Lean acid-gas enrichment processes can be used to upgrade low-quality offgas from treating units to higher-quality Claus plant feed or to smaller volume streams that are suitable for reinjection. The process objective is minimizing hydrogen sulfide (H2S) leaks into the systems vent gas, thus producing a gas enriched in H2S to the greatest extent possible.
Designing and operating acid-gas enrichment plants are highly sensitive for a number of parameters, including lean-solvent temperature (a serious constraint in the Middle East). Other parameters are feed gas, including H2S/carbon dioxide (CO2), choice of tower internals type, number of contact trays, and solvent selection.
Managing acid gases.
For acid gas feeds with an H2S concentration greater than 50%, a reaction furnace temperature in excess of 925°C (1,700°F) can be achieved using the simple straight-through Claus process. However, if the acid-gas H2S concentration is significantly lower than 50%, the minimum required reaction furnace temperature of 925°C (1,700°F) may not be attainable without an upstream acid-gas enrichment unit to increase the H2S concentration of the Claus plant feed gas.
The required reaction furnace temperature is a function of acid-gas contaminants. Fig. 1 shows the reaction furnace theoretical adiabatic flame temperature as a function of the H2S content in the acid-gas feed for a straight-through Claus plant configuration. The two horizontal dashed lines represent the temperature targets required to completely destroy benzene, toluene and xylenes (BTX) and straight-chain hydrocarbons.
As shown in Fig. 1, the minimum flame temperature required to destroy BTX and heavy hydrocarbons cannot always be maintained. Aromatics (BTX) cannot be destroyed if the acid-gas H2S concentration is less than 60%, and paraffinic heavy hydrocarbons cannot be destroyed if the acid-gas H2S concentration is less than 50%.
| Fig. 1. Reaction furnace adiabatic flame |
temperature vs. acid-gas H2S content.
Techniques such as supplemental fuel-gas firing can raise the reaction furnace temperature. However, supplemental fuel-gas firing introduces a number of negative factors.
First, there is a decrease in overall sulfur-recovery efficiency with supplemental fuel firing. This is mainly due to the formation of significant amounts of undesirable byproducts such as carbonyls (COSs) and CS2. In addition, the water and inert gases produced by combustion lead to less than a favorable Claus equilibrium, which decreases the overall sulfur-recovery efficiency. In addition, equipment sizes must be larger to handle the higher gas flow that results from co-firing with fuel gas. Finally, fuel-gas supplemental firing usually requires more operator attention to ensure that coke formation does not occur.1,2
Preheating the acid gas and/or the combustion air streams prior to being fed into the reaction furnace is another option for increasing the reaction furnace temperature. The maximum reaction furnace temperature increase that can be achieved by preheat depends on the heating medium used, but is limited to about 60°C to 90°C (110°F to 165°F). Preheating increases sulfur plant capital and operating costs and increases the total pressure drop across the unit.
Oxygen enrichment is another process option that can effectively increase the reaction furnace temperature. However, depending on the location of the facility and the quantity of oxygen needed, oxygen enrichment may be prohibitively expensive if an inexpensive oxygen source is not readily available.
With the advent of selective amine treating systems, the H2S concentration of a Claus plant acid-gas feed stream can be increased by rejecting CO2 and other contaminants. Selective amine treating systems can also be used to increase the feed gas H2S concentration of existing Claus sulfur plants with the following advantages: 13
No impact on the reaction furnace combustion air requirements
No impact on sulfur plant capacity
Stable operation in the reaction furnace
Achievable required temperature for destruction of contaminants such as BTX, ammonia and cyanides
Wide range of acid-gas concentrations
New technology has recently been developed that integrates an acid-gas enrichment unit with the downstream tail gas treating unit. This technology utilizes a special double-absorption design to enrich the acid gas. The process can be designed to process acid gas with an H2S concentration below 10% and achieve an overall sulfur recovery that exceeds 99.9%.
Acid-gas enrichment technology.
The process is designed to selectively absorb H2S from lean acid gases that could contain less than 10% H2S, such as sour natural gas, refinery gas, synthesis gas or other sour CO2 streams to produce a high-quality acid gas with an H2S concentration up to 75%. This process can be used with various licensed selective amine treating technologies including formulated MDEA and proprietary selective treating solvents.4 The technology can also include a third-stage absorber with an integrated Claus tail-gas unit that uses a common regenerator.
Lean acid gas contains significant amounts of inerts such as CO2. Carbon dioxide lowers the net heating value of the acid gas and also reduces the concentration of sulfur dioxide (SO2) and H2S in the reaction furnace, making sulfur conversion more difficult. Dilute acid-gas feeds often contain contaminants such as ammonia and aromatics (BTX) that must be destroyed in the reaction furnace to protect downstream catalyst beds from fouling. The low-heating value of dilute acid-gas streams makes the complete destruction of these objectionable components difficult.5 The minimum temperature for effective operation of the reaction furnace on clean acid gas should be above 925°C (1,700°F). In extreme cases, when the H2S content in the acid gas falls below 10%, the minimum reaction furnace temperature may become impossible to attain and additional processing steps must be used to effectively convert the H2S to elemental sulfur. In addition, the dilution effect of CO2 in lean acid gases will increase the size of the sulfur-recovery unit (SRU) as the plant size is controlled by the total volumetric flow of acid gas. This, in turn, will significantly increase the cost of the SRU.
