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 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.  

Hydrocarbon Present in Amine Solvent Downstream of Absorber

Problem Definition

A South American Refinery Client requested assistance tackling the problem of hydrocarbon being present in their amine solvent (rich amine). The client reported an incidence of hydrocarbon in their acid gas stream going to SRU. They are looking into putting a flash tank in service for the amine circuit and require SRE’s analysis to determine prime location, operation guidelines, and instrumentation required. There was an existing flash tank and was put out of service long ago, the tank was designed as a charge drum for amine system. P&ID of the amine circuit was provided (flash tank situated after the lean-rich amine heat exchanger) along with their current option.

SRE’s Response

Within a couple of days of receiving the request, SRE reviewed the P&ID and information provided by the client to present the recommendations. Flash drum should be installed after the absorber, and before the lean-rich amine heat-exchanger, to ensure Hydrocarbon is condensed and a significant amount of H₂S is NOT flashed. As per industry practice, absorbers operating below 10 bar usually do not require a flash drum. It was advised to the client to further investigate the event of hydrocarbon carryover to ensure there is no permanent damage to the amine circuit/equipment.

A write-up was sent to the client explaining where the flash drum should be installed and what the limitations will be. In addition, operation guidelines and instrumentation requirements were also presented to the client. For the short term, the client was advised to ensure that the amine inlet separator is functioning well, and that extra precautions are taken to stop hydrocarbon from entering the amine circuit.

RESULTS

The client was fully onboarded with SRE’s recommendations. They will strive to ensure that the flash drum will be installed upstream of lean-rich amine heat-exchanger and that proper instrumentation will be used. Operation guidelines have been provided to the client and will be further refined as the need arises.

SRE continues to provide support to this client as they are in the process of the modifications.

Solids Contamination

Problem Definition

European Refinery Client requested assistance with solids contamination in their DEA system. Corrosion issues in the regenerator bottom section and reboiler were reported. Amine analysis results were sent to SRE for review.

SRE’s Response – Solids contamination

Within one hour of receiving the request, SRE provided review of DEA analysis results and reported to the client that Heat Stable Amine Salt (HSAS) levels were considerably higher than maximum guideline level of 2 weight percent and were the probable cause of corrosion in the regenerator and reboiler.

The contamination in the system was the result of high corrosion rates found in the unit. A report on HSAS management was sent to the client. Additional guidance was provided to the client on short-term mitigation of HSAS using neutralization to immediately reduce the corrosion problem.

RESULTS

Using SRE’s guidelines, the client was able to reduce HSAS to an acceptable level. Solids contamination and corrosion rates were reduced.

SRE continues to provide assistance to this client to maintain the unit within guidelines for HSAS, solids and corrosion.

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 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.

1. Comprimo (Formerly Exxon) Degassing Process

   • Air used for sparging and sweeping

   • Catalyst added to pit to promote decomposition of polysulfides

2. Aquisulf (SNEA)

   • Aquisulf catalyst

   • Multiple compartments

3. Shell

   • Uses air for agitation

   • Stripping column within the pit

4. Enersul HySPEC

   • Series of CSTRs (Continuous Stirred Tank Reactors)

   • Air used to sweep and catalyst added

5. Fluor D’GAASS

   • Pressurized above-ground contactor

   • Air used for agitation

6. 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.  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.

Trace Oxygen in Raw Gas To Determine Corrosion Source

Q4 2017 saw SRE complete a number of interesting projects.  For one gas plant in Canada, SRE was involved with determining the source of corrosion with our client’s gas sweetening unit.  In an amine system, corrosion problems can easily be identified by the color of the amine: pale green indicating light corrosion; brown indicating corrosion greater than the filtration capabilities; and black indicating dangerous levels.  Although there are many sources for corrosion, our client had already identified that their corrosion was most likely cause by an increased amount of Bicine.

There are several mechanisms for producing bicine in amine gas treating facilities which include (1) reaction of diethanolamine (DEA) with glyoxal – a common hydrogen sulfide (H2S) scavenger – and (2) exposure of the heated gas treating solution to an oxidizer. Bicine impacts gas treating amine solutions in two ways. First, it forms heat stable amine salts (HSAS) and second, it increases the corrosivity of the amine solution.  Here, it was thought that the oxidizer was Oxygen (O2) ingress from the field raw gas.

As such, SRE’s scope of work was to complete trace O2 analyses at various points through the gas plant, including the raw gas from each field and throughout the inlet lines to the Amine contactors.  In one day, SRE conducted 22 trace O2 measurements from 10 different locations.  Sampling was extensive as a 3-minutes sample time and portable equipment allowed the site Engineer to be able to request extra measurements for due diligence.  These capabilities are in stark contrast to a trailer full of equipment and a 2-hour run time – 1 hour to mobilize, 30 minutes to warm up line and 30 minutes to conduct analysis – used by other testing companies, where 22 samples could take a few days & cost 3 times more.

Results ranged from 20 ppm to 250 ppm with all raw gas inlets having a measurable amount of O2.  The site Engineer planned to use the data to conduct their own material balance and to continue to mitigate the amine system corrosion.

