This video covers fundamentals of Claus process, focusing on process chemistry, design principles, and typical configurations. We'll discuss how to optimize conversion and recovery efficiency, manage key operating parameters like the H2S ratio, and implement best operating practices.


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This is the final case study, where we’ll look at a testing job from about ten years ago at a refinery, and this is still a big client of ours to this day. So upon initial sampling we found that both feed streams had above threshold amounts of higher hydrocarbons (C2-C6), indicating over-circulation in the amine unit, and inadequate skimming operation of the SWS.

The low quality feed streams (& high contaminants) caused low thermal conversions.

High h/c content caused high CS2 formation. Poor hydrolysis, leading to 1.3% combined losses. And then their ADA signal was a little wonky from the inaccurate TGA readings. They were getting just under 96% recovery efficiency, with pretty much each stage underperforming.

SRE engineers then built a simulation model of the plant on that first night of testing and were able to provide some good guidance the following day. We increased the RF co-firing for better destruction temp, we increased the converter 1 temp, while reducing converter 3’s temp. And finally we lowered the final condenser temperature to 130°C. The increased RF temperature lowered the ammonia and BTEX breakthrough and jumped the thermal conversion efficiency to 50%. Increased the converter 1 hydrolysis by nearly 10%. But, with the increased co-firing rates came elevated gas mass velocities in the condensers, this increases the risk of liquid sulfur carryover to the next stages. Therefore, it was recommended that all the tubesheet blanks be removed to bring the velocities back down to normal. And, since the CS2 formation was still high, we recommended they review the circulation rates in the amine unit and the skimming operation of the SWS unit to attempt to reduce hydrocarbons and BTEX to the SRU.

So when we returned for the next set of quarterly testing, we found a much more accurate TGA, both feed streams were more optimized with less hydrocarbons, and the mass velocities dropped down into the normal range because they removed the tube blanks. This performance test, along with an incinerator optimization study, boosted the client’s recovery efficiency to well above the license, it improved the upstream unit’s operation, and the catalyst life was increased. This granted them huge savings in maintenance and fines, and greatly reduced their greenhouse gas emissions. It ended up being one of many examples of why testing and optimizing an SRU is often much more beneficial than some people might think.

And that brings us to the end of this webinar. Thank you for attending, and if you liked this presentation – consider looking into our on-site training, where we can send an engineer to your location to provide a wide range of courses regarding SRU’s and amine sweetening units. There is just one cost per course, not per person. So now I will take the time to answer any of your questions.

From there we will move onto some of the specific issues that can happen with the reaction furnace, starting with the instrumentation.

• Failures of the flame scanners is often due to the lens being coated with sulfur, soot, condensation, or corrosion products. All of this can be avoided with a properly set up purge system. If the purge systems do not have a rotameter for measuring flow then the purge air flow must be proven via another means. Flame scanners are a crucial safety element for the BMS. And also igniters are critical for safe start-ups and shutdowns, so there should be extras kept on-site.

• Fuel gas lines are not used often, so the system should be completely checked out before attempting any start-up or shutdown. Typical problems include plugged lines from moisture and corrosion. Having the fuel metered is highly recommended for safety and for historical records

• Failures in the optical pyrometers is normally due to the lens being coated, which can be rectified by ensuring that there is adequate flow of the purge air followed by a cleaning of the lens

• Ceramic encased thermowells must have a N2 purge to ensure that the corrosive gases from the RF do not penetrate the inner ceramic. This purge must be 3 to 5 psig higher than the pressure in the RF

• Proper air purges must be conducted before each attempt at a startup. If this is not performed, an explosion can occur within the RF- which can damage the main burner and checker wall

• Main Burner damage can be caused by burn-back due to low acid gas or fuel gas flow rates, corrosion, vibration, and plugging. All BMS logic should contain low flow shutdowns for both fuel and acid gas. Hydrocarbon carryover from the amine unit can cause fouling of the vanes and jets which can lead to plugging and vibration problems

• It is important that the Reaction Furnace rain shield is intact so that corrosion does not occur to the carbon steel shell

And this is what severe burner damage looks like, we can see that not only has the refractory lining eroded but also the burner shape itself has deformed. Operating the reaction furnace with a burner like this will create uneven mixing within the chamber and result in cold spots.

And that will bring us to reheaters

• Indirect steam reheaters can suffer from tube leaks, which can be indicated by unusual behavior with respect to process temperatures in the Reheater outlet and the corresponding Converter temperature profile.

• Liquid sulfur entrainment from the upstream Condenser can result in plugging and serious corrosion problems at or near the downstream reheater, this also causes a reduction in the Claus reaction in the converter.

• For Direct-fired reheaters, the burner management system, or BMS, must be reviewed regularly to ensure the proper burn stoichiometry is still being achieved, more specifically this means having the correct air to fuel gas ratio, or acid gas if it’s burning that. A burn ratio above 100 percent will result in excess air going to the converter, which can cause sulfation and risks a sulfur fire starting. Burn ratios that are too low, like below 70% in general, can result in soot deposition onto the catalyst. Our performance testing includes a DFR evaluation with downstream oxygen measurements to verify the correct burn stoich is being achieved.

• And then lastly, like any burner, having fully functional and calibrated instruments is key. We must know that the air and fuel gas flow rates are correct, and that the temperature indicator and control loop is functioning properly. Otherwise the BMS wont be working at its full potential, and we could have false converter inlet temperatures.

Now onto the wasteheat boiler and condensers, and seal legs.

• Thermal shocks to the WHB can result in a tubesheet leak so it is very important to make sure that the RF temperatures are controlled when warming up or cooling down. The recommended heating and cooling rate is 50°C per hour.

