygen to produce desired amount of SO2). The inner walls of the reaction furnace are lined with refractory bricks to protect the shell of the vessel from the extreme heat.
Wasteheat Boilers
The wasteheat boiler is attached to the back of the reaction furnace. This is where most of the heat removal takes place. These boilers are available in either a one-pass or two-pass design. A two-pass is used when there is a hot gas bypass already in place. By sending hot, processed gas to the first converter, the tube sheet is protected from high temperatures and sulphite attacks. When it comes to removing heat, the waste heat boiler is your friend— just let that hot steam rise to the top!
Claus Process Condenser
The Claus process condenser is an excellent shell and tube heat exchanger. Its function is to remove sulfur and heat. It separates gas and the liquid leads into your liquid-sulfur run downs. It maintains an outwards temperature in the range of 150°C to 165°C to minimize the sulfur vapour carry-over to the incinerator. Any higher than that and things might get frenetic! Keep in mind that condensers achieve low pressure steam production — 50 psig. Use this steam in heat tracing, as desired. That steam is produced on the shell side, with sulfur product on the tube side.
Reheater
Reheaters play a crucial role in maintaining sulfur temperature and avoiding condensation in the converters. Remember that processed gas leaves the condenser at the sulfur dew point temperature. This temperature must be increased. This increase provides optimal temperature for the Claus reaction in the gas phase and on to the converters.
Although two reheating methods exist, one is clearly superior. The direct reheating method is less desirable, as it adds additional sulfur bearing compounds to the process; this immediately lowers the overall practicable efficiency of the SRU. Moreover, between 0.1-0.5 % loss of sulfur can occur through this method.
Indirect heating is preferred for this reason. Harnessing the mighty power of steam, no added compounds can crawl through the pipes and into your end product. Simple to control and with no effect on overall practicable efficiency, indirect heating is the industry gold standard. Cost issues may arise, however, as some refineries see steam costing up to $5 per ton. The key point here is to focus on maintaining a 2:1 H2S to SO2 ratio.
Whatever the method, once converted and reheated the sulfur moves to the catalytic converter stage and incineration stage.
Catalytic Converter , Thermal Incinerators and Instrumentation
The catalytic reaction occurs at this stage. Through an exothermic reaction, heat is released, and the temperature begins to rise in the catalyst bed. Temperature control, as always, remains critical. Here, Claus reaction is favoured at lower temperatures. We want the processed gas to be in the gas phase.
Once catalyzed the thermal incinerator comes into play by converting the remaining off gas into SO2. The temperature of your incinerator should not exceed 650°C. Keep in mind that this is controlled by the amount of fuel gas and air being burned. Be sure to monitor SO2 concentrations at ground level for proper plume dispersion. Instrumentation can help monitor oxygen levels within a 2-4% range, but they are not always accurate. Make sure you understand the normal base conditions to avoid excess temperatures and any accidents.
We hope this blog was informative to you and your Claus Processing Unit aspirations. Follow our blog for more pertinent and useful updates in the field of sulfur recovery.
The Importance of High Quality SRU Feed Streams
The SRU is only as good as the feed streams it receives – this is a common statement in the sulfur recovery industry. Before testing
The SRU is only as good as the feed streams it receives – this is a common statement in the sulfur recovery industry. Before testing an SRU, one of the first questions we ask is “how stable is the acid gas flow”? And after analyzing the samples, one of the first things we check is the acid gas quality, i.e., the H2S content, as well as the concentrations of contaminants in the feed stream(s).
The reaction furnace (RF) is the first vessel and considered the ‘heart’ of the SRU. Its performance is based largely on the quality of feed stream(s) it is processing, whether it be only Amine Acid Gas (AAG), or the additional Sour Water Stripper Acid Gas (SWS AG) often processed in refineries. The H2S content affects how hot the RF can run, and the higher the better; it also dictates which configuration can be utilized, whether it be straight through, split-flow, or direct oxidization.