When the acid gas is too diluted in H2S, a selective absorption technique may be used to enrich the acid gas prior to entering the Claus unit. By selectively absorbing H2S from the acid gas and then stripping the rich solvent, two gas streams are produced. The gas passing through the absorber is primarily CO2. This stream is sent to an incinerator for conversion of trace amounts of H2S to SO2 prior to discharge to the atmosphere. The gas stream leaving the regenerator is acid gas enriched in H2S. This stream can be processed in a conventional Claus unit.
Another selective treating application is in the processing of tail gas from a Claus SRU. The sulfur recovery efficiency of a third-stage conventional modified Claus unit is thermodynamically limited to about 97%. A common practice that is used to comply with stringent sulfur emission environmental regulations is to convert the sulfur compounds in the Claus unit tail gas, such as COS and SO2, to H2S using hydrogenation and hydrolysis. The H2S is then removed from the converted tail gas and recycled back to Claus sulfur plant. This configuration can achieve sulfur recoveries of up to 99.9%.
Amine-based solvents capable of selectively removing H2S are used in these processes. These processes are based on MDEA or on sterically hindered amines that react rapidly with H2S and slowly with CO2. Typically, these processes concentrate H2S by a factor of three to five.
The following describes the double absorption acid-gas enrichment and the integrated double-absorption sulfur-recovery processes. These processes and configurations were developed to increase the H2S content of lean acid-gas streams.
Double absorption acid-gas enrichment process.
The double-absorption process can be used as a stand-alone process to improve the quality of the acid gas from conventional acid-gas removal units. This process recycles a portion of the acid gas to a second absorber to concentrate the H2S. Fig. 2 shows the basic configuration of the double-absorption process.
| Fig. 2. Double-absorption acid-gas |
The acid-gas feed stream enters the unit and is scrubbed in the first amine absorber, V-1, with a lean amine stream 2. The solvent typically consists of 40% to 50% MDEA, although other solvents, such as a sterically hindered amine can be used. The amine absorber generally consists of 12 to 18 trays. About 85% to 90% of the feed gas CO2 is rejected in stream 3. The rich-solvent stream 4 exits the bottom of the first absorber and combines with the rich solvent from the second absorber, V-2, forming stream 6.
The combined stream is pumped and heated with the lean/rich exchanger, E-1, using the heat content of the lean solvent from the regenerator, V-3. The regenerator operates at a slightly higher pressure than the absorber. This allows recycling of a portion of the acid gas without using a compressor.
The heated stream enters the top of the regenerator, which consists of 20 to 22 stripping trays and a wash section. Alternatively, other contacting devices, such as packing, can be used. The acid gas in the rich solvent is stripped with heat applied at the bottom reboiler, E-2, producing overhead stream 9 and a lean solvent, stream 10.
The lean solvent is pumped and cooled in the lean/rich exchanger, E-1. The lean solvent is further cooled in E-3. Air or cooling water can be used as the cooling medium. The lean amine should be cooled as much as possible, as cooling favors the selective absorption of H2S, thereby increasing the H2S selectivity. The cooled lean amine is split into two portions, stream 2 and stream 22, which are fed into the first absorber, V-1, and the second absorber, V-2, respectively.
The overhead vapor from the regenerator, stream 9, is cooled in the overhead condenser, E-4. Liquid in the stream is separated in the reflux drum, V-4. The liquid stream, which is mostly water, is pumped and used to reflux the regenerator. The enriched acid gas is split into two portions, stream 17 and stream 18. Stream 17 is routed to the second absorber, V-2, for further enrichment and stream 18 is sent to the SRU.
The flow ratio of stream 17 to stream 14 ranges from 25% to 75%, depending on the H2S concentration in the feed gas. For a low H2S-content feed gas, a higher flow ratio of possibly 75% may be necessary. The ratio can be reduced to less than 25% when the feed gas contains a higher H2S concentration. For most applications, acid-gas enrichment to about 75% H2S can be achieved. In addition, over 90% of the hydrocarbons and BTX components can be rejected with the CO2 stream. The H2S enrichment and the absence of BTX and heavy hydrocarbons in the enriched acid gas are highly desirable for good performance of the Claus SRU.5,6
Furthermore, depending on the feed-gas composition and acid-gas loading of the semi-lean solvent, the overall circulation rate can be reduced by splitting the semi-loaded rich solvent stream 7 from the first absorber into two separate streams. One stream can be cooled and reused for absorption in the second absorber V-2. The other stream, consisting of semi-lean rich solvent from the first absorber, which is still unloaded in terms of its H2S content, can be fed to the lower section of the second absorber for bulk H2S removal. The remaining semi-lean solvent can then be sent to the regenerator, V-3, for solvent regeneration. Fig. 3 shows the configuration for this option.
| Fig. 3. Double-absorption acid-gas |
enrichment process with rich-solvent
Integrated double-absorption acid-gas enrichment/sulfur recovery process. The double-absorption acid-gas enrichment configuration can be integrated with the tail-gas unit to reduce the total project cost. The semi-lean solvent from the tail-gas unit, which is unloaded at the upstream absorber conditions, can be reused to reduce the overall solvent circulation while eliminating a dedicated regenerator. With this option, a single regenerator can be used to regenerate the rich-solvent streams from both the acid-gas enrichment and the tail-gas units.