• Low levels in the WHB are particularly dangerous since exposed tubes are subject to extremely high temperatures from the Reaction Furnace, and it is therefore critical that the level column be reporting accurate boiler feed water levels

Condenser tubes can be fouled by Sulcrete, NH3 salts, or just solid Sulfur

• Like the WHB tube sheet failures are caused by thermal shock and corrosion

• Tubesheet failures can result in freezing/solidifying the sulfur which can plug off the rundowns and seal legs. A tube or tube sheet failure can be identified by steam coming from the lookbox or from seeing slug flows of the sulfur. In the worst case, the solid sulfur ‘bridging’ in the outlet end of the condenser completely plugs off and allows the condenser to flood entirely with liquid sulfur, which is then carried over to the downstream Reheater/Converter

• Failures in a Converter bed screening/grating can result in catalyst falling into the outlet nozzle of the Converter and into the Condenser, finally ending up in the bottom of the seal leg. Depending on the amount of catalyst that has migrated into the seal legs, the legs can be either pulled and cleaned or isolated, then 50 psig steam or compressed air can be used to blow the catalyst out of the seal leg.

• Rodding the rundowns, seal legs, and up into the outlet section of the Condenser may allow for continued operations until the train can be brought down for repairs

The most important factor in designing sulfur condensers is the mass velocity of the process stream. If velocities are too low, sulfur fogging can occur, if velocities are too high, sulfur re-entrainment can occur, both leading to sulfur carryover, and a reduced recovery. Liquid sulfur entrainment is especially detrimental when it occurs in the final condenser, where losses can be upwards of 1.5% off the recovery efficiency.

Capacity evaluations by way of VMG simulation software can determine the optimal mass velocity through the condenser process tubes. These capacity evals should be up to date with the process parameters and are essential when operating at a high turndown, or expecting to in the future.

Here are some pictures of the common condenser problems, in the top left we see condenser tubesheet that’s been pulled and water tested, all the water coming out of the tubes would suggest that it failed this leak test miserably. The top right picture is what sulfur concrete, or ‘sulcrete’ looks like in a rundown, and sulcrete can be formed when there are impurities in the liquid sulfur such as catalyst dust or hydrocarbon soot. And we will typically see a buildup of sulcrete when the rundowns haven’t been cleaned before a start-up and there's still dust and contaminants in there. The bottom left picture is a hole in a multi-pass condenser and we’ll actually cover a case study about that later on. Then the bottom right picture is of sulfur that has built up and partially plugged the outlet of a condenser which could have been due to long continuous sulfur entrainment, or from a tubesheet leak.

Converters, where the catalytic reaction takes place.

• 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.

And then more quick notes;

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

• And 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 450C 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.

So to quickly sum up the troubleshooting process for catalyst deactivation, once the specific mechanism has been identified, we need to eliminate the cause, whether it be air, soot, or poison going onto the catalyst, or if its just normal aging that we need to minimize with smoother start-up and shutdowns. Once the cause has been taken care of, we need to assess the performance of the converter, is the temperature profile still ok, is the conversion reasonable? Then we can take the necessary planning steps to either do a heat soak to try a reversible, if applicable. Or to plan a catalyst changeout for the next shutdown.

So now onto the sulfur pits, or degassing pits. The two key elements for degassing are agitation and gas sweeping, where the agitation can be from continuous circulation, from dropping through tray columns, or from an actual agitator which shakes the liquid sulfur. These processes break the H2S out of solution, so then the gas sweeping aspect can move the H2S out of the pits and to the incinerator. Some degassing pits also use a chemical catalyst to improve the process of breaking the H2S out of solution.

So when the degassing becomes less effective and too much H2S is remaining in the sulfur, it could be due to a number of issues in the process. Sometimes the agitation equipment malfunctions, like a broken pump or agitator. And sometimes the air blowers will stop working. The reason for poor degassing can be difficult to identify so often times professional sampling of the liquid sulfur must be done. This process would include sampling each different stage of the degassing process as well as the sulfur pit inlets and outlets. By sampling incrementally and moving upstream, we can quickly identify the problem area and take action to bring the sulfur product back up to spec.

And that brings us to our next case study, which is about the sulfur pits. Last summer we were brought in to a gas plant to investigate increasingly severe glycol losses from an unknown location in the SRU. This plant has 3 SRU trains, with a common MCRC tail gas unit. All 3 condensers used glycol, and all the rundowns and the lines to the pit were heated with glycol, so there were quite a few locations to look for a possible leak.

With a 60:40 glycol to water mixing ratio, the amount of total diluted glycol lost was estimated to be over 1,500 L/day. So we had to quickly come up with method to test for the source of the leak without having to add any tracers to the process, which may impact the quality of the sulfur product.

SRE devised a plan to sample from the pit outlets first, then move backwards (or upstream) until the exact source of the glycol was found. We first tested the pit outlet lines and found glycol in 2 of those 3 outlets. Next we tested each stage within those 2 pits, and we found that the entire #1 pit had glycol contamination, but only the last 2 sections of the #2 Pit. So this led us to conclude that there had to be a leak somewhere between the first and second sections of Pit 2. Then we had to check all the Condenser rundowns that led to Pit #1 to find that leak, which ended up being in the second Condenser’s tubesheet, and was found to be much more severe of a leak. Now that the leaks were identified, they could be repaired during a fairly quick shutdown.

So our team stayed on site to assist with a smooth shutdown of those 2 trains, and we were even able to see how bad the condenser leak really was. That, and the pit tracing leak were patched up, and the SRU was started back up 24 hours later.

In conclusion, both leaks were identified and then repaired in a timely manner. We didn’t have to use tracers, and we analyzed all those liquid sulfur samples on site, with fast results. And we saved them a bunch of money by stopping the glycol losses, and cleaning up the sulfur product back to normal.