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.

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:

1. Flow rates of the amine acid gas, sour water stripper acid gas and air (main, trim and total) to the SRU;

2. Amine Acid Gas H2S, CO2, & hydrocarbons content;

3. Sour Water Stripper Acid Gas, Ammonia (NH3), H2S, H2O content;

4. 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);

5. H2S and SO2 concentrations from the ADA;

6. 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.

Troubleshooting SRU Feed Streams

“The SRU is only as good as what it receives in terms of amine acid gas and SWS acid gas”.

When evaluating the performance of an SRU, the first things to check are the feed stream quality and consistency. Since the SRU is only as good as what it receives, there are many potential areas for troubleshooting with regards to upsets with the feed stream units. All SRUs have an Amine Acid Gas feed stream, and many refineries have an additional Sour Water Stripper Acid Gas feed stream. The first indication that there maybe an issue with your feed streams is swings within your air demand signal. Large and uncontrollable swings in the combustion air demand signal occur due to fluctuations in the acid gas feed stream compositions and flow rates. Typically, when these fluctuate by more than 10%, the Air Demand Signal will fall outside of the optimal range and result in an immediate loss in recovery efficiency.

While plant swings can be unpredictable, they can be prepared for, new gas streams should be introduced slowly for a smoother transition. This can, for example, give the ADA time to adjust to the changing H2S content in the feed stream. Plant upsets can never be fully eliminated, so the SRU instrumentation must be regularly calibrated in order to be prepared for feed stream swings. Full performance testing of the upstream amine and SWS units is the best way to optimize performance and minimize swings in the feed stream compositions and flows.

Another common issue with SRU feed streams is when they have high hydrocarbon contents. Hydrocarbons require much more oxygen to oxidize in the reaction furnace, which throws off the air demand. Also, more hydrocarbons means more CS2 production, which will hurt the recovery efficiency if it isn’t hydrolyzed. If sufficient amounts of hydrocarbon make it into the converters, catalyst poisoning will occur and deactivate the catalyst.

Excessive accumulation of hydrocarbons in the feed streams can be due to:

Over circulation of amine, or amine temperatures falling below inlet gas temperatures, which results in HC condensation.

Insufficient flash tank residence time or skimming operation can also increase hydrocarbons in the amine or SWS acid gas. The same goes for the reflux drum.

Sometimes the Reflux Drum purge rate is too low, or sometimes the pump does not start, resulting in LPG carryover to the RF.

High levels of other contaminants can be problematic as well; BTEX, mercaptans, and methanol are all catalyst poisoning compounds that should be kept below threshold levels in order to ensure their full destruction in the reaction furnace. High CO2 contents will increase COS production and reduce efficiency if not fully hydrolyzed in the first converter.

The best way to minimize contaminants in the feed streams is to perform regular maintenance, testing, and optimization of the amine and sour water units.

Troubleshooting Converter Issues

If the temperature rise across a converter is observed to be lessening, this indicates that deactivation is occurring.  This phenomena may be accompanied by an increase in the temperature rise in the downstream Converter since it now has to do ‘more work’.  We also need to be aware of an increase in the RF pressure, which may indicate that one of the Converters has gone ‘sub-dewpoint’ and is plugging off due to liquid sulfur.

There are a number of mechanisms that can cause catalyst deactivation.  They include BTEX and methanol poisoning, sulfation, carbon fouling, hydrothermal ageing,  and normal ageing.

•  BTEX poisoning occurs when the RF is unable to completely destroy BTEX components in the acid gas feed stream(s) to the SRU. The resulting effect is a ‘cracking’ or ‘polymerizing’ of these components on the Claus catalyst.

• Methanol poisoning is normally due to an SRU with an acid gas by-pass that allows methanol to by-pass the RF.  Both of these poisoning mechanisms are permanent.

• Soot deposition and liquid sulfur deposition on the top of the catalyst, results in plugging of the converter beds, but these can be reversible with a heat soak.

• Sulfation of catalyst occurs when excessive free oxygen is carried over from either the RF or direct-fired reheaters.

• Hydrothermal ageing results when the catalyst is exposed to excessive amounts of water vapor over a long period of time.  Although the actual physical mechanism is still not completely understood, it can occur when either excessive steam is introduced into the process and may also occur due to serious tube or tubesheet leaks (BFW being on the shell side) from the Wasteheat boiler or Condensers.

• Thermal ageing is caused by ‘thermal excursions’ or ‘sulfur fires’ in the catalyst beds. Temperatures above 1300 F, which are all too easy to obtain during a serious sulfur fire, can result in ‘fusing’ of the catalyst into large solid pieces.

Other converter issues:

• Exposure to large amounts of condensed water will result in immediate destruction of the catalyst pellets.

• If there is a sudden step-change reduction in the temperature rise across the first Converter, this would indicate that a severe carryover of contaminants such as hydrocarbons and/or amine has occurred.