The concentrations of contaminants, mainly hydrocarbons and BTEX, is also important for the RF performance. For their complete oxidization, hydrocarbons require much more oxygen than H2S does; this negatively impacts the smooth operation of the Air Demand signal. Hydrocarbons and BTEX also cause various issues downstream if they are not completely oxidized, therefore keeping their levels at a minimum is vital. Maintaining stable and consistent feed stream flows is also crucial for the smooth operation of the Air Demand control loop.
Optimizing the operation of upstream Amine and Sour Water units is vital for providing the SRU with the highest possible quality feed streams, and for minimizing the levels of contaminants. SRE now offers full Amine Unit Performance Evaluations, along with the SRU testing we’re known for. Our highly trained team of engineers can safely obtain these hazardous samples, and our optimization programs make the sour units achieve the highest efficiencies they were designed for.
Sulfur Pit Degassing
Why do we degas? Crude oil and natural gas contain sulfur compounds which get concentrated as they makes their way to the SRU in the
Why do we degas? Crude oil and natural gas contain sulfur compounds which get concentrated as they makes their way to the SRU in the form of hydrogen sulfide (H2S). H2S is present in liquid sulfur in two forms: dissolved and chemically bound (known as polysulfides or H2Sx). The residual H2S content in produced liquid sulfur can be in excess of 600 ppm and the Lower Explosive Limit (LEL) for H2S in air is 4% which is easily reached if liquid sulfur is not degassed. The main goal then of degassing is to reduce the potential safety risk to people, the environment, and equipment. Increasing product purity may also be a reason for degassing to lower levels. The industry standard for safe handling of sulfur product is 10 ppm or less.
Degassing typically consists of two stages, an agitation stage followed by a sweeping stage. Air is typically used in both stages as it is readily available and cheap, oxygen also promotes the direct oxidation of hydrogen sulfide and polysulfides. That being said, other gasses such as nitrogen, steam, and Claus tail gasses can also be used for sweeping the released H2S from the pit.
There are several processes that can be seen in industry and that have been implemented around the world. It is likely that if you have worked in a sulfur plant that you have experience with one or more of these processes.
Comprimo (Formerly Exxon) Degassing Process
Air used for sparging and sweeping
Catalyst added to pit to promote decomposition of polysulfides
Aquisulf (SNEA)
Aquisulf catalyst
Multiple compartments
Shell
Uses air for agitation
Stripping column within the pit
Enersul HySPEC
Series of CSTRs (Continuous Stirred Tank Reactors)
Air used to sweep and catalyst added
Fluor D’GAASS
Pressurized above-ground contactor
Air used for agitation
CSI ICOn
Fixed catalyst bed contactor before or after pit
Operates at pressure of SRU
Finally, we’ll talk about operation and troubleshooting fundamentals. Knowing the basics of degassing chemistry, such as the kinetics, effects of catalyst, and flow characteristics provide a solid foundation for any issues that you may encounter. The next step is knowing your design, understanding how your particular process works compared to others is necessary to being able to identify problem areas. Lastly, ensure that your data is accurate and reliable when monitoring KPIs. To help with this, get onsite verification of your process, including fact checks of technical drawings and data, and liquid sulfur testing.
Reach out to us at SRE for more information on troubleshooting tips and support as well as some interesting case studies from our experience.
IMPROVE SAFETY, INCREASE RELIABILITY, & REDUCE COSTS
Traditional vs. Above Ground Sulfur Seal Legs
While catalytic converters perform the sulfur conversion portion of the modified Claus unit, sulfur condensers allow for the recovery of that sulfur in a liquid state.
While catalytic converters perform the sulfur conversion portion of the modified Claus unit, sulfur condensers allow for the recovery of that sulfur in a liquid state. After the sulfur is condensed from a vapor to a liquid, it drains through a gravity rundown system into the temporary sulfur storage pit, or collection vessel. At the beginning of the sulfur rundown system, the liquid side must be sealed off from the vapor side to prevent process gas from escaping with the liquid sulfur. The two types of sulfur sealing mechanisms are the traditional underground seal leg, and the increasingly common above-ground sulfur seal. Both types have their strengths and weaknesses.
