B. Marès, A. NAPOLEONI and G. DALARY, Axens, Paris, France; and G. W. PARK, Kuwait Oil Co., Ahmadi, Kuwait
In 2024, Kuwait Oil Co. (KOC) saw the successful commissioning of new sulfur recovery units (SRUs) at Jurassic Production Facilities (JPF-4 and JPF-5), serving sour gas wells in north Kuwait (FIGS. 1 and 2). Developed by Axens (the authors’ company), these optimized SRU processes reflect a significant step forward in sulfur recovery technology, strongly inspired by insights from the customer’s feedback in 2020 following the commissioning of the authors’ company’s SRU at JPF-3, particularly from a related article published by the co-author.1
The optimized process at these plants includes a unique SRU, featuring the authors’ company’s patented switching reactors with internal coolinga, paired with a caustic scrubber. This combination enhances environmental performance and significantly reduces investment costs.
The success of these projects underscores the importance of close collaboration between process licensors and clients. The synergy between the two companies has been instrumental in achieving these advancements, demonstrating how tight cooperation can lead to substantial process optimization improvements in just four years.
This article highlights key aspects of collaboration and technological advancement in process design development and project execution.
FEATURES OF THE AUTHORS’ COMPANY’S SRU VS. A CONVENTIONAL SRU
A conventional SRU typically consists of the equipment and piping shown in FIG. 3. Catalytic conversion is maximized in three (or two) successive, fixed catalytic beds [with activated alumina and titanium oxide (TiO2) catalyst] at low temperature. The reactor inlet temperatures are maintained by reheat exchangers at approximately 240°C (464°F), 205°C (401°F) and 190°C (374°F), respectively. The first catalytic reactor is maintained at sufficiently higher temperature to ensure carbonyl sulfide (COS) and carbon disulfide (CS2) conversion on titanium catalyst, which are formed in the thermal reactor. The Claus catalytic reaction is exothermic and is favored at low temperature. However, each reactor inlet temperature should be maintained above the sulfur dewpoint to prevent sulfur condensation on the catalyst. Produced sulfur at each step is removed in the condenser to improve the desirable reaction in the following catalyst beds. The sulfur is drained via seal legs into the sulfur pit, degassed and sent for export.
The catalytic reaction system of the second technology is unique. Other sections are almost the same as those of the conventional SRU. The typical process schematic is shown in FIG. 4.
The process is based on the Claus reaction carried out in two steps, a first thermal stage and then two catalytic stages, with the last operating in sulfur sub-dewpoint mode. The fundamental idea of this process is to remove the heat produced by an exothermic Claus reaction directly in the catalyst bed, rather than in a downstream heat exchanger. This controls the temperature throughout the catalyst bed within a narrow range. The heat exchanger applied is a thermoplate type with a large clearance. The space between the plates is filled with catalyst so that the cooling heat exchanger is embedded in the catalyst.
The first catalytic reactor of a conventional Claus plant is always a compromise between two targets: the reaction temperature must be high enough for maximum COS and CS2 hydrolysis, and as low as possible for favorable equilibrium of the Claus reaction and maximum conversion (shown in FIG. 5).
The internally cooled reactor can solve this conflict. The top layer of the catalyst is not equipped with thermoplates. The feed temperature to this adiabatic section can be adapted to safely reach the required temperature for COS and CS2 hydrolysis [usually 300°C–310°C (572°F–590°F)]. The second section downstream in the same reactor is cooled and a fixed outlet temperature slightly above the sulfur dewpoint can be set by an external heat sink (evaporation of boiler feedwater circulating in the thermoplates). As the heat of the reaction is removed, more sulfur is produced. This combination of adiabatic and cooled (pseudo-isothermal) reaction reaches conversion rates comparable to two-stage, conventional SRU catalytic reactors, at the outlet of the first stage of the authors’ company’s SRU catalytic reactor. The adiabatic section in the reactors is filled with TiO2, and the subsequent isothermal section is loaded with activated alumina.
A second identical reactor that is operated at a lower temperature follows downstream, shifting the chemical equilibrium towards more sulfur formation, shown in FIG. 5. Sulfur is adsorbed in the catalyst pores in liquid form. The outlet temperature can be chosen in a range of 100°C–128°C (212°F–262°F)—i.e., possibly even below the sulfur solidification point of 113°C–119°C (235°F–246°F).