Fig. 4 shows a configuration where acid-gas enrichment is integrated with the tail-gas treating unit. The combination of the enrichment unit with a tail-gas absorber processing the tail gas from a Claus unit can achieve over 99.9% total sulfur recovery even when the feed gas H2S concentration is low.
| Fig. 4. Integrated double-absorption acid-|
gas enrichment/sulfur recovery process.
In this configuration, a two- or three-stage Claus SRU is used to process the enriched acid gas. A conventional modified Claus SRU would require more than three stages and other various additional processing steps to achieve at best, 99% sulfur recovery. This integrated tail-gas treating configuration significantly reduces the sulfur plant energy requirement and improves sulfur-recovery efficiency while requiring less capital investment than a conventional design.
The effluent from the Claus unit, which contains trace quantities of H2S, SO2 and other sulfur compounds, is processed in the hydrogenation unit. The hydrogenated gas is quenched and extra water is condensed and removed prior to routing the gas to the tail-gas absorber, V-5. Lean amine is supplied from the lean-amine header. Effluent from the tail gas absorber, which contains environmentally acceptable levels of H2S, can, depending on environmental regulations, either be vented directly to the atmosphere or routed to an incinerator for disposal.6, 7
The rich amine from the tail-gas absorber is pumped and combined with the rich-amine streams from the first and second absorbers. The combined stream is heated in the lean /rich exchanger and fed to the common regenerator. Depending on the actual feed gas conditions and sulfur-recovery requirements, the semi-loaded solvent, stream 35, from the tail gas absorber, V-5, can be re-used in the second absorber, V-2. This configuration (option 1) as shown in Fig. 5, reduces solvent circulation and the solvent regeneration duty. With this configuration, the incremental amount of solvent used in the tail-gas absorber can be reduced, thus improving process economics while maintaining high sulfur-recovery efficiency.
| Fig. 5. Integrated double-absorption |
acid-gas enrichment/sulfur recovery process
Depending on the acid-gas composition and the semi-rich solvent loading, another option, shown in Fig. 6, can be used to further reduce the total solvent circulation rate and solvent regeneration duty. This configuration re-routes a portion of the semi-loaded rich solvent stream 7 from the first absorber, V-1, to the second absorber, V-2. The stream is cooled prior to entering the lower section of the second absorber, providing a cost-effective means for processing lean acid-gas feeds.
| Fig. 6. Integrated double-absorption |
acid-gas enrichment/sulfur recovery process
Optimization options. Several acid-gas enrichment process configurations and various options for integrating sulfur recovery with tail gas treating are presented here. The double-absorption process and various configuration options effectively produce acid-gas enriched in H2S from a lean acid- gas feed. Acid gas can be enriched from less than 7% to over 75% H2S. The various configurations also allow removal of hydrocarbons and BTX that are known to interfere with SRU operation. Furthermore, a CO2 stream with environmentally acceptable levels of H2S can be produced from the absorbers for disposal by incineration. When integrated with Claus and tail-gas treating units, the process is capable of reducing the number of Claus reaction stages and can achieve over 99.9% total sulfur recovery. The double-absorption process also solves the problems of low H2S content and low acid heating value by providing a Claus plant feed with a high H2S content. HP
1 ZareNezhad, B. and N. Hosseinpour, Applied Thermal Engineering, Vol. 28, Issue 7, May 2008.
2 ZareNezhad, B., Hydrocarbon Processing, October 2008, pp 109115.
3 ZareNezhad, B., Research Report 1342B, Petroleum Ministry, November 2008.
4 ZareNezhad, B., Hydrocarbon Processing, February 2009, pp. 6372.
5 Chow, T. K., C. H. Lawrence, J. A. Gebur and V. W. Wong, Canadian International Petroleum Conference 55th Annual Technical Meeting, Calgary, Canada, 2004.
6 Clarke, D., J. Iyengar, M. Al-Khaldy and S. Summers, 51st Annual Gas Conditioning Conference, Oklahoma, 2001.
7 Chow, T. K, J. A. Gebur, and V. W. Wong, World Petroleum Congress, Second Regional Meeting, Doha, Qatar, 2003.
|The author |
||Dr. Bahman ZareNezhad is an academic professional member of the Ministry of Science, Research and Technology in Iran. His research activities are mainly focused on advanced oil refining and gas processing technologies, tail-gas treatment, sulfur recovery and NGL extraction processes. Dr. ZareNezhad has published several technical and research papers in international journals and has presented several technical courses regarding oil and gas industries. He has 22 years of varied experience in research, process engineering, project management and technology development, and is a consultant for several oil and gas companies. Dr. ZareNezhad holds a PhD in chemical engineering from the University of Manchester Institute of Science and Technology (UMIST) in England. |