The traditional underground (in-ground) sulfur seal leg has been used in SRUs for over 50 years. These depend on the head pressure of a liquid sulfur level within the vertical leg to act as a vapor seal and block the process gas. Traditional seal legs function well during normal operation, but in the event of a pressure spike they may cause process gas to blow out and into sulfur storage. While supplemental gas relief can sometimes be desirable, this gas contains hazardous H2S and SO2, and will continue to enter the sulfur pit until the leg is refilled with liquid sulfur. In addition to this, underground seal legs are also cumbersome to remove in the event of plugging off.
Above ground sulfur seals have been around since the 1990s, they utilize a float and orifice to create a vapor seal, similar to a float steam trap. These seals do not allow process gas to enter sulfur storage, because any pressure event will immediately close off the orifice. There is, therefore, no supplemental relief path in these original above-ground designs. While being much easier for maintenance and accessibility, the original design does require periodic cleaning of the filter screen. CSI has, however, developed an advanced version of the above-ground seal which addresses the perceived weaknesses of the original design, called the SxSealTM 2000. This sulfur seal has been very well received and allows for both supplemental pressure relief and simple clean-out without having to open it up and remove a screen. While some companies can be reluctant to deviate from traditional methods, advancing technology will always provide means of improvement, thereby reducing safety hazards and increasing operational effectiveness and ease-of-use.
KPIs for the SRU
Sulfur Recovery Engineering (SRE) clients often ask about Key Performance Indicators for their Sulfur Recovery Units.
It is difficult to identify KPIs for the SRU without compositional analysis and feed stream data. If you think about it, the data that you see from the DCS – flows, temperatures and air demand analyzer (ADA) info – are all directly related to what is actually coming into the SRU.
Sulfur Recovery Engineering (SRE) clients often ask about Key Performance Indicators for their Sulfur Recovery Units.
It is difficult to identify KPIs for the SRU without compositional analysis and feed stream data. If you think about it, the data that you see from the DCS – flows, temperatures and air demand analyzer (ADA) info – are all directly related to what is actually coming into the SRU.
Things to look at are inlet flows to the SRU, temperature differentials across the catalytic converters, and the concentrations reported by your tail gas analyzer. It is important to note that these data points are dependent on the compositional analysis of feed streams. SRE can provide our clients with this analysis, and recommends that a Performance Evaluation and Optimization be conducted periodically as part of any SRU routine maintenance program.
If your crude or gas wells change frequently, it is recommended that feed streams are tested more regularly as operating parameters may need to be adapted in order to compensate for varying acid gas quality or contaminants. For example, if the H2S content in the amine acid gas drops significantly (i.e. a drop in sulfur loading) then the combustion air requirements, the converter bed temperature profile, and the measured ADA concentrations will all change as well.
In a refinery, it is important to do regular sampling of both the amine acid gas and the sour water stripper acid gas to determine their respective compositional analysis, especially if the source of crude supplying the refinery is constantly changing. Some SRE clients have us come to site and conduct this analysis on a quarterly basis.
Here is the short list of SRU KPIs to monitor for performance and optimization that we consider important:
Flow rates of the amine acid gas, sour water stripper acid gas and air (main, trim and total) to the SRU;
Amine Acid Gas H2S, CO2, & hydrocarbons content;
Sour Water Stripper Acid Gas, Ammonia (NH3), H2S, H2O content;
Differential temperature across the first and second converter (i.e. the maximum bottom bed temperature of the converter minus the outlet temperature from the reheater);
H2S and SO2 concentrations from the ADA;
Stack Emissions.
Regular reviews of your SOPs, PMO plan and other operating manuals will ensure that you are up to date with the most efficient operating procedures.