In sub-dewpoint processes, the advantage of the internally cooled reactor is evident. Temperatures can be adjusted and kept constant by external heat sinks. This dramatically simplifies the precooling-adsorption-regeneration procedure. Furthermore, the possibility of fixing and equalizing the temperature by external heat sinks makes it possible to choose the lowest sub-dewpoint temperatures. Even in state-of-the-art processes, an allowance of 10°C–15°C above the solidification temperature must be maintained to prevent freezing and subsequent sulfur plugging in colder areas (e.g., close to reactor walls).
This allowance can be scrapped completely in the internally cooled reactor. In fact, there is no risk of blocking at temperatures even below the freezing point. Sulfur is adsorbed faster in the catalyst pores than it accumulates on the surface and, therefore, has no influence on the gas flow. In addition, the embedded heat exchanger keeps the temperature evenly distributed over the cross-section of the reactor. This prevents the accumulation of solid sulfur in peripheral areas, as is often observed in adiabatic reactors.
The process is cyclic and designed so that after 24 hr, the two reactors switch, as shown in FIG. 6. The cycle of switching gas flow from reactor to reactor is set by the sulfur-holding capacity of the catalyst in each bed, and it depends on the accumulated acid feed gas flow. For that purpose, switching four-way valves actuates and modifies the process gas circulation through the unit. The former second reactor becomes the first reactor, and vice versa. The switching procedure is completely automatic and takes only a few seconds.
The two units will be compared based on actual operation performance and investment cost. TABLE 1 shows a comparison summary. The most obvious differences between the two units are sulfur recovery efficiency, tail gas composition and sulfur dioxide (SO2) emissions to the atmosphere. These differences come from the lower temperature of catalytic beds due to internal cooling in the authors’ company’s SRU case, which moves the chemical equilibrium towards more favorable sulfur production, shown in FIG. 5. The sulfur compounds in tail gas and SO2 emissions are substantially reduced compared to the conventional SRU case. For both cases, additional downstream treating units are required to meet environmental regulations for a maximum of 250 ppm SO2 emissions.
The total investment costs for the two SRUs (TABLE 1) appear to be equivalent considering separate sulfur degassing pits of the conventional SRU. However, if three catalytic reactors are applied to the conventional SRU, including one more sulfur condenser, then the authors’ company’s SRU may obtain a marginal cost advantage over the conventional SRU. After conducting a utility balance review, one noticeable dissimilarity between two technologies emerges. The low-pressure steam production rate of the authors’ company’s SRU is just half of that from the conventional SRU, since the required heat duty in the sulfur condensers in the authors’ company’s SRU is reduced due to internal cooling in the catalytic beds. For other utilities, the two units are almost identical.
During the transient switch, as detailed in FIG. 6, no loss in performance was discovered because the sequence forces the two beds into sub-dewpoint operation before the switch. This results in even better conversion efficiency during transient time.
The authors’ company’s SRU is a proven and commercialized SRU technology that has 18 proprietary sulfur recovery systema references globally, mostly without tail gas treating units (TGTUs). Sub-freezing mode, rather than sub-dewpoint, is also available. Through the sub-freezing operation mode, it is possible to increase the sulfur recovery efficiency further up to 99.85%. SO2 emissions will drop accordingly.
CUSTOMER FEEDBACK AFTER SRU COMMISSIONING AT JPF-3
After commissioning the SRU at JPF-3, the final wrap-up meeting was held at the KOC headquarters in Kuwait. In the meeting, the author from KOC requested that his Axens counterpart develop an optimized TGTU in addition to the tail gas incinerator and the stack located downstream of the SRU to meet the 99.9% sulfur removal target. Additionally, it was noted that the current air addition scheme using air blowers in the stack should be replaced with a more environmentally friendly design, as this configuration does not adequately mitigate sulfur compound emissions to the atmosphere. The schematic of the SRU at JPF-3 is shown in FIG. 7.
In the same year, the author published an article in Hydrocarbon Processing1 suggesting that the optimized TGTU for the authors’ company’s proprietary SRUa should be a caustic scrubbing system for the reasons discussed below.
