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Technologies for gas processing & sulfur removal
Jacobs offers a variety of sulfur solutions for our clients' needs. Our technology options include the following:
ADIP refinery / natural gas
The ADIP process is a regenerative process that selectively reduces H2S in gas to very low concentrations in the presence of CO2. The ADIP process uses an aqueous solution of diisopropanol amine (DIPA) or the aqueous solution of methyldiethanol amine (MDEA). MDEA is used for applications in which high selectivity for H2S is required. Depending on operating conditions, 20-60% of the CO2 is co-absorbed – if DIPA is used as the ADIP solvent, and this can be reduced to 10%-30% if MDEA is used as the solvent.
The ADIP process can also be used for enrichment of acid gas feed to a sulfur recovery plant, to achieve a higher H2S content. Integration of gas treating with the SCOT solvent system is also an option.
ADIP liquid hydrocarbon treating
In addition to its use as a regenerative process for the reduction of H2S to very low levels in gases, the ADIP process is also used to selectively reduce H2S and COS to very low levels in liquid hydrocarbons, such as propane-propylene (PP), butane-butene (BB), LPG and NGLs. The process is based on regenerative absorption with an amine solvent in contact with the acidic feed. Removal of CO2 is also possible. H2S removal from LPG or NGLs down to 20 ppmwt or lower, and COS removal down to 5 ppmwt as sulfur are achievable.
The Sulfinol process is a regenerative process that removes H2S, CO2, COS and mercaptans from gases. The sulfur compounds in the product gas are removed to low ppm levels. This process is specifically for treating large quantities of gas, such as natural gas, which are available at elevated pressures.
The Sulfinol process is unique in the class of absorption processes because it uses a mixture of solvents, which allows it to behave as both a chemical and a physical absorption process. The solvent is composed of Sulfolane, DIPA or MDEA and water. The acid gas loading of the Sulfinol solvent is higher, and the energy required for its regeneration is lower, than those of purely chemical solvents.
At the same time, it has the advantage over purely physical solvents because severe product specifications can be met more easily, and co-absorption of hydrocarbons is relatively low. The Sulfinol-M process is used for selective absorption of H2S, COS and mercaptans, while co-absorbing only part of the CO2. Deep removal of CO2 in LNG plants is another application. Integration of gas treating with the SCOT solvent system is also an option.
The Claus process recovers elemental sulfur from H2S containing gases originating from gas treating plants such as alkanolamine units or physical solvent plants. Modern Claus plants are able to process H2S/NH3 containing gases as well, originating from sour water strippers.
The SUPERCLAUS® process recovers elemental sulfur from H2S-containing gases originating from gas treating and sour water stripper plants. Yields up to 99.2% overall sulfur recovery, without any further tail gas cleanup, are possible.
SUPERCLAUS® was first introduced in 1988 and there are now over 190 sulfur recovery units globally with the largest single train unit now in operation is 1,200 tons per day. Single location multiple train units have been designed for capacities up to 5,000 tons per day. Clients who have chosen SUPERCLAUS® for their operations include Chevron, BP, Total, Saudi Aramco, Conoco, Indian Oil Corp., Kuwait Petroleum, Exxon, and ADNOC.
The EUROCLAUS® process recovers elemental sulfur from H2S-containing gases originating from gas treating and sour water stripper plants. The EUROCLAUS® process is an improvement of the SUPERCLAUS® process.
Yields from 99.3 up to 99.5% overall sulfur recovery, without any further tail gas cleanup, are possible for clients. First introduced in 2000, there are now 10 EUROCLAUS® units currently under design with 40 units in operation.
(Low temperature) SCOT
The Shell Claus Off-gas Treating (SCOT) process removes sulfur compounds from Claus tail gas to comply with stringent air emissions regulations. The conventional SCOT process is able to easily meet less than 250 ppmv total sulfur in the SCOT offgas, which corresponds to an overall sulfur recovery efficiency of 99.9% on intake. The Low Temperature (LT)-SCOT has the same recovery capabilities, but it reduces the total installed cost (TIC) by 15% compared to the conventional SCOT unit. Low Temperature SCOT saves utility costs when compared to regular SCOT. We also complement the slate of sulfur solutions by offering Shell’s SCOT technology for sulfur recovery requirements up to and above 99.9%. We are the number one licensor of Shell’s SCOT technology. The Low Temperature SCOT technology is able to achieve high sulfur recoveries while obtaining significant savings in utility consumption and lower total installed cost values compared to the conventional SCOT design.
SUPERCLAUS® / scrubber
Selection of an appropriate and cost effective Tail Gas Treatment process to follow existing Claus plants is a challenge facing refiners and natural gas plant owners around the world. New emission regulations, interest in increasing sulfur recovery and processing of higher sulfur crudes are the main drivers.
The most common approach is to install an amine-based Tail Gas Treatment Unit (TGTU), however, lower investment costs and higher reliability can be achieved by combining two well established processes, our SUPERCLAUS® process and caustic scrubber wet gas technology. By combining these technologies investment costs are reduced, the process is less expensive to operate and to maintain, requires a smaller footprint, greatly simplifies overall operation and has a greater on-stream reliability when compared to an amine-based TGTU.
The Shell Sulfur Degassing process removes H2S and H2Sx from liquid sulfur eliminating potential toxic and explosion hazards associated with handling, transport and storage of liquid sulfur. Elemental sulfur, produced by the Claus process, contains both physically dissolved H2S and chemically bound H2S in the form of hydrogen polysulfides (sulfanes): H2Sx. Liquid sulfur produced typically contains 250-350 ppm wt H2S as H2S and polysulfides.
The principle of sulfur degassing is to accelerate decomposition of the poly-sulfides according to H2Sx ↔ H2S + Sx-1 and to remove the dissolved H2S from the liquid sulfur. In the Shell Sulfur Degassing process, the sulfur is degassed to less than 10 ppm wt H2S/H2Sx.
Advanced burner control & advanced burner control plus
Proper control of the amount of combustion air that is routed to the thermal stage of a Claus type unit is key in reaching optimum performance. Any deviation of the optimum amount can lead to recovery efficiency decrease. Jacobs' Advanced Burner Control (ABC) system is able to respond fast and accurately to changes in feed gas flows and operating conditions to have a smooth and optimum operation of the unit. This control system is more efficient over conventional control systems.
Jacobs also offers the Advanced Burner Control Plus (ABC+) system, which adds on-line feed gas analysis and automatic composition compensation to the features that ABC system provides. The major advantage of ABC+ is that any changes in the feed gas composition are noticed and coped with (i.e. the amount of combustion air is adapted automatically) before the gas passes through the unit. In this way, feed gas composition upsets are handled upfront and a stable unit operation is obtained under all circumstances.
Sour water stripper
Many process units throughout a refinery generate significant quantities of sour water. Sour water collected within a refinery contains both H2S and NH3. A Sour water stripper can be applied to remove these components from the sour water.
Subdewpoint units & SUPERCLAUS®
Especially for revamp situations, the addition of a SUPERCLAUS® unit to a sub-dewpoint unit is an easy way to improve the overall sulfur recovery efficiency.
Jacobs offers other technology options such as ammonia destruction and heavy hydrocarbon destruction. Such features are automatically included in the design, when needed, according the client’s project needs. Another option for clients is oxygen enrichment. Also, depending on the project needs, the best solution is recommended. At any time if desired by the client, a design can be adjusted for any future situation.