• A sudden increase in temperature in the Converters will be due to a ‘sulfur fire’.  This means that there is free oxygen getting to the Converters either from the RF and/or the Reheaters. If the problem is not corrected quickly, it will be necessary to introduce ‘snuffing steam’ or an inert gas to stop the fire.  Do not allow the temperatures to go above 1400F in the Converters or there will be severe damage done to the internals.

• Damage in the Converter internals normally shows up as a failure in the catalyst supporting mesh screen and grating, which will result in catalyst falling through and ending up in the Condensers, Rundowns, and Seal Legs (often plugging is the result).  In the worst case scenario the carbon steel support beams will bow downward or collapse.

Don’t forget about your liquid sulfur.

Don’t Forget About Your Liquid Sulfur!

Upon production in the upstream Claus Condensers, liquid sulfur inevitably contains both dissolved H2S and conjugated polysulfides, H2Sx. Depending on the position of the specific Condenser in the process, the concentration of H2S bearing species in the liquid can range from 200 to 700 ppm. From a personnel safety perspective, direct exposure at these levels could be fatal!

From a product quality perspective, safety is also, obviously, the driver with respect to reliable liquid sulfur degassing operations. The presence of elevated H2S can create both a toxic and corrosive environment with respect to downstream product handling. Here, while the H2S content should be quite low, concentrated pockets can indeed develop in the sulfur holding tank and also pose a potentially serious risk to those loading trucks and rail cars. Most importantly, it should not be assumed that these individuals are experts in terms of mitigating the risks associated with H2S (i.e. knowledge of wind direction, body position, etc.)!

When an engineered degasification process is employed, the industry standard is for there to be less than 10 ppm H2S remaining in the liquid sulfur product. In the absence of any agitation, the final product should contain no more than 30 ppm. Here, these general expectations lead nicely into the following case study:

A gas processor in Western Canada, and regular SRE client, provides their liquid sulfur product to a nearby forming facility. The specific business arrangement is very simple: A processing/forming fee is charged back to the provider prior to marketing of the final, solid sulfur product. Considering the current market demand for sulfur, it is important that additional forming fees are not charged due to out-of-spec liquid sulfur.

This case study begins with the Gas Plant having received notice that liquid sulfur, recently received and subsequently sent out for analysis by the forming facility, contained elevated H2S. Furthermore, a nearby resident filed an odor complaint around the same time period. Here, SRE was contracted and immediately mobilized to begin troubleshooting this degassing issue starting the very next day!

SRE’s tailored, on-site liquid sulfur analysis provides fast and accurate results in terms of total H2S content in your liquid sulfur by utilizing a catalyst to quickly convert polysulfides back to H2S. Initial liquid sulfur samples, collected from the degassed portion of each sulfur pit, revealed that only one of the two pits (i.e. multiple sulfur trains on-site) was discharging out-of-spec liquid sulfur. Sulfur from the two pits is stored in common collection tanks, which were also determined to be out-of-spec and confirmed the results reported by the forming facility. Of important note, SRE conducted on-site liquid sulfur analyses for this same client just a year before and all results, at all locations, were well below 10 ppm.

From above, the key to this solving this problem was to determine the critical operating difference between the two degassing pits. In conjunction with SRE’s on-site liquid sulfur analyses and a formal review of previous operations (i.e. DCS data, Operator logs, etc.), the power of SRE’s proprietary Gas Chromatograph application provided the necessary insight into the issue and a path forward for the client.

With time, liquid sulfur will naturally degas. Agitation also plays a key role and works to speed up this process and, essentially, serve as a robust control to mitigate product quality-associated risks. As was previously mentioned, when an engineered degasification process is employed, the industry standard is for there to be less than 10 ppm H2S remaining in the liquid sulfur product. However, sweep air, across the top of the liquid surface in the degassing pit is required to achieve a reasonable level of H2S removal. It follows that a sweep air-related issue would negatively impact the overall the driving force, setup at the interface of the liquid sulfur level and pit’s vapor space. If we cannot remove the previously released H2S (by way of sweep air), then we can only remove so much from the liquid sulfur!

Vapor space gas samples were analyzed and clearly depicted the discrepancy amongst the two pits. Here, there was approximately five times more H2S present in the vapor space of the degassing pit in question! Reduced air velocities, measured with an anemometer at all available locations, and reduced air temperatures, specifically across the heating element near the pit’s intake, supported SRE’s Gas Chromatograph findings and subsequent conclusion of significantly reduced sweep air flow. Shortly after the troubleshooting site-visit, the client determined that a portion of the sweep air line leading to the Thermal Incinerator had collapsed and was the root cause of liquid sulfur quality challenge.

Most clients perform, at a minimum, an annual SRU Performance Evaluation. The most important take away from this case study is that the degassing process is truly an important part of the SRU, but is, typically, overlooked. By taking a more proactive approach, SRE can easily verify the performance of your degassing system while on-site conducting regularly scheduled, ‘more typical’ SRU-related service offerings. If additional, routine verification is necessary, SRE also offers a Tuned Liquid Sulfur Safety Test Kit, which is very easy for your Operations and Engineering teams to operate and utilize for more frequent analyses. In terms of protecting your facilities, personnel, and bottom line- SRE has you covered!