The proprietary offgas treating processb (FIG. 8) is the best treating unit for use with the conventional SRU—the number of commercialized sulfur plants proves this assertion. However, what if this unitb is combined with the authors’ company’s SRUa? Combining an amine-based offgas treating unitb with the authors’ company’s SRUa is not a good option, because in that case, all the benefits of the sulfur recovery processa become very limited.
Due to this limitation, a caustic scrubbing system is considered instead. The process first incinerates SRU tail gas, generating a stream containing SO2. This gas—containing 36 mol% of water—is cooled and the water is removed in the quench tower to prevent caustic dilution in the subsequent scrubber. The gas is then sent to a caustic scrubber, where the SO2 is absorbed in an aqueous caustic solution, as shown in Eq.1:
2NaOH + SO2 —> Na2SO3 + H2O (1)
The purge water is transferred to a wastewater treatment facility, and the flue gas is released to the atmosphere. The process uses stainless-steel material or alloy cladding in the caustic scrubber to prevent corrosion. Daily caustic (NaOH) consumption is estimated at 2.8 t–3 t for a 200-t sulfur production facility. The actual caustic consumption for JPF-4 and JPF-5 is higher due to the absence of a quench tower. For a sulfur production rate of 200 tpd, the consumption would be closer to 5 tpd. This also depends on acid gas composition and residual SO2 content at the caustic scrubber inlet. SO2 emissions limits can be designed with a wide range of 50 ppm–250 ppm. Several qualified vendors for scrubber design and manufacturing offer their own technologies, such as venturi types, sprays, water curtains, etc. A schematic flow diagram of the process is presented in FIG. 9.
The comparison of two units is summarized in TABLE 2. The parameters of the caustic scrubbing system have been estimated while those for the proprietary offgas treating unitb are taken from actual cases.
The proprietary unitb has a higher overall sulfur recovery efficiency than the caustic scrubbing system due to H2S recycle to the SRU and a high efficiency of amine absorption for H2S.2 Conversely, only chemical conversion occurs in the caustic scrubber, not recovery. Also, further wastewater treatment is required for the scrubbing system (e.g., oxidizing solution by air). Byproduct sodium sulfate (Na2SO4) is generally regarded as non-toxic. The equipment cost for a caustic system is much lower than that for the proprietary unitb, since the scrubbing system consists of a simple configuration without reactors and amine facilities. Its operation cost is more economical than that of the proprietary unitb, mainly due to steam consumption in the amine unit. The caustic system is not sensitive to tail gas composition because there is no catalytic reactor, and all H2S is converted to SO2 in the upstream incinerator. Furthermore, the caustic system can handle a wide range of tail gas composition changes without process upsets like SO2 breakthrough or amine foaming/carryover in the proprietary unitb. SO2 emissions can be reduced by up to 50 ppm with an adequate scrubber design, and CO2 emissions will be substantially reduced compared to the proprietary unitb due to no steam consumption. For plant owners looking for countermeasures against tight environmental regulations, the caustic scrubbing system may be a good alternative.
PROCESS OPTIMIZATIONS AND PERFORMANCE AT JPF-4 and JPF-5
Considering KOC’s concern in decreasing SO2 emissions by meeting the 99.9% sulfur removal target using the authors’ company’s processa, the company has developed a global scheme to achieve this specification, focusing on the simplest, most efficient and economically attractive solution.
Consequently, two 120-tpd modularized SRUsa coupled with a common caustic scrubbing system for tail gas processing from the SRU have been implemented on each of the JPF-4 and JPF-5 projects (FIG. 10). The caustic scrubbing section has been designed to decrease the SO2 content in the flue gas from the two incinerators and waste heat recovery systems (WHRSs) below 250 ppmv.
The caustic polishing occurs in a spray-type scrubber, equipped with a venturi quencher device on the flue gas inlet, fed by a slipstream from the slurry loop to cool down the gas from the WHRS by saturating it with water. The contact of the flue gas with the caustic slurry is maximized by multiple spray banks at different elevations. Each spray bank is composed of a series of spray nozzles, designed to achieve proper atomization of the recycle slurry.
The system pH is controlled by the addition of caustic into recirculation piping in a pH range of 6 to 8. A slipstream of air from the main blowers is injected into the sump liquid to oxidize the sodium bisulfite (NaHSO3) and Na2SO3 to sodium sulfate (NaSO4).
To control the salts accumulation in the loop, a continuous bleed at 10% (w/w) slurry concentration is removed from the recycle pump. Such effluent is non-toxic and can be sent to the water treatment package without any impact on the water specification, or it can be sent directly to the disposal wells.
The JPF-4 and JPF-5 facilities successfully started up in early 2024. Performance acceptance tests were conducted after startup and capacity ramp-up without any delay in the presence of the licensor. The average figures of the main parameters from the 96-hr performance acceptance test are listed in TABLE 3 and compared to design.
All figures for product specifications and production were satisfied during the 96-hr performance acceptance test.
The benefit of the combination of the authors’ company’s sulfur removal technologya and the simple caustic scrubber system, achieving a 99.9% sulfur removal efficiency, was demonstrated during the test.
Further development by the licensor. The authors’ company’s unitsa in operation at JPF-3, JPF-4 and JPF-5 are fitted with a vertical reactor design, which is suitable and economically attractive for SRU capacity up to 150 tpd/train.
Recently, the authors’ company developed a horizontal reactor design that allows the processa to be suitable for a higher sulfur capacity while keeping the same performance advantages. The authors’ company has one 400-tpd unit reference fitted with horizontal reactors, combined with the latest catalyst developments by using the new SRU catalystc promoted TiO2 instead of the flagship catalystd. The new SRU catalyst to remove COS and CS2 has proven to offer higher performance while improving cost to fill.3
Takeaways. The economical and reliable combination of the sulfur removal technology processa along with the caustic scrubber solution to achieve 99.9% sulfur removal was selected for the JPF-4 and JPF-5 projects. The operational benefits and good performance were demonstrated during performance acceptance tests completed after startup. The SO2 content in the flue gas was significantly lower than the 250-ppmv specification.
Through active feedback and collaboration between the licensor and the client, the authors’ company improved its process design and became more competitive in the market, while the owner company, KOC, was able to operate optimized processes that complied with environmental emissions limits and benefited from economical construction and operating costs. It was a win-win strategy and established a best practice for both companies. HP
NOTES
Axens’ Smartsulf®
Shell Claus Offgas Treating (SCOT)
Axens’ Sulshine® CRS 41
Axens’ Sulshine® CRS 31
LITERATURE CITED
Park, G. W., “Optimize the selection of sulfur unit blocks and process technology combinations,” Hydrocarbon Processing, December 2020.
Park, G. W., “Optimize the design of amine treatment and sulfur recovery,” Hydrocarbon Processing, May 2020.
Le Touze, J., T. Serres, M. Chevrier and E. Roisin, “New low-density titania catalyst for improved sulfur recovery,” Sulfurmagazine, January–February 2024.
Benoît Marès has more than 15 yr of experience in the sulfur recovery industry. He is a Sulfur Expert for Axens SA in Paris, France, where most of his work is focused on providing his expertise for the design, troubleshooting and developments of SRUs. Additionally, he works as a Modular Units Proposal Manager, where he oversees the development of technical offers for modular unit tenders. Marès received an engineering degree in Chemical Engineering from ENSIACET School of Toulouse, France, and a second degree from the University of Natal in Durban, South Africa.
Alessio Napoleoni works at Axens as a Technology Engineer, where he is responsible for gas sweetening and SRU design and technical proposals, and for improving gas technologies competitiveness. Napoleoni has 12 yr of experience as a process and technology engineer in the oil and gas industry. He earned an MS degree in chemical engineering in 2012 from the University of Rome La Sapienza.
Guillaume Dalary has more than 15 yr of experience in gas treating, with a particular focus on gas sweetening, sour water stripping and sulfur recovery processes. As a Sulfur Expert at Axens SA in Paris, France, he participates in various projects phases, ranging from technical proposal to onsite support for unit startup, troubleshooting, tuning and performance tests worldwide. Dalary earned an MS degree in chemical and process engineering in 2007 from ENSGTI engineering school of Pau, France.
Gi Won Park works in the upstream segment for Kuwait Oil Co. in Kuwait. He has 28 yr of experience in process design and operation and holds two U.S. patents and an international patent in process technology. Park has worked on various projects and revamps, including three billion-dollar projects for grass-root refining (SK Energy) and petrochemical plants as a senior process engineer and engineering team leader. Park holds a BS degree in chemical engineering.
